llBatielle
Columbus Laboratories
Considerations
future fnergy
U.S. ENVIRONMENTAL
PROTECTION
AGENCY
OFFICE OF
RESEARCH AND
DEVELOPMENT
VOLUME I
FUEL/ENERGY SYSTEMS:
Technical Summaries and
Associated Environmental Burdens
-------
11119
ENVIRONMENTAL CONSIDERATIONS IN FUTURE ENERGY GROWTH
by
BATTELLE
Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
and
BATTELLE
Pacific Northwest Laboratories
Battelle Boulevard
Rirhland, Washington 99352
for the
OFFICE OF RESEARCH AND DEVELOPMENT
ENVIRONMENTAL PROTECTION AGENCY
Contract #68-01-0470
April 1973
-------
EPA Review Notice
This report has been reviewed by the Environ-
mental Protection Agency and approved for
publication. Approval does not signify that
the contents necessarily reflect the views
and policies of the Environmental Protection
Agency, nor does mention of trade names or
commercial products constitute endorsement or
recommendation for use.
11
-------
ABSTRACT
The environmental factors associated with alternative fuel/energy
cycles were analyzed to provide a basis for making explicit judgments
regarding economics and environmental trade-offs.
A preliminary compilation of effluent data was developed for those
energy sources considered commercially viable in the 1975 to 1990 time
period. A preliminary methodology was developed for organizing the
compiled effluent data, for evaluating the combined effects of extrac-
tion, transportation, processing, and utilization of fuels to'produce
energy, and for ranking the fuel/energy systems environmentally. The
data hank and computer program for the ranking procedure are extant.
The computerized methodology enables any energy system evaluator to
test preferred weighting factors readily.
Based on this evaluation of the overall fuel/energy cycle, air emissions
associated with coal utilization can be reduced to approximately those
from natural gas systems, with an attendant increase in water pollution
or solid waste production. This improvement can be accomplished
through the application of advanced treatment or control technology
projected to be available during the early part of the 1975 to 1990 time
period. Later in the period further technology advances will becone
available for also minimizing the water and solid waste burdens produced
through coal utilization.
Qualitative environmental relationships were evaluated for advanced
energy systems considered developmental during the 1975 to 1990 time
period. Those judged to exhibit major potential for supplying signi-
ficant portions of future energy demand with reduced environmental
impact are: geothermal, solar, and nuclear fusion.
ill
-------
CONTENTS
Section Page
I Conclusions 1
II Recommendations 3
III Introduction 5
IV Fossil-Fuel Energy Systems 7
V Nuclear Fission Energy Systems 37
VI Advanced Energy Systems 49
VII Miscellaneous Energy Systems 55
VIII Acknowledgment 59
IX References 61
X Appendices 63
-------
FIGURES
Page
1 SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - 11
HIGH SULFUR EASTERN COAL
2 SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - 12
LOW SULFUR WESTERN COAL
3 SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - 13
OIL
4 SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - 14
OIL, MODIFIED
5 SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - 15
GAS
6 MATERIAL FLOW IN NUCLEAR (FISSION) FUEL CYCLE 39
vi
-------
TABLES
No. Page
1 Modules of Significance in the Analysis of Environmental 9
Impacts
2 Summary of the More Important Systems Options 16
3 Selected Modules Analyzed 21
4 Summary of Principal Environmental Burdens for Some 24
Selected Modules
5 Summary of Module Impacts 25
6 Summary of Ranked Systems , With Media Impacts, Effi- 30
ciencies, and Costs
7 Alternate Ranking of Systems 31
8 Summary of Ranked Space Heating Systems 33
9 Summary of Control Costs 35
10 Summary of Environmental Impacts—Air Receptors 43
11 Summary of Environmental Impacts—Water Receptors 44
12 Summary of Environmental Impacts—Land 45
13 Environmental Ranking of Advanced Energy Systems 51
vii
-------
SECTION I
CONCLUSIONS
1. The major results of this study nay be summarized as follows:
(a) A preliminary compilation of effluent data has been developed
for those energy sources considered commercially viable in the 1975
to 1990 time period. These data represent readily available infor-
mation within EPA and private industry concerning the quantity of
residual pollutants produced during the extraction, conversion, trans-
portation and stationary use of fuels to produce electricity or direct
heating under best available conditions of environmental control. The
incremental cost of control and the overall cost of electricity pro-
duced also have been compiled.
(b) A preliminary methodology has been developed for organizing the
effluent data collected and for combining the emission data for each
module into a single environmental index for each energy system. The
value of such an index is that it provides a tool for making explicit
the value judgments of any system evaluator with respect to the rela-
tive environmental impact of energy systems. This methodology has
been applied in the context of this study Lo develop a gross environ-
mental ranking of the energy systems considered. Ultimately, such a
ranking of energy systems must be done on the basis of specific local
environmental impacts which may vary considerably die vvei^liLiu^ j'cicLui"
associated with each module and pollutant.
(c) From the data compiled in this study it is clear that natural gas
systems produce electrical energy with the least associated environ-
mental burdens. Moderate air emissions occur in the extraction and
combustion phases but other burdens are small or negligible. Elec-
trical energy produced by residual fuel oil systems gives rise to
greater environmental burdens. Significant air emissions occur in the
refining and combustion phases and water pollutants are produced in
the refining phase. Eastern coal-based systems, which employ current
technology, produce still greater environmental burdens, chiefly in
the form of solid waste from extraction and combustion and air emis-
sions from combustion.
(d) The application of improved technology in the areas of fuel con-
version and pollution control can be expected to achieve substantial
reduction in the overall environmental burdens. The control of S02
emissions from coal and oil combustion to achieve ambient air quality
standards can be technically achieved in the 1975 to 1990 time period.
Similar conclusions may be drawn regarding coal conversion technolo-
gies such as liquefaction and gasification. However, such treatment
or control technologies must transfer the inherent fuel sulfur plus
chemical reactant to another media creating water pollutants or
-------
solid waste products. Near the end of the 1975 to 1990 time period
regenerative stack gas cleaning technologies, such as MgO scrubbing,
and advanced combustion techniques, such as fluidizcu-bed combustion
of coal and oil, can be made available which will achieve equivalent
reduction of air emissions with only a moderate increase in the pro-
duction of solid waste. This conclusion can be illustrated by com-
paring the approximate total annual air emissions associated with
the extraction, transportation, and combustion of Eastern coal to pro-
duce 1000 MW of electricity for: coal burned in a conventional boiler,
235,000 tons; conventional boiler plus wet limestone scrubbing,
60,000 tons; conventional boiler plus MgO scrubbing, 60,000 tons; and
fluidized-bed combustion of coal plus combined cycle, 40,000 tons.
The corresponding approximate total annual production of solid waste
for the same four systems is: 500,000- 1,300,000- 530,000- and 700,000
tons, respectively. By comparison, the total of the air emissions
associated with the extraction, transportation, and combustion of
natural gas is about 80,000 tons. The solid waste production for the
natural gas system is negligible. Similarly the approximate total
annual air emissions from the extraction, transportation, refining,
and combustion of oil could be reduced by wet limestone scrubbing of
the power pland stack gas from about 120,000 tons to about 75,000 tons
with an associated increased production of 322,500 tons of solid waste.
Application of MgO scrubbing would achieve the same level of air emis-
sion with minimal increase of solid waste production over no scrubbing.
(e) Based on this evaluation the air emissions from coal-based systems
can be reduced by application of advanced technology to less th?n those
of natural gas, while minimizing the attendant increase in solid waste.
(f) The data bank and computer program for the ranking procedure are
extant. The computerized methodology makes it simple to test the
preferred weighting factors of any energy-system evaluator.
(g) The pertinent environmental factors have been identified for those
advanced energy sources considered to be developmental during the 1975
to 1990 time period. The qualitative environmental relationships have
been evaluated by a panel through value judgments and subjective con-
siderations. Advanced energy sources judged to exhibit major potential
for supplying significant portions of future energy demand with re-
duced environmental impact are: geothermal, solar, and nuclear fusion.
2. The very broad scope of the project and the short time available for
this preliminary study have necessarily limited the effort to an over-
view. Nevertheless, the assembled data represent a unique compilation
of emission inventories which can serve as a foundation and point of
departure for both technical investigators and policy makers.
3. Emission data for hazardous trace materials are grossly inaccurate or
not available.
-------
SECTION II
RECOMMENDATIONS
This program was limited by the short time available to compilation
of readily available data, selection of limited environmental cate-
gories and first-order application of weighting factors. It is
recommended that additional effort be undertaken to address key issues
not adequately treated in this initial study. These key issues
include:
1. Refinement of the emissions assessments made in this initial study
to improve the validity of the results.
2. Development of data for atmospheric omissions of trace metals and
fine particulates,and for water emissions of trace metals and other
parameters for which incomplete data exists for some modules.
3. Comparison of impacts from radioactivity with material pollutants.
4. Comparison of energy (thermal effluents) residuals and material
residuals.
5. .Location of impact (generation of impact in one location and the
use of energy in another).
6. Relative weighting of air, water, solid waste, land impacts (land
use, waste disposal, strip mining, etc.).
7. Extension of the existing emissions data to include evaluation of
,the overall environmental impacts in the ecology and social
categories, and the incorporation of these impacts into the evaluation
of alternative energy systems.
8. Nuclear reactor accidents.
Additional effort in this area also should include an evaluation of
methodology to aggregate impacts at various levels as an aid in
decision making. Aggregation could include impacts at the levels of
•> Region > National
•> Module > System .
-------
SECTION III
INTRODUCTION
One of the many activities in which the Environmental Protection Agency
is engaged is the assessment of the comparative environmental impacts
of various fuel sources and energy cycles. This is being done in order
to provide a basis for recorrnending environmentally preferred energy
policy initiatives which may be required to meet future energy demands.
The Columbus Laboratories of Battelle Memorial Institute is assisting
the Environmental Protection Agency in this activity by analyzing the
available, pertinent: emission information and providing to the
Environmental Protection Agency the projected total environmental
burden associated with alternative approaches to the future supply of
energy. The overall objective of Battelle"s efforts is to provide EPA
with the necessary information regarding the environmental emissions of
alternative energy cycles to permit explicit.judgments regarding
economic and environmental trade-offs. This will permit the formulation
and execution of sound policy in this critical area.
To support the activities of EPA in this area, Battelle's Columbus
Laboratori.es submitted a proposed research program on October 17, 1972,
vhich consisted of three tasks. The first task was concerned with a
projeccion or tne environmental burden oi ba'se line fuel-supply pro-
jections during the period 1975 to 1990. It was prqposed^that..this
~eti
-------
The second task included in the proposed research program of
October 17, 1972, included a quantification to the maximum extent
possible of the effectiveness and economic costs of pollution control
for each alternative energy supply and technology considered in Task 1.
These vere to be considered in terms of common indices to permit com-
parison of alternatives. It further was proposed that wherever possi-
ble pollution control would be considered ac that necessary to achieve
existing standards or new standards which are anticipated as a result
of Federal or environmental legislation, or alternatively, pollution
control would apply the "best available" technology.
The third task which was proposed was the ranking of all alternative
energy supplies and technologies from best to worst, so far as
environmental burden is concerned. The environmental effects of each
phase of the energy cycle vere to be considered and separate rankings
were made for the commercially available energy supplies and for the
developmental technologies.
It was proposed that for each of the tasks the information to be
analyzed by Battelle would be drawn from published literature, from
experience of Battelle staff members in various fields, and from mem-
bers of the EPA staff. It was emphasized that access to EPA informa-
tion was vital to the success of the program and that every effort must
be made to expedite the exchange of information between EPA and
Battelle.
The proposed program was accepted by EPA and work was begun on
ftptviVini- ?;>, 1972. Tliii repjrt is ccr.ccrr.cd vith cne resullLi, ul Llie
study. The body of the report is divided into four basic segments.
The first segment deals with the fossil-fuel energy systems, the second
with nuclear energy systems, and the third with advanced energy systems.
The final segment of the body of the report is concerned with the
results and conclusions drawn from the study. The appendices to the
report contain discussions of the technology, the sources and quanti-
ties of pollutants, and the effectiveness and cost of pollution control
techniques for the significant segments of the fuel/energy picture.
The very broad scope of the subject and the short time available for
this preliminary study have necessarily limited the effort Lo an over-
view. A data base, of environmental emissions has been compiled from
readily available information, and a preliminary methodology has been
developed for ranking the fuel/energy systems on the basis of environ-
mental burden. These elements are extant and can serve as a framework
for more detailed analysis and for the addition of new data on
emissions and technologies as it is developed if the program is
extended and expanded.
-------
SECTION IV
FOSSIL-FUEL ENERGY SYSTEMS
It is anticipated that in the time period of concern to the study--
1972 to 1990--fossil fuels will continue to be the dominant source of
energy in the United States. For this reason, considerable attention
has been given to the analysis of the many and varied energy systems
currently in use or under development which utilize fossil fuels.
The complexity of the environmental factors associated with the utili-
zation of fossil fuels requires that the environmental impact of
alternative energy sources must be analyzed for the entire energy
system from extraction through utilization. This, in turn, requires a
systematic approach which will accommodate the large number of vari-
ables involved and which will result in an evaluation of energy systems
which reflects all of the variables. The modular approach chosen for
this study permits such a systematic evaluation. Because of the limi-
tations in the data base, the environmental impact of each module has
been evaluated on the basis of emissions, not effects as ultimately
ehould be done to permit development o£ a more meaningful ranking
methodology.
TECHNICAL APPROACH
Information Procurement
The procurement of pertinent information within the brief time span of
the study and subsequent analysis of that information was accomplished
by close cooperation with various members of the EPA staff. Both pub-
lished and unpublished information was provided by the EPA for the
study. Other information was procured from Battelle's library, as well
as other libraries, and from consultants and Battelle staff members
knowledgeable in the fields involved. Considerable numbers of docu-
ments have been acquired during the course of the study and are being
maintained in the project file for future reference.
In many cases, pertinent information — particularly that concerned with
environmental burden and cost of environmental control—was not avail-
able. In such cases, lack of information has been noted and the need
for its development emphasized.
-------
Modular Approach
The pathways by which various fossil fuels are utilized or processed
and converted to other forms of energy are many and varied. In order
to assess the efficiency of energy utilization and the environmental
burden for the various optional energy systems which utilize fossil
fuels, a modular approach has been used. In general, the modules,
defined as a distinct phase in a fuel/energy system, fall within one of
five categories: the extraction or procurement of the fuel from its
source, processing of the fuel, the conversion of the fuel to a differ-
ent form of energy, transportation, and the utilization of the fuel.
This approach allows ready identification of those phases of the fuel/
energy system which contribute a major share of the environmental burden.
It also provides a data base for extensive analysis of a large number of
possible system options. A list of the important modules to be con-
sidered is given in Table 1.
A very large number of possible pathways from the extraction of a fuel
to utilization of the fuel exist. A conceptual view of the modular
relationships of importance are presented for coal, oil, and gas in
Figures 1 through 5. From these diagrams, a list of systems composed
of from two to five modules has been constructed and is presented in
Table 2. The list does not represent all possible combinations of
modules but rather those considered to be of major importance.
Fifty selected modules have been analyzed for energy efficiency and
environmental burden durinc the ccurce of the firr.t sccmsnt of the
study. A list of these modules is given in Table 3.
In Appendices C through T, each of the modules under consideration is
defined and described. The energy being used in that particular
module is quantified, the effectiveness and cost of pollution control
is developed, and the various environmental burdens are listed and
quantified where the data are available. The components of environ-
mental burden considered for each module include emissions of air and
water pollutants, solid waste produced, and the land use required by
the operations involved in the module.
System Description and Assessment
The modules described in the foregoing section have been used as build-
ing blocks for the various potential energy systems. In the study of
electric power generation systems, 15 selected coal systems, 2 mixed-
fuel (coal and municipal refuse) systems, 6 oil systems, and 2 gas
systems have been described and analyzed. These include the important
options open to the nation for meeting the projected energy deficit.
In addition, 5 systems have been analyzed in which the end use of the
energy is space heating. The overall environmental burden for each
-------
TABLE 1. MODULES OF SIGNIFICANCE IN THE ANALYSIS
OF ENVIRONMENTAL IMPACTS
Gas Extraction, Processing,
Transportation, and Utilization Options
EXTRACTION AND CLEANING
Gas Extraction and Cleaning/Continental (North America Exclusive of
Arctic Regions)
Gas Extraction and Clcaning/Off-Shore
Gas Extraction and Cleaning/Arctic
Gas Extraction and Cleaning/Overseas
TRANSPORT
Gac Pipeline (Conventional)
Gas Pipeline (Arctic)
Cryogenic Tanker
STORAGE
Storage/Domestic
Storage/Tanker
UTILIZATION
Conventional Boiler
Combined Cycle
Space Heating
Oil ExLraceion, Conversion,
Secondary Processing, Transportation,
nnd Utilization Options
EXTRACTION
Oil-Gas Well/Continental
Oil-Gas Well/Off Shore
Oil-Gas Well/Overseas
TRANSPORT OF CRUDE
Oil Pipeline (Conventional)
Oil Pipeline (Arctic)
Tanker
CONVERSION OF CRUDE
U.S. Refinery
Topping Operations (Overseas)
Topping Operations (Domestic)
PROCESSING OF FRACTIONS
Residual Desulfurization
Naphtha No. 2 Fuel Production
Heavy Oil Gasification
Light Oil Gasification
Blending Fuel Oil
-------
TABLE 1. (continued)
TRANSPORT OF PRODUCTS
Barge
Tanker
Pipeline
UTILIZATION
Conventional Boiler
Conventional Boiler/Flue Gas Cleaning
Combined Cycle
Fluid Bed Combustor
Space Heating
Coal Extraction, Processing,
Transportation, and Utilization Options
EXTRACTION
Surface Mine (Eastern Coal)
Surface Mine (Western Coal)
Underground Mine (Eastern Coal)
TRANSPORT OPTIONS (Before Processing)
Rail
Barge
TREATMENT OR CONVERSION PROCESSES
Physical Goal Cleaning
Chemical Leaching
Solvent Refining
Gasification (Low Btu)
Gasification (High Btu)
TRANSPORT OPTION (After Processing)
Rail
Barge
Coal Slurry Pipeline
Gas Pipeline
UTILIZATION PROCESSES
Conventional Boilers
Combined Cycle
Fluid Bed Combustor
Conventional Boiler/Flue Gas Cleaning
Space Heating
10
-------
Conventional
Bailer/
Flue Cas Clng.
FIGURE 1. SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - HIGH
SULFUR EASTERN COAL
11
-------
Conventional nolle
Long TransnlE&lon
FIGURE 2. SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - LOW
SULFUR WESTERN COAL
12
-------
011/Caa Veil
(Continental)
Oil/Gas Veil
(Off-Shoze)
aphtha, No. 2
Fuel Production
FIGURE 3.. SCHEMATIC REPRESENTATION 07 MODULAR RELATIONSHIPS - OIL
-------
Barge, laiuer
FIGURE A. SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - OIL, MODIFIED
-------
Gas
Extraction &
Cleaning
(Continental)
Storage/Doneatlc
(Optional)
Cas
Extraction &
Cleaning
(Off-Shore)
Conventional
Boiler
Cas
Extraction &
Cleaning
(Arctic)
Storii~,;/Tcnker
Cenblned
Cycle
Cos
Extraction &
Cleaning
(Oversees)
FIGURE 5. SCHEMATIC REPRESENTATION OF MODULAR RELATIONSHIPS - GAS
-------
TABLE 2. SUMMARY OF THE MORE IMPORTANT SYSTEMS OPTIONS
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(S)
(9)
(10)
(11)
(12)
(13)
(14)
(15)
(16)
Extraction
Process
Surface Mine
(Eastern Coal)
Surface Mine
(HAS tern Coal)
Surface Mine
(Eastern Coal)
SurfEc.'i Mine
(Eastern Coal)
Surface Illnc
(Eastern Coal)
Surface Mine
(Eastern Coal)
Surface Mine
(Eastern Coal)
Transport
None
Mono
Xor.e
Rail, Ecrge,
None
Rail, Barge,
None
Rail, Earge,
None
Kail, Barge
Kor.e
Processing of
Riw Fuel
Fu'il/Er.erp.v
Physical Coal
Clo -.ning
C -ie~ leal
L=.iching
Solvent
Refining
:-asify
(.ow 3tu)
Gasify
( ,ow Btu)
iSasify
(High 3tu)
^?o^.e
Secondary
ProccsEing
Svstc^s - Coal
None
None
None
None
None
None
Kone
Transport S
Storage
Rail, Earge
Slurry
Pipeline
None
None
Kane
Pipeline
Gas
None
Utilization
Conventional
Boi.'.er
Conventional
Boiler
Conventional
Boiler
Conventional
Boiler
Combined
Cycle
Space Heating
Conv. Boiler
with Tlvjc Gas
Cleaning
-------
TABLI 2. (Continued)
Extraction
Process
(17) Surface Mine
(IS) (Eastern Coal)
(19)
Transport
Rail, Barge,
None
(20) through (38) Repeat above options
(39) Surface Mine
(Western Coal)
(40) Surface Mine
(Western Coal)
(41) Surface Mine
(Western Coal)
(42) Surface Mine
(Western Coal)
(1) Oil/Gas Well
(2) (Continental)
None
Reil
None
Rail
Oil
Pipeline
Processing of Secondary
R»w Fuel Processing
Fu'jl/EnerRy Systcns - Ccal
None None
vith underground nlned Eastern
None None
None None
Cs'sify None
(High Btu)
Uasify None
(Low Btu)
Fuel/Er.ergy Systecs - Oil
U.S. Refinery Resld. Desulf.
Transport &
Storage
None
Coal
None
None
Pipeline
Gcs
None
Barge, Tanker
Utilization
Fluid Bed
Conbustion
Systca
Conv. Boiler
& Long Dist.
Transmission'
Conventional
Eoiler
Space Heating
Conventional
Boiler
Conventional
Boiler
-------
TA27,E 2. (Continued)
o>
Extraction
Process
(3)
-------
TABLE 2. (Continued)
Extraction
Process
(16) Oil/Gas Well
(17) (Foreign)
(18) Oil /Gas Well
(19) (Foreign)
(20) Oil/Gas Well
(Foreign)
(21) Oil/Gas Well
(22) (Foreign)
(23) Oil/Gas Uell
(24) (Foreign)
(25) Oil/Gas Well
(26) (Foreign)
(27) Oil/Gas Veil
(28) (Foreign)
(29) Oil/Gas Veil
(30) (Foreign)
(31) Oil/Gas Well
(Foreign)
Transport
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Tanker
Processing of!
Raw Fuel
Fucl/Eni»r£
Topping
Refinery
Topping
Refinery
Topping
Refinery
Topping
Refinery
Topping
Refinery
Topping
Refinery
Topping
Refinery
Topping
Refinery
Topping
Refinery
Secondary
Processing
V Systems - Oil
No. 2 Oil
No. 2 Oil
Light Oil
Gasification
Naphtha
Production
Rcsid. Dasulf.
Blending
None - Hi S
Resid.
None - Hi S
Resid.
Heavy Oil
Gasification
Transport &
Storage
Barge, Tcnkcr
Barge, Tanker
Gas
Pipeline
Barge, Tanker
Barge, Tanker
' Barge , Tanker
Barge, Tar.ker
Barge, Tanker
Gas
Pipeline
Utilization
Space Heating
Combined Cycle
Space Heating
Combined Cycle
Conventional
Boiler
Conventional
Boiler
Conv. & Flue
Gas Cleaning
Fluid Bed
Co Jib us Cor
Space Heating
-------
TABJZ 2. (Continued)
to
o
Extraction
Process Transport
(1)
(2)
(3)
(4)
(5)
<6)
(7)
(8)
(9)
Gas Well None
(Continental)
Gcs Well None
(Off Shore U. S.)
Ges Well None
(Arctic)
Processing of Secondary Transport &
Raw ~uol Processing Storage Utilization
Fuel 'Energy Systems - Gas
Detulfir-ization None Gas Pipeline Coav. Eoiler,
Space Keating,
Corabincd Cycle
Dcsulfurization None Gas Pipeline Conv. Boiler,
Space Heating,
Corbined Cycle
Desulfu'-ization None Arctic Gas Conv. Boiler,
Pipeline Space Heating,
Combined Cycle
(10) Gas Well
(11) (Overseas)
(12)
Kone
Deswlfu: iaation
None Cryogenic Conv. Eoiler
Tanker £• Stg. Spoce Heating
Combined Cycle
-------
TABLE 3. SELECTED MODULES ANALYZED
Strip Mining of Eastern Coal
Strip Mining of Western Coal
Deep Mining of Coal
Physical Cleaning of Coal
Chemical Cleaning of Coal
Liquefaction of Coal (Solvent Refining)
Rail Transport of Coal
Conventional Boiler, Eastern Coal
Conventional Boiler, Western Coal
Conventional Boiler, Physically Cleaned Eastern Coal
Conventional Boiler, Chemically Cleaned Eastern Coal
Conventional Boiler, Liquefied Coal
Conventional Boiler (Limestone Scrubber) , Eastern Coal
Conventional Boiler (MgO Scrubber), Eastern Coal
Conventional Boiler (Limestone Scrubber), Western Coal
Conventional Boiler (Limestone Scrubber), Physically Clean Eastern Coal
Gasification (Low Btu) Eastern Coal - Lurgi
Gasification (High Btu) Eastern Coal - Hygas
Gasification (High Btu) Lignite - C02 Acceptor
Gasification (Low Btu) Eastern Coal - Molten Iron Combustion
Gasification of Crude Oil
Hie'1 Pressure Fluidizcd Bed
Chemically Active Fluidized Bed
Gas Dcsulfurization
Gas Pipeline-
Conventional Boiler, Natural Gas
Underground Gas Storage
LNG Tanker
LNG Port Facilities
LNG Storage
•LNG Distribution
LNG Gasification
Oil Shale Extraction and Processing
Oil/Gas Well - On Shore
Oil/Gas Well - Off Shore
Oil Tanker Transport
Oil Pipeline
Oil Barge
Refinery - Domestic Crude
Refinery - Imported Crude
Topping Refinery
Conventional Boiler, Domestic Residual
Conventional Boiler, Topping Residual
Municipal Refuse Processing (St. Louis Method)
Municipal Refuse Burning, Conventional Boiler, Limestone Scrubber
Space Heating - Electrical, gas, oil, coal and synthetic gas from coal
Nuclear Fission
21
-------
energy system has been obtained as the summation of the estimated
environmental burden for each module making up the system, modified by
the efficiency of energy utilization for these modules. Weighting fac-
tors were applied to permit a summation of burdens.
In addition to the summation of environmental b'jrdens, costs of energy
conversion for each of the systems were estimated so that the systems
could be compared economically, as well as environmentally. The cost
of pollution control for specific modules is presented in the appropri-
ate appendix for those modules for which this information is available.
In addition, the overall cost of energy production has been derived for
each system.
Derivation of Emission Values
The pollutant emissions resulting from the operation involved within
each module were derived from various sources. These values were then
reduced to a common basis, namely, emission per million Btu. This
reference energy was taken as the heat value of the primary fuel pro-
duced by the module, except in the case of electric power generation,
for which the input energy to the power plant was taken as reference.
Thus, in general, the emissions are given in pounds per million Btu.
The land use burden includes the land area involved and a time factor.
For the processing and utilization modules the proper unit arises from
the fact that a certain land area is associated with a plant with a
Et'.T !".'=.•? J~h rri.;r-!i ,-.•*• c^v J-.inc nf r-nsl^ --.a,- hrn/r1 riv- H-. - iJC'-livS Icr.L hcStll".'"'
value (Btu per hour). When the area in acres is divided by this
energy rate, the resulting units are acrc-hour/10D Btu. For the ex-
traction modules the area is associated with a total energy (e.g., tons
of coal per acre). The resulting burden in acres/10^ Btu is converted
to consistent units by multiplying the burden by the length of time
assumed for the operation.
DATA ANALYSIS
Environmental Burden of Modules
The unit-basis pollutant emissions, land-use burdens, and efficiencies,
for 50 modules are compiled in a series of module data sheets which are
presented in Appendix A. Data are included for those burdens for which
information was available during the period of the study. Emission from
processes which are in the early stages of development are estimates or
are based on extrapolation from bench or pilot studies. Continued re-
view of the data to incorporate new information as it is developed will
be necessary in order for the modular approach to achieve its maximum
22
-------
potential in describing the overall burdens of fuelVencrgy systems.
The extensive data base represented by the tables presented in Appendix
A can- be summarized for the purpose of illustrating the information con-
tained, by tabulating a few of Liu: important environment parameters for
some selected modules. These condensed data are given in Table 4. The
values are stated in pounds per million Btu for air emissions of NOX,
S02, and particulates, for water emissions of suspended solids and
organic materials, and for solid wastes produced. The land-use burden
is expressed in acre-hour per million Btu. Data are given in Table 4
for selected gas, oil, and coal modules which include extraction, trans-
portation, conversion or treatment, and utilization. The number of the
table in Appendix A containing the complete data is indicated for each
module.
The data presented in Table 4 illustrate the differences in burdens
which exist among the various modules. These burdens arise through
different steps in the fuel-energy cycle and various components of the
environment can be affected. It is difficult to evaluate alternative
energy systems directly on the basis of emissions data as presented in
Table 4 or in Appendix A. Therefore, it was believed to be desirable
to aggregate these complex emissions«at various levels and finally into
a single number which will reflect all of the emissions and thus aid in
comparing the environmental aspects of various energy systems.
A method for accomplishing the at-,}-,rogation of emissions was employed *
which is based upon methodology developed for the Bureau of Reclamation,
ii f< r>____j-_—fc ...f £tjj« Interior lit TI, _ .^_i..,-: . ..r ..•„•» i-t.^^,-..-, ^^.i-\-\I-\A~
ology are given in Appendix B. During this brief study no attempt was
made to detail the analysis on a regional basis. The results thus
represent a national overview which can be useful in the evaluation of
national'priorities. Ultimate implementation of energy policy should
include consideration of regional factors.
The first level of aggregation of the emission data, as described in
Appendix B, is the summation of the weighted parameters for each envir-
onmental component within the module. The resulting totals for the
air, water, solid, -and land-use lufrdens are compiled for each module in
Table 5. Since the actual emissions* have been weighted in the calcula-
tion of the totals given, units arc not assigned to the totals. Exami-
nation of Table 5 shows the range of values which occurs for a given type
of burden. Some general points regarding control technology associated
with the modules given in Table 5 should be noted.
o Mine modules assume land restoration (80 percent.coverage, no bare
areas greater than 1/4 acre, tuul 600 living stems per acre), and
treatment of acid mine drainage
o Physical coal cleaning assumes restoration of land used for refuse
piles (all p'yritic material covered with nonreactive soil) and
treatment of acid-bearing run-off
23
-------
TABLE 4. SIKKARY OF PRINCIPAL ENVTHOKtOIAI. BUSDENS FOR SOME SELECTED MODULES
Selected
Air Ealsaions,
Data From lb/106 tstu
Selected Modules Table No,
FxtracHon Kodulu
Strip Dining- Eastern
(E.) coal
Strip rain Ing- Vcs tern
(H.) coal
Onshore otL veil
Katuial £83 veil
Trnnepartatton Modulo
Kail-coal
Pipeline- oil
Flpclfne-g«a
Conversion or Treatment
riodulo
Physical roal cleaning
Chemical coal cleaning
Solvent refining of coal
Refining oi oll-doncatic
crude
Katural gai desulfuriza-
tloa
Utilisation Modules
tonvcnUJM&i bollci(CB)-
V. coal
C.D. with 11 ret tone
tcrubbci (LSS)-U. coal
Fluldtzed-hed combustion
plug coablned cycle-
K. coal
CbOlflcation (molten
Iron coabustlon) plus
C.B.-E. coal
C.B. with HBO icrubbcr-
E. coal
C.B. 'physically cleaned
E. coal
C.ll. vlth LSS-physlcally
cleaned E. coal
C.B. 'chemically cleaned
E. coal
C.B. -solvent refined
E. coal
Chemically active
fluldlzcd-bcd plus
conblncd cycle-
residual oil
C.B.-rccidu.il oil from
domestic crude
C.B. -natural ess
A-l
A-2
A-34
A-24
A-7
A-3?
A-26
A-4
A-i
A-6
A-39
A-25
A- 3
A- 15
A-22
A-20
A-W
A- 10
A- 16
A-ll
A- 12
A-23
A-«
A-28
KOX
0.0002
0.00008
8 x 10'6
0.23
0.02
0.009
0.304
0.006
0.04
0.21
0.025
0
0.98
0.78
0.14
0.39
0.60
0.68
0.55
0.7S
0.56
0.16
0.70
0.39
SOj
NCB
(leg
6 x 10-5
Keg
0.0014
0.016
0
0.004
C 1
0.003
o.m
0.0183
1.65
0.16
0.7
0.017
0.50
2.02
0.2
1.93
0.71
0.45
1.B3
O.OOOb
Pare leu lace
0.14
0.07
3 x 10'6
Keg
0.0014
0.002
0
0.01
o.oos
0.27
0.002
0
0.07
0.07
0.02
0.034
0.1
0.046
0.044
0.1
0.0003
0.01
o.os
O.OIS
Fnvlrontri
nt«l V'a mi-inters
Water (.missions,
lb/106 3tu
Suspended
Solid Organic
0.55
0.28
0
0
Keg
0
0
He«
Heg
0
0.004
RtR
0.025
0.025
0
0
0.025
0.025
0.025
0.025
0.0:5
0
0
0.016
Keg
Vet
0.008
Keg
0
0
Keg
Meg
lieg
0.002
K«B
O.C11
0.011
0
0
0.011
0.011
0.011
0.011
0.011
0
0
0
Solid Uaste,
lb/10& Bt.i
: Ash Sludge
0 0.24
0 0
0 0
0 0
0.083 Heg
0 0
0 0
0 0.3
0 0
16. 0
0 0.026
Keg tfeg
9. 0
1.8 13.4
17.3 0
10. 0
2.4 10.6
5. 4 0
1.1 11.9
11.9 0
0.031 0
3.0 0
0 0
0 0
l^ir.d Use ,
acre-hour
per 10* Btu
0.3
0.16
0.06
0.06
0.29
0.3
1.0
0.033
0.08
0.08
0.009
O.OOS
0.1
0.1
.
0.12
0.12
0.1
0.1
0.1
0.1
0.09
0.06
0.04
0.01
2ft
-------
TABLE 5. SUMMARY OF MODULE IMPACTS
in
Kodule
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Impacts,
Weighted Sums (IWgfJp) for Ench Environnental Component
Kodule
Eastern Coal, Strip Nine
Western Coal, Strip Mine
Eastern Coal, Deep Mine
Physical Cleaning of Coal
Chemical Cleaning of Coal
Liquefaction of Coal (Solvent
Refining)
Rail Transport of Coal
Conv. Boiler, Eastern Coal
Conv. Boiler, Western Coal
Conv. Boiler, Physically Cleaned
Eastern Coal
Conv. Boiler, Chemically Cleaned
Eastern Coal
•Conv. Boiler, Liquefied Coal
Conv. Belief, Lines tone Scrubber,
Eastern Coal
Conv. Boiler, MgO Scrubber, Eastern
Coal
Conv. Boiler, Limestone Scrubber,
Western Coal
Ccnv. Boiler, Limestone Scrubber,
Physically Cleaned Eastern Coa-1
Air
0.186
0.0933
0.0005
0.0218
0.212
0.222
0.0247
7.040
3.150
3.338
4. 215
1.585
1.396
1.39 A
1.453
0.922
Water
0.0033
0.0013
0.045
0
0
0
0
0.0039
0.0039
0.0039
0.0039
0.0039
0-0039
0.0039
0.0039
0.0039
Solid
0.240
0.040
9.60
0.06
0
16.0
0.083
12.0
9.0
5.41
11.41
0.074
29.8
12.16
21.05
13.60
Land Use
0.34
0.17
0-20
0.003
0.002
0.027
0.29
o.io
0.13
0.10
0.10
0.09
o.io
0.10
o.io
0.10
-------
TABLS 1. (Continued)
Module
Nur.be r
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
Ir.pacts,
Weighted SUT.S (EVoCb) for Erich Er.viror.ner.tal CcnTsor.ent
Module
Gasification. Eastern Coal, Lurgl
(Low Btu) plus Conv. Boiler
Gasification, Eastern Coal, Kygas
(High Btu)
Gasification, Lignite, CO. Acceptor
(High Btu)
Gasification, Eastern Coal, Molten
Iron Combustion (Low Stu) plus C. E.
Gasification of Crude Oil
High Pressure Fluidized Bed plus C. C.
ChenicalJy Active Fluidized Bed plus C. C.
Natural Gas Well
Natural Gas Desulfurizatlon
Gas Pipeline
Underground Gas Storage
Conv. Boiler, Natural Gas
LNG Tanker
LNG Port Facilities
LNG Storage
LNG Gasification
Oil Shale Extraction and Processing
Air
1.624
1.79
0.027
0.44<5
0.17
1.042
0.761
0.845
0.0229
0.304
0.60
0.446
0
0
0
0.0026
0.484
Water
0.0046
0.0023
0.0023
0
0.0002
0
0
0.0031
0
0
0
0.0002
0
0
0
0
0.001
Solid
9.75
31.9
39.2
10.0
0.18
17.40
3.0
0
0
0
0
0
0
0
0
0
>400
Land Use
0.12
0.02
0.02
0.12
0.04
0.10
0.12
0.05
0.005
1.00
Neg.
0.02
0
Neg.
0.00005
0.00004
N.D.
-------
TABLE 5. (Continued)
Module
Number
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
Module
Oil/Gas Well - On Shore
Oil/Gas Well - Off Shore
Oil Tanker Transport
Oil Pipeline
Oil Bcrge
Refinery, Domestic Crude
Refinery, Imported (Arabic) Crude
Topping Refinery
Conv. Boiler, Domestic Res id
Conv. Boiler, Topping Rcsld
Municipal Refuse Processing (St.
Louis, Method)
Municipal Refuse Burning, Conv.
• Boiler, Limestone Scrubbing
Space Heating, Electricity
Space Heating, Gas
Space Heating, Oil
Space Heating, Coal
Nuclear Fission
Weighted Sums
Air
0.00008
0.00016
0.1416
0.157
0.0143
0.214
0.225
0.155
3.151
1.811
0
0.717
0
0.572
1.13
10.5
0.0032
Impacts,
(EWpQp) for Each Environmental Component
Water
0.0223
0.0023
0.0495
0.00495
0.00512
0.0068
0.0068
0.00425
0
0
0
0
0
0
0
0
0.022
Solid
0
0
0
0
0
0.026
0.026
0.026
0
0
0
-132.0
0
0
0
0
4.0
Land Use
0.05
0.05
0
0.31
0
0.009
0.009
0.009
0.04
0.04
0.034
0.1
0
0
0
0
0.3
-------
e Boiler modules assume 99 percent efficiency for particulate removal
* Stack gas cleaning modules assume 90 percent reduction in S02 and 20
percent reduction in NOV
X
• Cooling towers are assumed for all modules discharging heat in water
effluents. The heat discharged to air is not included in the burden
totals.
The compilation of Table 5 also shows the cross-media effects of alter-
nate pollution control approaches. For example, Modules 8 through 16
are all conventional boilers burning several different kinds of coal,
either with or without stack-gas cleaning. Comparison o£ Module 8 with
Module 13 shows an 80 percent reduction in air burden when a limestone
scrubbing system is employed, with an attendant increase in solid
burden due to the gypsum sludge produced. Module 14 shows the same
reduction in air burden, but does not have the increase in solid waste,
since the MgO scrubber is a regenerative system. Module 22, high-
pressure fluidized-bed combustion, also is a coal utilization module
vhich exhibits yet smaller air burden with an intermediate solid impact.
Thus, Table 5 can be used to compare alternative processes on a burden-
by-burdcn basis.
Environmental Burden of Systems
The second level of aggregation of the emission data—as described in
Appendix B--is the summation of the weighted totals for each environmental
component over all of the modules in each chosen system. Again weighting
factors reflecting the relative importance of each module are employed in
the summation. The result is a separate total for air, water, solid
waste, and land-use burdens which reflect the individual contributions
of all of the burdens.
The final aggregation of the emission data is the summation of the en-
vironmental component totals to give a single system environmental index.
The methodology which was used in the derivation of this final aggrega-
tion is described in detail in Appendix B. The results obtained by this
approach are described in the following paragraphs. It should be noted
that this is simply one method of aggregating the complex emission data
and the results arc not a unique representation of that data. The method
includes the flexibility to allow any system evaluator to select weight-
ing factors at each level of aggregation' to reflect his understanding of
the relative importance of each factor involved. The computer program
readily allows recalculation of the system environmental indices on the
basis of refined weighting factors.
During this short study a group of 26 systems for producing electric
power and a group of 5 systems for space heating were selected for
28
-------
analysis. The electric power group included 15 coal, 2 mixed-fuel
(coal plus municipal refuse), 6 oil, I nuclear fission, and 2 natural
gas systems. These include the important options which must be con-
sidered in arriving at an cne-gy policy. The group of space heating
systems included electricity, natural gas, oil and coal.
Electric Pover Systems
All of the systems which have been analyzed are listed in Table 6.
For each electric power system and appropriate modules, burdens given
in Table 5 were employed to derive an overall system environmental
index. Since the module burdens are stated on a unit basis, the
efficiencies must be factored in. The weighted sums in each module
were first adjusted by dividing each of the four values by the product
of the efficiencies of each module following it in the system sequence.
The impacts for electric-poucr-generation modules are stated on a unit
input basis, therefore, the efficiency factor is applied to those
impacts as well, in order to put all systems on a common output basis.
The adjusted burdens of all modules in a given system were then added
to give total air, water, solid and land-use burdens. These totals are
given for each system in Table 6. Again, the burden data in Table 6
are useful in comparing the trade-offs which are involved in the con-
sideration of various system options.
The total air, water, solid and land use values were normalized as
described in Appendix B and then summed to give the overall system
environmental index. The systems are arranged in ranked order in
Table 6 according to the value of the derived system index.
Three additional elements are included in Table 6; the overall system
efficiency (the product of the efficiencies of each module in the
system), the estimated overall cost to produce electricity, and the
approximate year of availability of each system.
It should be emphasized that the system index as given in Table 6 was
.derived with equal weight being given to the burdens from each module
in the system and also to the air, water, solid and land use burdens.
With these assumptions, three of the four systems which include lime-
stone scrubbing are ranked belov; the corresponding system without
scrubbing. This occurs because the S02 and sludge produced (16 Ib
sludge per Ib of SC>2 removed) are given equal environmental importance.
In view of the fact that air emissions are, in general, more likely to
produce adverse health effects than are solid wastes, it would be
reasonable to assign a lesser weight to solid waste in the system
analysis. Based on this premise a second calculation was carried out
in which the solid burdens were assigned a weighting factor of 0.3
while keeping the remaining media weights equal to unity. The results
of this calculation are given in Table 7 in which the systems are
ordered according to their revised ranking. For comparison, the rank
of each system obtained previously with equal media weights also is
given. The revised order shows the expected changes. Systems with
29
-------
TASIS «. JB«A*Y » SA»«O s\i rse. wot KSIA IMACTS. enmoteits. urn COJTS
er/S[orae.e/Ol>trlbullon/Caa|{|tailon
3.2
11.2
12.4
16.7
19.7
22. 6
23.3
23.7
23.9
24.1
24.1
23.0
27.1
27.3
29.3
30.9
30.8
33.2
34.6
36.3
17.)
41.3
43.6
43.1
33.3
Hone Tjepor'.ed ro>l<
Hat. lie veil
bit ceal. J.H. Kail
Virt coal. 3.K. Hall
bit coal. S.M. tall
901 t. eoal-lOt rreparod
bit coal,* 3.X. tail
Hone Oil leaker
bit coal Rait
bit coal fell
Vil(leilloa
CaaU. lev Btg Lurf,!.
B«f!nery doneetle
Vona
Dona
Refiner* doMBtlc.
71iv3lcal coa.1 clean
PnyBleal coal clean
Hona
Hal. a,aa pipeline
Ka.n
Ko; •
tforr
It..
Oil barto
Koii.
Van
Votr
Oil tajTfO
Mo- a
Hov n
Nil. (aa fipallu
Hor I*
Oil laefter
liorn
Vo:.
Oil tanker
Ko-n
fo-ir
fore
Con-, bollar
Crnblnrd cycle
Conv. boiler
lleo ic rub
Conv. bailor
Conv. bolloc
Conv. botlvr
Con&lned cjrclo
Conv. boll»r
Conv. boiler
H£0 ecrwb
Conv. buller
tapp. reeld.
Conv. boiler
Co-it, boiler
l!«e ecrub
Conv. bo!!:r
!!«.
-------
TABU 7. \ittawn usnise or JYSIW
Vo!|St(fig »•
Rank
lor ti
Syeteei Kanlt
»vlrei
wcnlel
Vf m 0.3 Ince«
1
Z
3
4
}
•
J
•
»
10
11
11
11
14
19
14
• y
*»
SI
1*
20
21
II
13
»«
ti
It
• Include
1.
J.
11.
11.
14.
19.
16.
It.
IS.
17.
18.
It.
21.
11.
11.
t«.
•>«
It,,
17.
)0.
n.
92.
5*.
}}.
• 41.
a.
enlv
and effect ia
}
e
i
i
4
)
7
7
•
T
0
4
}
«
1
1
}
i
l
7
0
9
4
7
9
J
for
All WB - 1
1
I
4
1
6
a
3
14
9
10
13
T
11
IS
11
11
• •*
if
13
11
12
23
20
14
2)
It
Extraction
line
Kone
• Traneportellon
u«y;.-!
ilaported reald
Sv*rr>**J
FroceiJint
ier/Slor*G«/DUErlbu£ion/4
ri. bed ccmbuat.
Trin«port«tlen
.UllflcAtlRI
Vlllltatlen
Conv. boiler
Combined cvela
Muciecr Flaelon • Total Syateaa
bat
bat
(at.
tf.it
bat
bet
Vnt
bat
bat
bit
Von.
b_ •
as
Co.!
cut
coal
(01 E.
. S.M.
, t.n.
oal*20l Prepared Kun. Rafuia
lull
ilall
lea .ell
coal
COO.I
coal
coal
coal
coal
coal
coal
Oil «ell.
Oil >
bit
taat
Oil >
bat
on i
bat
rail.
coal
cocl
.ell.
coal
re 11.
coil
envlronscnt al Icpacta reeultlng
nol c<
mala to.
, S.M.
SOI t.
. S.K.
, 5.K.
. 5.N.
, S.M.
Stf
. ."«
, 3.H.
cnahor*
onihore
. 5.X.
. D.n.
oCfahaco
, O.K.
onihoro
. O.K.
(all
C' a 1-101 rrapered
K»ll
Pill
Hull
Rill
Ull
bit
Oil tinker
n_. i
an
r.ti
Oil pipeline
Cll pipeline
rill
tall
611 pipeline
fall
>I1 pipeline
•mi
€••!->, iw lu.
noli. Iroa
Hone
Oil barjo
Kac. til plpolloe
Kone
Rone
Oil tanker
none
Oil tanker
Xt»e
Oiv. bailer
1 Ino ac rub
Conv. boiler.
Cce-blned cycle
Conv. boiler
Conv. boiler
Una scrub
Conv. boiler
ItD* acrub
Conv. boiler
t'iO icrub
Conv. botUt
line aerub
Conv. boiler
Conv. boLlrr
I IB* if rub
Ccnv. bellrr
Conv. boiler
Conv. boiler
lopp. rrald
CAIV. boiler
Conv. boiler
Conv. bpller
tfwB. rvili!.
Conv. boiler
Conv. boiler
Con., boiler
llaia acrwb
Conv. boiler
dra. retld.
Ccav. boiler
Conv. bailer
do». re lid.
Conv. boiler
•
ilyela o( nuclear accident pro^aBlll!
-------
relatively large solid burdens moved up in rank. For example, the
systems which include limescone scrubbing arc ranked above the corres-
ponding systems without scrubbing.
Space Heatinn Systems
A separate analysis was made of a. group of 5 space heating systems
which represent a utilization of energy one step beyond the general"ion
of electricity. The methodology was the same as before with appropri-
ate modules chosen to make up the representative systems, and the
module data given in Table 5 used to derive the system index. The
results are given in Table 8 in which the space heating systems are
ranked according to the system index.
The oil, coal, and synthetic gas systems are grouped in the ranking
between gas, the highest, and electricity, the lowest. The low ranking
of the electrical space heating system reflects the inefficiency of the
electric power generation module.
DISCUSSION OF THE RESULTS
Systems Relationships
TnspficHon of T.ib]^? f> and 7 reveals a number of interesting feature.
A few of these may be noted as illustrative of the comparisons which
may be drawn.
o KaLural gas and LNG systems predictably rank high environmentally.
* Among the currently available systems, nuclear fission, Western
coal, and imported oil/topping refinery systems are highly ranked.
« MgO scrubbing systems and, given the assumption of lesser weight
for solid waste, limestone scrubbing systems are favorably ranked.
• Various coal cleaning and processing options show significant
environmental gains over the use of untreated coal.
o The developmental technologies; chemically-active fluidized-bed
combustion of oil, molten iron gasification of coal, and high-
pressure fluidized-bed combustion of coal are highly promising from
the environmental viewpoint.
• Systems including strip mining of coal are environmentally accept-
able if land restoration and treatment of acid mine drainage is
practiced.
32
-------
TABLE 8. SUMMASY OF RANKED SPACE HEATING SYSTEMS
Rank
1
2
3
U> A
Ul ^
5
System
Environmental
Index Fuel for Space Heating
8.3
16.1
17.9
19.7
30.8
Natural gas
Fuel oil, 0.3% sulfur'^
Coal, 1.5% sulfur(c)
Synthetic gas from c6a3.
Electricity^
Total
Air
Burden
2.3
1.7
11.0
3.6
4.6
Total
Water
Burden
0.005
0.054
0.009
0.012
0.022
Total
Solid
Burden
0
0.037
0.85
46.3
74.6
Total
Land
Burden
1.5
0.6
1.4
1.4
2.1
(a) System comprising: gas well, gas desulfurination, gas pipeline, gas space heating.
(b) System comprising: on-shore oil well, oil pipeline, domestic refinery, fuel oil
space heating.
(c) System comprising: S.M.E. coal, rail trans-port, physical coal cleaning, coal
space heating.
(d) System comprising: S.M.E. coal, rail, high Btu gasification (HYGAS), gas space
heating.
(e) System comprising: S.M.E. coal, rail, conv. boiler with limestone scrubbing,
electrical space heating.
-------
« The oil systems are intermediate in rank due to higher than average
air and water emissions.
One of the most striking results is the high ranking of the coal/
municipal refuse, mixed-fuel systems. This option, described in
Appendix U, is highly promising from a number of viewpoints. The
modules (processing and burning of municipal refuse) are based on the
St. Louis approach (arbitrarily selected for illustration), and the
system burdens were derived by combining the appropriate fraction of
the burdens from the modules involved. This option consumes the com-
bustible portion of the municipal refuse which obviates the need for
an alternate means of disposal and, in turn, results in a negative
value (a credit) for the solid waste burden of the module. In
addition, the prepared refuse replaces & portion, 10 to 20 percent in
the cases included, of the coal required by the power plant, thus
reducing the coal system burden by that fraction.
A system involving shale oil was not included in the computer analysis.
Vith the current understanding of the approaches to the exploitation of
shale oil,' >3,4) it appears that undesirably large environmental
impacts will be associated as indicated in the data for the shale oil
module in Table 5. Th«se impacts wi31 certainly place any system
including the shale oil module at the bottom of the ranked list. There-
fore, it was excluded icrom the analysis of the rest of the systems so
as to avoid distorting the calculations,
An approximate picture o£ the estimated availability time frame may be
drawn by listing the systems as follows:
(1) Currently available
LNG
Nuclear fission
Natural gas
Oil-conventional boiler
Coal-physical cleaning
(2) Available by 1975
Mixed fuel—coal/municipal refuse
Topping of imported crude
Limestone scrubbing of flue gas
(3) Available by 1980
MgO scrubbing of flue gas
Chemical coal cleaning
Crude oil gasification
-------
(4) Available by 1985
Fluidized-bed combustion of coal and oil
Gasification of coal
Liquefaction of coal (solvent refining).
Cost of Pollution Control
The costs associated with the various mechanisms for the control of
emissions from different phases in the fuel/energy cycle are developed
in the pertinent appendices, A summary of the ranges of control costs
in terms of medium, fuel, and module is given in Table 9.
TABLE 9. SUMMARY OF CONTROL COSTS
Medium
Control Cost
ner 106 Btu
Module
Air
Coal
Gas
Oil
Water
Coal
Gas
Oil
Solid
Coal
Gas
Oil
Total
Total
$0.10
0.01
0.05
$0.35
0.05
0.25
$0.16 - $0.65
$0.005 - $0.01
0.005 -
0.005 - 0.01
$0.015 - $0.02
$0.01 - $0.10
0
0
- 0
- 0.03
Total
$0.01 - $0.13
Processing, power plant
Extraction, power plant
Processing, power plant
Extraction
Extraction
Extraction, processing
Extraction, processing,
power plant:
Processing
35
-------
SECTION V
NUCLEAR FISSION ENERGY SYSTEMS
The alternate energy supplies considered commercially viable in the
1972 to 1990 time period included the fossil fuels and nuclear fission.
Power generation by means of nuclear fission is expected to expand
during the time period under consideration and thus to supply an
increasing share of the. nation's energy demand. It is necessary,
therefore, to consider the environmental impacts associated with the
entire range of operations of the nuclear power industry.
There arc currently five fission power plant concepts being developed.
These are:
« Light Water Reactor (LWR)
• High-Temperature Gas-Cooled Reactor (HTGR)
« Liquid Metal Fast Breeder Reactor (LMFBR)
• Gas-Cooled Breeder Reactor (GCBR)
e Molten-Salt Breeder Reactor (MSBR).
The LWR and the HTGR are commercially viable-, in that they are'
coni'rercially available to the electric .pcwr.r. *r..-l:i<:f-,ry. !-H.(-ti «-he --
national commitment to developing the LMFBR, it is expected that this
type of power plant will be commercially applied in Lhe latter part of
this time period. The GCBR and the MSBR are beinj; developed as backup
technologies for the nuclear power industry and are not expected to
reach commercial application in the 1975 to 1990 time period. There-
fore, these two concepts are not included in this assessment; rather
they are treated with the analyses of advanced energy technologies and
are reported in Appendix W of this report.
All forecasts made to date show continued increases in the amount of
electricity consumed in the United States over this time period and in
the number of nuclear power plants built to supply that electricity.
If these forecasts hold true, then there will be a corresponding
increase in the amount of radionuclides generated in meeting this
electrical demand. The amount of radionuclides released to the environ-
ment also is expected to increase even though improved radwaste systems
are adopted which would reduce the release rates. This study forecasts
the quantity of radionuclides released during 1975, 1980, 1985, and
1990.
The quantities of radionuclide wastes from the LUR power reactor indus-
try for 1967, 1970, 1975, and 1980 were previously forecast in Phase I
37
-------
of a study'-*' conducted for the U. S. Atomic Energy Commission. The
forecast of this document is based on the same general assumptions with
some modifications of input data and can be considered a continuation
of that forecast.
TECHNICAL APPROACH
A combination of forecast data for the electrical power industry and
general material balances for the nuclear segment of that industry are
used to estimate the quantities of waste for 1975, 1980, 1985, and 1990.
The relevant material flows in and out of the nuclear power industry
are identified and quantified by type and location, with emphasis
placed on determining the final disposition of waste materials.
The general flow of radioactive materials through the power reactor
system was divided into 9 steps for the uranium cycle and 8 steps for
the thorium cycle. These 17 steps are presented schematically in
Figure 6. For each step, a material balance was made to determine
relevant inputs and outputs, including the quantities, physical forms,
and disposal system. The material balances for each process are pre-
sented in flowcharts and tables. Five of the steps involved two dis-
tinctly different processes having different effluents and, thus, two
sets of data were prepared. (As an example, separate tables were pre-
pared for the acid leach and carbonate leach uranium mills activities.)
Tim waalc Luiial t.Lt-jJi> lor Liie uranium and thorium cycles were combined.
Each of the resultant steps is described as a separate industry and the
data for each is presented in Appendix V of this report.
The waste produced by each process was assumed to be directly propor-
tional to the activity level throughputs for 1967 and 1970 and are
taken from AEC records and Nuclear Indus try 1970. Projections were
made using the Linear Programming Model of the U. S. P°«er EconomyC6)
which has been used in previous studies for the USAEC,'7' and the
ISOPRO computer code^ which calculates throughputs based on installed
capacity.
Assumptions Made in This Study
Because this was a preliminary study, several simplifying assumptions
were made which are listed here.
* The AEC is now providing numerical guidelines on design objectives
for light water cooled reactors which would carry out its policy of
keeping radioactivity in effluents to levels which are as low as
practicable. The cited projected levels for reactors built after
36
-------
1>
Ii0jl(
w>2
Muloi
Ccnrcrl
Corrcrt
Urinvin Rrcrcl
lui fre/cl» (I.".
Vrjnivn Rfc>cl
*
X,^
PuOj.,,..,
\
X
m*^*
^*- t
• ("TC'1?)
•:•.' i i-«:»i
; (l.^'i)
frinlun Pecrde
•
MM
Or,
11(11
1
CenetntntcJ U^Oj
l.tflnc JrvVor
. Conn rt
T--
lDrMtrr'
Coircrt
1
o» w.
1 .
!•• •"
fibrlctle fuel
1
fuel Clcncnti
I
bictor 0?cril(on
Irr«tfliud fuel
I
?fjrccen
Jkorlvn Cyclt
Klne
Or*
Concent rite
I
.Cenctntnted CjntMtt
Rill
/
y°*
/
/
S ......
1
Convert Ifc{fc03)t
•• Vitle Slorjqe
ihttrtin tttft^t (ine*'!) •
FIGURE 6. 'MATERIAL FLOW IN NUCLEAR (FISSION) FUEL CYCLE
39
-------
1930 reflect anticipated technological improvements in radwaste
treatments.
9 It is anticipated that numerical guidelines also will be forth-
coming on design objectives for fuel reprocessing plants to keep
their radiation releases and resultant radiation exposure as low as
practicable. The projected levels reflect some anticipated tech-
nological improvements in waste treatment systems for power and
reprocessing plants.
o The quantities quoted for radiological impact in this report are
given as total activity (curies) released. The effects of these
releases, which depend on the particular nuclides involved, are
excluded in this study. Similarly, the occupational hazards are
excluded.
» No attempt was made to anticipate any changes in the standards or
estimate any costs that might be involved in meeting them.
* The primary assumptions applying to two or more processes are:
(1) The study covers only the commercial nuclear power industry,
including all related portions of the fuel cycle.
(2) Only Um's, HTGR's, and IMFBR's were included in the study.
(3) LWR's and IMFBR's operate only in the uranium fuel cycle.
riut-oiiiuiii ruuycie was included. nick's operate only on the thorium
cycle. Oxide fuels are used for all reactors.
(4) Only gaseous diffusion enrichment facilities are used assuming
a tails assay of 0.2 percent U235.
(5) No target irradiations were considered, or the recovery of
special products (i.e., Up237, Cs137).
(6) The physical limits of the power reactor system for each type
of waste and product are as follows:
Type of Waste or Product System Physical Limit
Airborne Physical boundary of plants
Waterborne Physical boundary of plants
Surface-stored wastes Physical boundary of plants
Burial vastes Burial ground
Production Shipping facilities
(7) The radwaste treatment systems used in this study reflect
anticipated technological improvements in power reactor radwaste
systems.
-------
(8) Activation of permanent reactor equipment was not determined.
No waste disposal due to decommissioning of reactors and reprocessing
plants is included.
(9) Possible accidental releases of radioisotopes during shipments
were not included.
(10) Solidified high-level wastes are to be shipped to permanent
storage five years after reprocessing.
(11) The use and disposal of radioisotopes for research and medical
applications were not included.
(12) Available economic and technical data were used. Special
analyses were not made to develop new data. 1970 costs were used
for operating and capital costs.
(13) No throughput for foreign use is included.
Because information was not readily available in the short time per-
mitted for this report, capital and operating costs were not developed
for many-of the waste treatment systems used in the nuclear industry.
General systems for which no cost data were developed were: sanitary
vastes, nonradioactive solid wastes, and nonradioactive chemicals dis-
charged to the air, land, and uater. The reason is that the costs for
such systems are small in relation to the total costs of waste treat-
.ment .systems. The .components of Che -nuclear industry -for^'whtclV''no"costs
were developed-are-as-follows:
Industry Component Waste System
U Mining Mine Ventilation Systems
Low-grade Ore Disposal
U Milling Ventilation Systems
Tailings Disposal
Th Milling Solid and Liquid Wastes
Enrichment Airborne Wastes
Liquid-borne Wastes
Surface Burial Capital Costs
The radiological releases at these stages of the nuclear fuel cycle are
small in comparison to those at the fabrication, reactor operation, and
reprocessing stages.
41
-------
SUMMARY
Estimates have been made of the quantity of effluent expected from the
projected utilization of nuclear power reactor plants to meet the elec-
trical energy demand during the period 1975-1990. These estimates are
made assuming normal plant operating conditions. On the basis of the
time allotted for completing the study, the emphasis was placed upon
identifying and quantifying the release of radiological effluents in
the nuclear fuel cycle. A very preliminary study was made of some of
the other effluents of importance and these are also reported.
Nuclear Demand and Fuel Requirements
Using historical data from 1965 to the present a constant growth rate
of 7.18 percent was used for projecting electrical demand up to 1980.
Using a mix of other data and other energy projections, growth rates of
6.6 percent per year and 5.6 percent per year were used for the decades
1980-1990 and 1990-2000, respectively. To project the nuclear require-
ments, it was assumed that the nuclear plants would be base load plants
with fossil plants built after 1980 being used for load following.
Further, it was assumed that no fossil plants would be built after
1990. Based upon these assumptions, nuclear plants will produce roughly
19/29/41/54 percent of the total installed capacity for the years 1975/
1980/1985/1990. If construction schedules for nuclear plants continue
to slip and/or no na-.or new markets f«v. r*1rrf"r •{.-•!!•«• ar.r-.es-.; T.,-. M»te !;!:»;•
period, these demand values may be considered upper estimates. These
estimates of nuclear power requirements were used to define the nuclear
fuel requirements and the throughputs for each stage of the nuclear
fuel cycle.
Environmental Emissions
Estimates of the quantity of radioisotopes released to air, water, and
land receptors were made using the calculated throughputs required to
meet the demand schedule for each stage of the nuclear fuel cycle.
These are summarized in Tables 10, 11, and 12 for air, water, and land
receptors, respectively. Also shoun in the tables arc the other bur-
dens which must be studied to determine the total environmental impact.
Where data on these nonradiological burdens were immediately available,
they are included in Tables 10 to 12.
Throughout this report the amounts of radioactive wastes are reported
as curies of radioactivity. However, the total number of curies should
not be interpreted as a measure of the radiation hazard presented by
42
-------
TABLE 10. SlftCIAR? OF ENVIRONMENTAL IMPACTS—AIR RECEPTORS
Stage of
Cycle
U Mining
U Milling
Th Mining &
Hilling
V Conversion
U Enrichment
Fuel Fabrication
Reactor Operation
Fuel Reprocessing
Conversion
Waste Disposal
Totals
Parameter
Radiological, Ci^a^
Parti culatc & Gas
Thermal
Radiological, Ci
Participate & Gas
Thermal
Radiological, Ci
Part Leu late & Gas
The r ma 1
Radiological, Ci
Participate & Gas
Thermal
Radiological, Ci
Participate & Gas
Thermal
Radiological, Ci
Participate & Gas
Thermal
Radiological, Ci
Participate & Gas
Thermal
Radiologica'l, Ci
Participate & Gas
Thermal
Radiological, Ci
Participate & Gas
Thermal
Radiological, Ci
Participate *. Gas
Thermal
Radiological, Ci
Participate t Gas
Thermal
Year
1975 1930 1935 1990
5,000 9,000 16,000 *5,000
0000
0000
.3 .5 .8 L.3
.56 .86 1.41 2.79
9.4x10" ~2.0xlU? Z.Axiir z.sxiu-'
32 100 253 504
l.OxlO7 I.7xl07 1.9xl07 2.2xl07
25tcJ 62 100 190
Included in Reprocessing
0000
0000
1.94xl07 3.7xl07 4.3xl07 S.lxlO7
(a) Co, curies of radioactivity.
(b) Heat in gigawatts,
(c) Heat In megawatts.
-------
TABLE 11. SUMMARY OF ENVIRONMENTAL I!ffACTS~UATER RECEPTORS
Stage of
Cycle
U Mining
U Killing
Th Mining &
Milling
Parameter 1973
Radiological, Cl
-------
TABLE 12. SUMMARY OF ENVIRONMENTAL IMPACTS—LAND
Stage of
Cycle
U Mining
U Milling
Th Mining &
Milling
U Conversion
U Enrichment
Fuel Fabrication
Reactor Operation
Fuel Reprocessing
Conversion
Waste Disposal
(High Level)
Totals
Parameter
Radiological, Cl
Chemical & Sollti(b)
Land Usage(c)
Radiological, Ci
Chemical & Solid
Land Usage
Radiological, Ci
Chemical 6 Solid
Land Usage
Radiological, Ci
Chcirical & Solid
Land Usage
Radiological, Ci
Chemical & Solid
Land Usage'
Radiological, Ci<8)
Chemical & Solid
Land Usage-Waste^)
Radiological, Ci<°>
C: ; •-•!]. L •_<: 1 ft Soliu- • '•
Land Ucage-WastcCc)
Radiological, Ci
Chemical & Solid
Land Usage-Waste
Radiological, Ci
Chemical & Solid
Land Usage
Radiological, Ci
Chemical & Solid
Land Usage
Radiological, Ci
Chemical & Solid
Land Usage
1975
1.3x108
1,193
21,000
13
31
0
2xl05
1.9x10*
1
6x10^
Ox iv
12
2.9xl05
2.6xl05
5
Included
0
0
l.lxlO6
1980
2.4xl08
2,013
38,000
42
53
0
1.4xl06
3.4x10*
.1
1.5x10? .
1 • JX LU"
30
l.SxlO6
6.8xl05
14
1985
4.5xl08
3,439
65,000
120
92
0
2.6xl06
5.9x10*
I
.2.8x10*
£. , OA l\J **
50
2.9xl06
l.lxlO6
22
1990
7.7xl08
5,080
10. 1x10*
230
145
0
6.2xl06
l.OxlO5
2
5.2xlfi*
J » £X L\J
100
1.3x10^
2.2x10°
46
in Reprocessing
l.3xlo'
4,290(d>
I.3xl09
3.4xl09
11,220
3.4xl09
S.SxlO9
18,180
5.5xl09
(a) Ci, curies of radioactivity, where blanks.exist, no evaluations were made.
(b) Cubic yards of waste rock from open pit and underground mining.
(c) Acres of land required/year.
(d) Ft3 of solid waste/year.
(e) Shipped to offsitc licensed contractor.
-------
the various waste streams. Radiation hazard estimates require knowing
the quantity, chemical, and physical form for each nuclide released to
the environment.
Control Mechanisms and Costs
A great deal of attention is being and has been given to controlling
the dispersal of wastes from the nuclear industry to minimize the risks
to people and the environs.
From considerations of the radiological burden results given in Tables
10 through 12, it is evident that the major amounts of radioactive
effluent release occur at the reprocessing plant, the power reactor
plant, and the fuel fabrication plant. Therefore, the study has been
concentrated on investigation of control mechanisms and associated
costs for these three stages of the nuclear fuel cycle.
Reactor
The reactor waste treatment system is designed to collect all gases,
liquids, and solids containing radioactivity and treat them to mini-
mize radiation releases to the environment. A treatment system is
provided for each. Although there will be some variations in the waste
treatment systems for each reactor typa, LWR's, HTGR's and LMFBR's,
these differences are expected to be minor and consist prtm.-rily of
chemical reaction systems tor neutralizing or precipitating the liquid
waste streams.
The average costs (1970) for radioactive waste treatment systems for a
1000 MWe (megawatts, electrical power) LWR reactor were $2,611,000
capital cost and $38,430 per year operating cost. Forecasting future
waste facility capital costs is difficult because the policy of "as
low as practicable" is not quantified. We estimate that the installa-
tion for "as low as practicable systems" is about $15 million per
reactor and the operating costs will be about $500,000 per year.
In addition to radionuclide emissions, heat rejection from nuclear
power plants is of concern. The waste heat from a power plant is re-
leased either to a water body or to the atmosphere. The costs for heat
dissipation systems depend on the thermal efficiency of the plant and
the cooling system used. Typical costs for once through cooling to
water bodies range from $7 to $15 million; evaporative type cooling
systems range from $14 to $22 million; and dry cooling systems range
from $35 to $50 million. The cost of future control mechanisms for re-
ducing thermal discharges could range from 0 to $30 million assuming
the additional cost is that relative to the once-through-cooling-to-
fresh-water cost ($7 million).
-------
Fuels Reprocessing Plant
The reprocessing plant waste treatment systems consist of gas, liquid,
and solid treatment systems. The LMFBR, HTGR, and LWR reprocessing
plant waste treatment systems can be considered to be similar even
though the processes are quite distinct. The primary sources of waste
are: the fission productions separated from the thorium, uranium, and
plutonium recycle streams, the transplutonium isotopes, small percent-
ages of the uranium, thorium, and plutonium, and activated or contami-
nated processing material and corrosion products.
The costs incurred from the waste treatment facility are not very sensi-
tive to the process used. For a 5 ton per day reprocessing plant,
using 1970 costs, the waste treatment facility total.capital cost is
estimated to be $25 million. Annual operating costs are estimated to
be $3 million per year. It is not unreasonable to assume that "as low
as practicable" will become the guidelines for controlling releases
from reprocessing plants in the future. It is assumed that releases
of radioactive gas to the atmosphere will have to be controlled and
the estimated costs for gas treatment facilities are $7 million capital
costs and $1 million per year for operating costs.
Fuel Fabrication
All fabrication plants cm be treated as being essentially similar as
far as radioactive wastes and waste treatment are concerned. The prin-
cipal wastes are airborne particulate which are controlled with
filtered ventilation systems, and scrap which must be disposed of.
The average capital and operating costs for air treatment systems for
a 5 ton a day plant arc $2.2 million and $93 thousand per year, respec-
tively. The average cost for water disposal is estimated at $19,000
per year. Capital costs for water disposal systems are estimated at
$224,000. Applying as low as practicable releases to the fabrication
industry could impose some additional control mechanisms and costs;
however, no estimates have been made of these at this time.
Transportation
Since the nuclear fuel cycle has numerous industrial stages between the
extraction of ore to deposit of radioactive wastes, there are numerous
steps required in transporting nuclear materials in the nuclear power
industry with shipments by truck being the secondary mode. The prin-
cipal means of water transportation would be transcontinental freighter.
In some steps of the process, the shipments- may not go off-site.
The quantities of nuclear materials that will be shipped in these steps
for the years 1975, 1980, 1985, and 1990 were estimated. In general,
except for accidents, the impacts of shipments of nuclear materials are
identical to transportation of any other material. It has been assumed
-------
that no releases occur during the transport of nuclear materials be-
tween process steps of the fuel cycle simply because we have assumed
normal operational conditions. The impact of accidents has not been
evaluated since this would require a statistical analysis of the fre-
quency and severity of accidents for similar types of materials.
Experience to date indicates that the regulations now applicable assure
a trivial imp.ict to the environment. The AEG and others are currently
conducting statistical evaluations of the frequency and severity of
accidents and the attendant risk for shipments of spent fuel, recovered
Plutonium, and wastes. Assuming an accident would occur, a ranking of
materials from most hazardous to least hazardous was made. This rank-
ing is based simply upon the relative toxicity and chemical stability
of the compounds. No judgment regarding the effectiveness of the con-
tainer or shipping regulations was factored into the ranking. Pluton-
ium (nitrate or oxide form) represents the most hazardous material with
spent fuel and radioactive wastes being ranked second and third,
respectively.
-------
SECTION VI
ADVANCED ENERGY SYSTEMS
The energy resources used in this country through 1990 will be dominated
by fossil fuel, with gradual, but substantial, increases in the use of
nuclear fission energy. In the interests of conserving fossil fuels and
of reducing the environmental burden, other energy sources must be de-
veloped to meet future demands. In order to establish which systems
should receive preference, several potential energy systems were ana-
lyzed for their impact on the environment, their energy potential, and
their developmental costs, capital cost, and cost of converting energy.
The objective of this phase of the study (which was secondary to the
fossil fuel and conventional nuclear energy systems presented previous-
ly) was to identify and qualify selected advanced energy systems,
quantify where-possible the environmental burden, and rank the systems
•environmentally from best to worst. Additionally, systems were identi-
fied as to their potential for producing significant energy to mee.t
national demand by 1975 and by 1990. A further task was to investigate
the environmental burden influences of some miscellaneous energy sys-
tems, e.g., hydrogen energy. The study was carried out first by
describing the state-of-the-art of the system under investigation and
fcy rV".r-ri h^ng s':i>-,Qy=f -rlT:? r'ithill th2 IS'iliil S"£tSf2:. *":"£);£* "£hc t"1 '"L""~-
mental burdens were considered. This was followed by an assessment,
where possible, of the environmental control costs, the energy potential,
and finally, the development costs to bring the system on stream. The
energy systems investigated'were-as•followsr
o
e
Fuel Cells
Solar
Tidal
Fusion
Breeder Reactors
Hydrogen
Geothermal
Energy Storage
e Magnetohydrodynamics
o Thermoelectric
e Thermionic
o Waste Heat Recovery
o Space Heating
a Insulation
e Heat Pumps
There are, of course, other energy systems under consideration, includ-
ing ocean current thermal cycles, wind, and others, but it is believed
that the significantly viable systems have been examined. As would be
expected, source information was often conflicting or lacking. In cases
where this was pertinent to the evaluation of the energy system, expert
Judgments were made.
All systems investigated are described in Appendices W and X.
49
-------
Ranking of Energy Systems Environmentally
The prospective energy systems have been assigned to the categories
excellent, good, fair, and poor as a qualitative measure of their rela-
tive environmental emission. This was done to avoid any implication of
detailed quantitative relationships. A total of 23 systems has been
listed in Table 13. Coal, gas, and nuclear fueled steam electric plants
and hydroelectric plants have been included in this table for compara-
tive purposes only. These four systems are considered to be conven-
tional as they are currently at a high state of development, although
environmental effects and conversion efficiencies are subject to change
with continued development.
Residential heat pumps and solar heating systems are unlike the rest in
that they are not directly related to electric power production. They
were included because their future use would conserve fuel as a whole;
however, the widespread use of heat pumps will tend to increase loads
on central power plants.
Consideration was given to a wide range of factors, including thermal
efficiency and cooling water requirements, potential for air pollution,
land use requirements, environmental risks associated with fuel extrac-
tion, transport and processing, and the problems associated with dis-
posal of waste product, whether fly ash, water soluble salts, or
radioactive wastes. In some cases, there is conflicting information
as to th?- nntnnt-ir.1. r>rv.."f r.~rmf>nf-ai b>'r^-m. Cor.5ide^=:j,le eff-jrt v^s 'de-
voted to achieving a balance between optimism and pessimism.
Both positive and negative environmental burden were considered. For
example, the negative fuel consumption of breeder reactors is a posi-
tive impact, as is the contribution to the solution of solid waste
disposal problems when solid municipal waste is used as fuel in steam
electric plants.
Because no generally accepted methodology is available for comparing
the importance of fundamentally different burdens, value judgments and
subjective considerations had to be used. The resulting rankings thus
represent a consensus among a group of advanced energy system engineers
and environmentalists.
Much of the reasoning behind the assignment of relative positions to
the various systems is illustrated briefly as follows.
Fuel cell systems have at least two advantages over conventional steam
electric systems; they are more efficient thermally and vould produce
substantially less air pollution. Those advantages may be illusory,
however, because the fuel production would represent an additional step
which would reduce overall efficiency. Moreover, if the fuel is
5Q
-------
TABLE 13. ENVIRONMENTAL RANKING OF ADVANCED ENERGY SYSTEMS
Excellent
Solar Energy (Residential)
(c)
Heat Pumps (Residential, Electric)
Conventional Hydroelectric
(c)
Good
Tidal
Geothermal (Hydrocracked dry rock)
/c\
Solar (Rankine cycle)v '
Solar (Stirling)
(c)
Geothermal (Natural)
(b,c)
Fusion
Solar (Satellite)
Solar (Photovoltaic)
Natural gas/steam/elcctric
(a)
Fair
Geothermal (Nuclear stiumlated)
Magnetohydrodynamic (Closed cycle, nuclear)
Breeder reactors ffS.T-.-.r.-
Fuel Cells (Coal-to-hydrogen gasification)
Light Water Nuclear Reactors** *b>C*
Fuel Cell (Nuclear-electrolytic hydrogen)
Thermoelectric (Solar)
(c)
•Gasified coal/stcam/electric
Magnetohydrodynamic (Open-cycle - coal/steam/electric)
Poor
Coal/Steam/Electric
Thermionic (Nuclear)
(a)
(a) The conventional systems in 1972 are included for reference
purposes only.
(b) Capable of producing significantly increased energy by 1975.
(c) Capable of producing significant energy by 1990.
51
-------
produced by gasifying fossil fuels, there would be some production of
conventional air pollutants.
The solar energy systems are widely considered to be environmentally
"clean". However, the collectors would require the dedication of very
large land areas. Systems using satellite collectors would require
beam transmission of the energy to receivers on the ground. Some con-
cern has been expressed for the potential hazard associated with the
relatively intense beam of electromagnetic radiation.
Residential heat pumps represent largely beneficial environmental im-
pact because they would reduce the demand for fuel resources. On the
other hand, there might 'be a requirement for supplementary space heat-
ing at times for which resistance heating. systems appear attractive.
In that case, widespread use of heat pumps might lead to increased cen-
tral power station load, with attendant environmental insults, during
the most severe part of the heating season.
The various approaches suggested for utilizing Reothermal energy are
all site limited, and all appear to require dedication of substantial
amounts of land, much of which is presently scenic. In addition, there
is a potential for the contamination of surface water with dissolved
salts, and for air pollution with hydrogen sulfide or ammonia, for ex-
ample. Concern has also been expressed over possible subsidence of
relatively large areas, and for possible seismic activity as a result
of deep well injection,
Cc -. t r c 1 1 £ d . The - .Mj i im. 1 ^ a i Fu a i ur. reactors have several potential advan-
tages over fission reactors and fossil-fueled plants. They should be
more efficient, thus requiring less cooling capacity; there will be no
combustion products; and radioactive wastes will be largely contained.
However, there will be substantial tritium production, and the reactor
structures will be radioactive.
Utilization of tidal currents to produce electricity is attractive as
a nonpolluting system. However, there are several environmental factors,
including alteration of estuaries, both physically and biologically, and
the potential for local or meso-scale alteration of weather and climate.
Breeder reactors as a group have similarly 'been mentioned as having a
decided environmental emission advantage because of their fuel produc-
tion as opposed to consumption. However, their thermal efficiency is
not altogether favorable, and their production of tritium and fission
products which must be stored for decay represent adverse environmental
factors. In addition, the shipment and reprocessing of fuel in large
quantities represents a certain environmental risk because of the possi-
bility of accidents.
MaRnetohydrodynamic power systems receive much favorable attention
52
-------
largely because of their relatively high thermal efficiency. Seed re-
covery must be thorough for economic as well as environmental reasons,
but it is not known how important might be the escape of relatively
small amounts, by weight, of very small diameter seed particles which
are extremely difficult to capture. Sulfur recovery within the system
is a decided bonus but the very high temperatures associated with KHD
will tend to enhance production of oxides of nitrogen.
Thermoelectric and thermionic systems are not expected to provide any
significant power to meet national demands by 1990.
Discussion'of Advanced Energy Systems With
Regard to Their Ability to Produce Significant Energy
Of the systems presented in Table 13, only natural geothermal is cap-
able of providing significantly increased amounts of energy by 1975
without serious detriment to the environment.
The most striking potential advances in energy by 1990 are estimated to
be in LW nuclear electric and gasified coal-steam electric plants. The
gasified coal utilization in fuel cells to produce electrical energy
with relatively low environmental burdens at the point of utilization
looks promising by 1990. This may also be true for clectrolytically
produced hydrogen-fuel cell systems from surplus nuclear-generated
electricity if the capital costs can be made competitiva.
By 1990, solid waste utilization could account for 5 percent of the
total energy demand. This could also be true for residential use of
solar energy and heat pumps but solar energy storage systems and capi-
tal costs economics need to be more firmly established.
Magnetohydrodynamic topping systems for peaking power demands should be
•in use by 1990. Because of the very large energy potential, dry rock
geothermal system feasibility needs to be established. Significant
power from this source could become available by 1990 at very modest
environmental burdens if shown to be economically competitive.
53
-------
SECTION VII.
MISCELLANEOUS ENERGY SYSTEMS
Hydrogen energy (and a fuel cell total energy system utilizing hydrogen),
space heating and insulation, energy storage, and waste heat recovery,
were examined for their influence on the environment. Generally, these
systems have a favorable environmental impact: the combustion of hydro-
gen produces little or no burden; the use of insulation diminishes
space-heating fuel emissions and conserves energy resources; energy
storage, particularly as compressed gaseous fuel or as compressed air
for turbine power, decreases the environmental burden; and waste heat
recovery, where it is economically practical, diminishes the thermal
pollution of streams and air as well as representing potential resource
conservation.
The systems are qualitatively ranked as follows:
o Hydrogen energy
o Space heating and insulation
9 Energy storage
o Waste heat recovery.
Hydrogen is a vdty 'versatile fuel which"is capable, of providing'large
quantities of electrical* and oLhcr' liorrr.s oL energy including syniinetic
liquid and gaseous fuels. Until natural gas supplies or comparative
costs make hydrogen economically competitive, the incentive to move
swiftly toward a "hydrogen economy" is not present, and therefore, it
is unlikely that significant energy will be developed from this source
through 1990.
The assault on the environment caused by producing hydrogen by coal
gasification and hydrogen utilization to produce steam-electric power
is considered to be less than conventional coal-steam-electric plants.
Nuclear power-water electrolysis produced hydrogen will have little
more environmental impact than the LW nuclear electric plant itself ex-
cept for the inefficiencies of electrolysis and reconversion of the
hydrogen to electricity. An important consideration in the utilization
of hydrogen is that it will not contribute undesirable emissions at the
point of utilization either as fuel for fuel-cells or for steam gener-
ation when electrolytically produced hydrogen and oxygen are used as
the energy source.
Space heating consumes about 20 percent of the nation's energy. Envi-
ronmental emissions from air pollution emission can be effected by
fuels, equipment design, equipment adjustments, and thermal insulation
55
-------
of the structures.
The analyses presented in Appendix X for residential, commercial, and
industrial space heating are based on simplified cases using average
emission factors for different fuel-types in general classes of equip-
ment. An important consideration that is masked by the use of averages
is the wide difference in emission performance between different heat-
ing units within a class; in view of this factor, continued R&D effort
is needed to establish criteria for the design, operation, and mainte-
nance of combustion equipment for minimum emissions.
Improved thermal insulation is one of the most effective, simple, eco-
nomical, and immediate control measures for air pollution emissions
from space heating—and an approach that can be implemented by indivi-
dual home owners.
Hydro-pumped energy storage has proved to be the only practical system
thus far developed to store large quantities of energy recovered from
other systems, but its undesirable utilization of land as reservoirs is
a decided deterrent to its widespread use.
The elctrochemical storage of off-peak energy by means of water electro-
lysis-fuel cell combination in which the hydrogen and oxygen are stored
for later use, offer some attractive possibilities. Unlike hydro-
pumped storage, electrochemical storage is not seriously site restric-
tive. When used in conjunction with nuclear plants, electrochemical
storage of energy would tend to decrease the environmental burden as
Like natural gas, hydrogen may be stored as compressed gas or by lique-
faction. Though this may be accomplished without serious aesthetic
insult to the environment, the matter of leakage of hydrogen from under-
ground storage and gaseous emissions associated with the combustion
process associated with the compressor prime movers may contribute to
the environmental burden.
Compressed air storage from gas turbine power "generating equipment dur-
ing off-peak loads for reuse during peak loads appears to be quite
attractive. The gas turbine will produce only 1/3 the combustion
products as environmental burden since it is unnecessary to provide
power to the compressor during the period when the compressed air stor-
age is used. This system has not as yet been utilized extensively,
however.
Waste heat is generally regarded as the heat rejected in power cycles,
especially those associated with the generation of electricity. Waste
heat recovery and its utilization to produce useful products, and
thereby unburden the environment, hold very marginal promise economi-
cally. Financial incentives exist in the areas of climate control
(particularly in community total energy systems), agriculture, and
56
-------
aquaculture. As higher priority is placed on the conservation of energy
resources, a further enhancement of the benefits from waste heat re-
covery is to be expected.
More detailed descriptions of the energy systems, their environmental
burdens and, where possible, their environmental control costs, and
development costs to bring the system on stream to meet future energy
demands are presented in Appendices W and X.
57
-------
SECTION VIII
ACKNOWLEDGMENT
This report represents the combined efforts of Battelle's Columbus
Laboratories and Battelle's Pacific Northwest Laboratories. The over-
all program was directed by G. R. Smithson, Jr., and E. H. Hall.
Coordinators for the major sections were: E. H. Hall, fossil fuels;
C. M. Allen, advanced energy systems; and R. C. Liikala (BPNL),
nuclear fission. Battelie-Columbus staff and consultants participating
in the fossil fuel section were D. L. Morrison, P. W. Spaite, M. Fels,
W. T. Reid, H. S. Rosenberg, E. P. Stambaugh, M. Y. Anastas, J. M. Genco,
R. A. Ewing, R. W. Sullivan, D. M. Jenkins, H. W. Nelson, D. H. Frieling,
D. D. Moore, and W. J. Sheppard. BCL and BFNW staff participating
in the advanced energy section were J. B. Baker, W. H. Wilkinson,
R. B. Engdahl, P. E. Eggers, R. S. Denning, D. W. Locklin, P. D. Cohn,
M. C. Wolkenhauer, P. N. Lamori, J. E. Clifford, I. M. Grinberg,
J. R. Young, S. G. Talbert, R. E. Barrett, G. B. Gaines, K. Drumheller,
D. F. Newman, D. A. Dingel, and H. Reiquam. Battelle-Pacific Northwest
staff participating in the nuclear fission section were C. H. Bloomster,
J. B. Burnham, T. I. McSweeney, E. T. Merrill, and J. R. Young.
The cooperation of many individuals within EPA in the exchange of in-
formation was an essential element in the performances of this program.
Valuable aisioLciiv-c v.as pt^viucd by J. 0. 3with ijnu X. K. Jcmeb ul
Control Systems Division.
The support of this program by the Office of Research and Development,
Environmental Protection Agency, and the help provided by Mr. K. E.
Yaeger, the Project Officer and by Mr. G. Kendall of the Office of
Planning and Evaluation is acknowledged with sincere thanks.
59
-------
SECriON IX
REFERENCES
1. Environmental Evaluation System for Water Resources Planning, report
to Bureau of Reclamation, U. S. Department of the Interior, by
Battelle Columbus Laboratories, January, L972.
2. Water Pollution Potential of Spent Oil Shale Residues, Colorado
State University for the Environmental Protection Agency, Grant
No. 14030EDB, December, 1971.
3. Draft Environmental Statement for the Proposed Prototype Oil Shale
Leasing Program (3 Volumes), U. S. Department of the Interior,
September, 1972.
4. Wearer, Glen D., "Environmental Hazards of Oil-Sh-ale Development",
The Conservation Foundation, September 15, 1972.
5. BNWL-B-141, "Data for Preliminary Demonstration Phase of the
Environmental Quality Information and Planning System (EQUIPS),
"Battelle, Pacific Northwest Laboratory, December, 1971.
6. Engel, R.L., "DAEDALUS II: A Computer Code to Generate a Linear
Jfrogramming Model of a Nuclear Power Economy", BNWL-1459, June, 1970,
7. USAEC Division of Reactor Development and Technology, "Potential
Nuclear Power Growth Patterns", WASH-1098, December, 1970.
8. Deonigi, D. E., McKee, R. W., and Haffner, D. R., "Isotope Produc-
tion and Availability from Power Reactors", BNWL-716, July, 1968.
61
-------
SECTION X
APPENDICES
Page
A. Data Tables for Selected Modules 65
B. Methodology for Ranking of Energy Systems 165
C. Environmental Emissions—Oil and Gas Exploration,
Drilling, and Production 179
D. Environmental and Economic Considerations Involved
in Oil Shale Developrcent 197
E. Coal Hinins and Underground Gasification 225
F. Gas Pipeline and Underground Gas Storage 239
G. LNG Transportation, Handling, and Storage 243
H. Oil Transportation on Inland Waterways 247
T m.. .,. .... _ .. J - . w , .1 i. -C . .. .r»» _ •* i rt-f* n» -«.*- •
Jb • J.LCIllOlJl'JL UCH.J.WLI J.1UUUXC 4. VI. ItUGJ. CltlUi V J. J. A. L O.IIO'gf \J L. L. UJT
Rail, Truck, and Pipeline 253
J. Electrical Transmission • 275
K. Removal of Sulfur from Natural Gas 283
-L. Petroleum Refining 291
M. Gasification of Crude Oil and Naphtha 315
N. Physical Besulfurization of Coal 329
0. Chemical Desulfurization of Coal 341
P. Production of Synthetic Hydrocarbon Liquids from
Coal (Liquefaction) 353
Q. Coal Gasification 369
R. Generation of Electricity ........ 383
S. Stack Gas Cleaning 393
63
-------
APPENDICES (continued)
Page
• — S m
T, Fluidized-Bed Combustion of Coal and Oil 413
U. Solid Waste Utilization 427
V. Nuclear Fission Systems 437
W. Advanced Energy Systems 521
X. Miscellaneous Energy Systems . 589
64
-------
APPENDIX A
DATA TABLES FOR SELECTED MODULES
A-l. Strip Mining of Eastern Coal 68
A-2. Strip Mining of Western Coal 70
A-3. Deep Mining of Coal 72
A-4. Physical Cleaning of Coal 74
A-5. Chemical Cleaning of Coal 76
A-6. Liquefaction of Coal (Solvent Refinery) 78
A-7. Rail Transport of Coal 80
A-8. Conv. Boiler, Eastern Coal 82
A-9. Conv. Boiler, Western Coal 84
A-10. Conv. Boiler, Physically Cleaned Eastern Coal 86
A-11. Conv. Boiler, Chemically Cleaned Eastern Coal 88
A-12. Conv. Boiler, Liquefied Coal 90
A-13. Conv. Boiler (Limestone Scrubber), Eastern Coal 92
A-14. Conv. Boiler (MgO Scrubber), Eastern Coal 94
A-15. Conv. Boiler (Limestone Scrubber), Western Coal 96
A-16. Conv. Boiler (Limestone Scrubber), Physically Cleaned
Eastern Coal 98
A-17. Gasification (Lo Btu), Eastern Coal - Lurgi 100
A-18. Gasification (Hi Btu), Eastern Coal - Hygas 102
A-19. Gasification (Hi Btu) , Lignite - CC>2 Acceptor 104
A-20. Gasification (Lo Btu), Eastern Coal - Molten Iron
Combustion 106
A-21. Gasification of Crude Oil 108
A-22. High Pressure Fluidized Bed . ." 110
A-23. Chemically Active Fluidized Bed 112
A-24. Gas Well 114
A-25. Gas Desulfurization 116
A-26. Gas Pipeline 118
A-27. Underground Gas Storage 120
A-28. Conv. Boiler, Natural Gas 122
A-29. LNG Tanker 124
A-30. LNG Port Facilities 126
A-31. LNG Storage 128
A-32. LNG Gasification 130
A-33. Oil Shale Extraction and Processing 132
A-34. Oil/Gas Well - On Shore 134
A-35. Oil/Gas Well - Off Shore 136
A-36. Oil Tanker Transport 138
A-37. Oil Pipeline 140
A-38. Oil Barge 142
A-39. Refinery - Domestic Crude .' 144
A-40. Refinery - Imported Crude 146
A-41. Topping Refinery 148
A-42. Conv. Boiler - Domestic Resid 150
65
-------
DATA TABLES (continued)
A-43. Conv. Boiler - Topping Resid 152
A-44. Municipal Refuse Processing (St. Louis Method) 154
A-45. Municipal Refuse Burning, Conv. Boiler, Limestone
Scrubber 156
A-46. Space Heating - Electrical, Gas, Oil, Coal, and
Synthetic Gas from Coal 158
A-47. Nuclear Fission 160
66
-------
APPENDIX A
DATA TABLES FOR SELECTED MODULES
The unit emissions data derived for each of the modules are
given in the following tables. The source of original data and the
assumptions made are given in footnotes to each table, so that the
calculations can be repeated. The references cited are listed at the
end of this Appendix.
67
-------
TABLE A-l. ENVIRONMENTAL DATA FOR MODULE
Module - Strip Mined Coal, East
Unit - 106 Btu (output) '
Environmental Parameters
With Land Restoration and .
Treatment of Acid Drainage^ ^
ALE
NOX> Ib
S02, Ib
CO, Ib
Participate, Ib
Total organic material, Ib
Heat, 10« Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0.0002(2)
Negligible
Negligible
0.14V3)
Negligible
Negligible
0.55<4>
0,18
Negligible
negligible
Nil
0
0.24(5)
Negligible
0
None
5 x 1
2.5 x 10-77
7.A x 10
0.3
-5(8)
(9)
99.6%
(10)
68
-------
Footnotes for Table A-l:
(1) Impacts will be negligible .iftcr land restoration. Stated impacts
will occur during the actual operation.
(2) a. NO released to atmosphere from reclamation operation was
derived based on the assumption that a dicsel powered bulldozer is
used for reclamation.
b. Time requirement for reclamation (assumed) • 4 hr/acre.
c. Bulldozer engine power (assumed) = 150 hp.
d. Fuel consumption ratc^"1^ = 0.5 lb/hp'hr.
e. Emission factor(A-l) = 0.37 Ib N0x/gal of fuel used.
£. Average thickness of coal seam (assumed) = 2 ft.
g. Coal density (assumed) = 82 Ib/ft3.
h. Heating value of coal (assumed) = 12,000 Btu/lb.
(3) a. Emission factor (same as primary rock crushing and copper
mining) =0.1 Ib/ton of overburden.
b. Average overburden per ton of coal (private communication, EPA)
«= 33 tons.
.(4) a. Rate of silt run-off (assumed = 5000 tons/Mi^-year.
b. Average thickness of coal scnm (assumed) = 2 ft.
c. Coal bulk density (assumed) = 82 Ib/ft3.
d. Reclamation period (assumed) = 3 years
(5) a. Dissolved solids (CaSC>4) and sludge (FcOH2) come from acid
treatment (assumed).
h- IVrai itaon '..rsi-»f .'- jrfiai-nr. i-sl-n fnv a ohfi-v "/-.^l '"I'lC Vltlh £
^ ... —. —„ — _ —_. — _ _ — HV..r —- ...—.._ »««..« *.
capacity of 106 ton coal/year (assumed) = 106 gal/day.
c. Acidity of drainage water (assumed) - 1000 ppm.
(6) a. Death rate for strip coal mining(A-12) = 0.12/106 ton coal.
b. Heating-value of coal (assumed) = 24 x 10*> Btu/ton coal.
<7) a. Injury rate for strip coal mining(A"12) = 5.65 injuries/106
ton coal.
(8) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 180 days/injury.
(9) a. Land required for 106 tons of coal(A~12) = 280 acres.
b. Time required for reclamation (assumed) = 3 years.
(10) a. Efficiency of strip mine operation (assumed) = 99.6%.
b. Depictive waste not included.
-------
TABLE A-2. ENVIRONMENTAL DATA FOR KODULE
Module • Strip-mined coal, West
Unit - 1Q& Btu (output)
Environmental Parameters
With Land Restoration and
Treatment of Acid Drainage(1)
NOX, ib
S02, Ib
CO, Ib
Participate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (1150), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings j Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.00008 (Bulldozer operation^2'
negligible
Negligible
0.07(3)
Negligible
Negligible
0.28(4)
Not determined
Negligible
Negligible
Nil.
0
0
0
0
0
None
6.5 x 1
3.) x 10-7<6>
9.6 x 10
0.16
99.8%
(8)
70
-------
Footnotes for Table A-2:
(1) a. Impacts will be negligible after laud restorations. Stated
impacts will occur during the actual operation.
(2) a. KOX comes from a disel powered bulldozer used for reclamation.
b. Time requirement Cor reclamation (assumed = 4 hr/acre.
C. Bulldozer engine power (assumed) = 150 hp.
d* Fuel consumption rate(A~l) = 0.5 Ib/hp - hr.
e. NOX emission factor^"1) = 0.37 Ib/gal fuel used.
£. Average thickness of coal seam (assumed = 5 ft.
g. Coal bulk density (assumed) = 82 Ib/ft^.
h. Heating value of xjestern coal (assumed) = 9235 Btu/lb.
(3) a. Emission factor (given for suspended particulate from primary
rock crushing and for mining of copper ore) =0.1 Ib/ton of
overburden.
b. Average overburden per ton of coal = 13 tons.
(4) a. Rate of silt run-off (assumed) = 5000 tons/midyear.
b. Average thickness of coal seam (assumed) = 5 ft.
c. Coal bulk density (assumed) = 82 lb/ft3.
d. Reclamation period (private communication, E?A) = 3 years.
(5) a. Death rate-, for strip coal mining(A~12) = 0.12/106 ton coal'.
b. Heating value of coal (assumed) = 18.47 x 10*5 Btu/ton of coal.
(6) a. Injury rate for strip coal mining(A~12) = 5.65 injuries/106
con coal.
(7) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 182.6 days/injury.
(8) a. Land required for 106 tons of coal'A~i2' = 112 acres.
b. Time requirement for reclamation (assumed) = 3 years.
(9) a. Efficiency of strip mine operation (assumed) = 99.8%.
71
-------
TABLE A-3. ENVIRONMENTAL DATA FOR MODULE
Module - Eastern Deep-Mined Coal
Unit - 106 Btu (output)
Environmental Parameters
With Treatment of Acid Drainaec
Ail
NOX, Ib
S02, Ib
CO,
Particulate, Ib
Total organic material, Ib
Heat, 106 Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Add (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0
0
0
Negligible
0
0
Negligible
0.06<1>
0
0
0
0
3(3)
0
3 x 1
1.3 x 10-6 5
7.3 x 10~4(6)
0.74(7)
99.6%(8)
72
-------
Footnotes for Table A-3:
(1) a. Amount of acid drainage from deep coal mine attributable to
1000 Mtf plant per ycar^"^2) = 23050 tons/year.
b. Total sulfur content (A'12) = 0.2%.
c. Reclamation time required (assumed) = 10 years.
d. Dissolved solid material (assumed)
(2) a. Total dissolved iron content in acid mine drainage (A-1-2) =
0.167%.
b. Form of sludge (assumed) - Fe (011)3.
(3) a. Waste factor(A~^) = 0.036 tons waste/ton coal mined.
(4) a. Death rate(A~12) = 2 deaths/67.1 x 1012 Btu.
(5) a. Injury rate
-------
TABLE A-4. ENVIRONMENTAL DATA FOR MODULE
Module - Physical cleaning of coal
Unit - 106 Btu (output)
Environmental Parameters
Without
Environmental
Control
With
Environmental
Control
Air
NOV, Ib
SO?;, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Kan Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0.036<2)
0.01(9)
0
0
0
0
0
3.0 x 10-9(12)
6.0 x 10-8(12)
2.6 x 10-5(13)
0.003(14)
887.
(15)
0.01(5)
Negligible
Negligible
Negligible
Negligible
0
0.3(10>
Negligible
0
3.0 x 10"9
6.0 x 10-8
2.6 x 10°
0.003
88%
-------
Footnotes for Table A-4:
(1) &. KOX from thermal dryer. Operating characteristics for evaporating water from wet coal(A-2)
• 550 tons of coal produced per 50 tons of water evaporated.
b. Heat required for water evaporation • 1000 Btu/lb water.
C. Heating value of coal = 12,000 Btu/lb of coal.
d. KOX emission factor(A'l) ° 18 Ib/ton of coal burner.
e. No control equipment.
(2) a. S02 eaisslon factor(A"^ » 38 Ib/ton coal burned.
b. No control equipment.
c. Sulfur content of coal, S (assumed) » 37..
(3) a. Lime scrubber control efficiency (assumed) •> 90Z.
(4) a. Fartlculate emission factor for thermal dryerC*"1) *> 25 Ib/ton coal product.
b. Heating value of coal product = 13,180 Btu/lb.
C. No control equipment.
(5) a. Control efficiency of multiple cyclones with wet scrubber^A"^ •> 99.01 removal.
(6) a. Calculations are based on West Virginia coal.
b. Coal produced in 1963(A~3> ** 132,568,000 tons.
c. Hater discharged to environment in 1962(A~3) • 2,141 x 106 gal.
d. Suspended solid in watcr(A*3) a 157..
e. Density of slurry (assumed) - 62.4 lb/ft'.
(7) a. Dissolved solid in water (assumed) • 1Z.
(6) a. Organic material In the form of alcohol added as a frother in the processing of fines in
amounts of 0.3 Ib/ton produced.
b. 20X of coal produced cooes from fines (assumption).
(9) a. Measured acidity (H2S04)(A'2'A"4> - 198 Ib CaC03/acre-hr.
h. P.a-.. d on a l.QOO J.ar./hr ca=:ci£v 5l:nt.
c. 10% of input shows up as tailings (assumed).
d. Bulk density of tailings (assumed) = 0.8 Ib/ft .
e. Average height of the pile (assumed) = 30 ft.
f. Area occupied by refuse - 27 acres.
(10) a. Sludge comes from 803 and l^SO/, control (assumed).
b. Sulfur content of sludge (assumed) = 12Z.
(11) a. 107. of input shows up as tailings (assumed).
'b. Plant efficiency taken as 88% (losses include tailings, cool burned for drying and other
energy requirements).
(12) a. Basis: 40 men operate a 100 ton/hr capacity sand and gravel plant.
b. Assumption: 80 men operate a 1,000 ton/hr capacity coal cleaning plant.
c. Average injuries and nan-days lost per million man-hours for sand and gravel Industry and
stone quarrying and milling industry are 18.1 injuries/10^ nan-hours and 2,630 days lost/106
man-hours, respectively.^A~^
d. Death rate is assumed as 57. of the Injuries.
(13) a. Man-days lost per death is assumed as 6,000 days/death.
(14) a. Assume 75 acres required for a 1,000 ton/hr capacity plant and refuse pile.
(15) a. The efficiency is assumed to be 88Z.
75
-------
TABLE A-5. ENVIRONMENTAL DATA FOR MODULE
Module - Chemical Cleaning of Coal
Unit - 106 Btu (Output)
Environmental Parameters
Fuel Input» Coal
Ms.
KOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10& Btu
Acid (112S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings', ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Han Days Lost
land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0.002(3)
0.005(4)
0.05(5)
Negligible
Trace
Negligible
Negligible
Negligible
0
0
0
0
0
4.3
(6)
1.4 x 10-9(7)
2.7 x 10-8(7)
6.5 x 10"6(8)
0.08
(9)
95%
(10)
-------
Footnotes for Table A-5 :
(1) a. 100 Ib of product coal is burned in the production of ton of
product coal (assumed).
b. KOX emission factor^"1) = 18 Ib/ton coal burned.
c. Heating value of chemically cleaned coal (assumed) = 24 x 10
Btu/ton coal.
(2) a. Sulfur content of chemically cleaned coal, S (assumed = 1.22%.
b. S02 emission f actor C^'1) =3.85 Ib/ton coal burned
(3) a. CO emission factor^"1) = 1 Ib/ton coal burned.
(4) a. Particulate emission f actor ^"^ = 16 A Ib/ton coal burned.
b. Ash content of chemically cleaned coal, A (assumed) = 14.47..
c. Electrostatic precipitator efficiency (assumed) = 99%.
(5) a. Efficiency of plant operation (assumed) = 95%.
(6) a. Elemental sulfur =0.6 lg/106 Btu.
b. FeS04 =3.7 Ib/lO^ Btu.
(7) a. 80 men operate a 1000 ton/hr capacity chemical coal cleaning
plant (assumed). .
b. Using chemical industry data, injuries per man-hour (A~5/ =8.1
injuries/106 man hours. . .
c. Using chemical industry data, days lost per man hour^"^ =
528 days/lU" man hours.
d. Death rate (assumed) * 5% of total injuries.
(8) a. Man-day lost per death (assumed) = 6000 days/death.
(9) a. Land requirement for a 400 tons coal/hr capacity plant
(assumed) = 750 acres.
(10) a. Plant efficiency (assumed) = 95%.
77
-------
TABLE A- 6. ENVIRONMENTAL DATA FOR MODULE
Module - Coal Liquefaction (solvent refining)
Unit - 106 Btu (output)
Environmental Parameters
Fuel Input, Eastern Coal
(1)
Air
NO , Ib
SO-, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10» Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10& Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.21(2)
0,003(3)
On012(4)
0.27(5>
0.0036(&)
0.067(7>
0
0
Trace
Negligible after cooling tower
0
0 :
16.0(8)
0
0
0
2.95
<9>
1.4 x 1
2.7 x 10-8(«)
6.5 x l
(1) Impacts were estimated based on the coal containing 14.4% ash, 3.0%
S and a heating value of 12,000 Dtu/lb. In addition, the conl
liquefaction plant was assumed to have a capacity of 222xlO^Btu/day.
78
-------
Footnotes Tor Table-A-6 (Continutcd):
(2) a. Solvent refined coal (SRC) has a heating value of 16,000 Btu/lb,
0.057. ash, and 0.6% sulfur(^-6).
b. Plant cfficiency(A-6) = 75%.
c. Emission factor for NOX - 18 Ib/ton of coal burned.
'd. Average heating value of consumed coal = 14,000 Btu/lb.
e. Coal consumption rate = 110 tons/hr.
(3) a. Total sulfur content in the input coal - 30,833 Ib/hr.
b. Total sulfur content in the SRC - 3.469 Ib/hr.
c. Sulfur emitted as S02 = 0.1% total sulfur off gas-liquid
separator.
(4) a. CO emission factor(A-1) = 1 Ib/ton of coal burned.
b. No control equipment.
(5) a. Particulate emission factor(A~l) = 16A Ib/ton of coal burned.
b. Emission control efficiency (assumed) 98%.
c. Average ash content of consumed coal, A = 7.23%.
(6) a. Total organic material emission factor ** 0.3 Ig/ton of coal
burned.
b. No control equipment.
(7) a. Total heat released = 0.308 x 1010 Btu/hr.
(8) a. Totil ash input rats = 148:000 Ib/hr.
b. Total ash output rate in SRC = 289 Ib/hr.
(9) Elemental sulfur product = 99.9% of total sulfur-off gas, liquid
separator.
(10) a. Assumption: 80 men operate a 1,000 ton/hr capacity solvent
refining plant.
b. Use chemical industry data, injuries per man hour(A-5) = g.i
injuries/106 man hours.
c. Use chemical industry data, days lost per man hour^'S) = 528
days lost/10^ man hours.
d. Death rate = 5% of total injuries (assumed).
(11) Man days lost per death (assumed) = 6,000 days/death.
(12) Land required for a 222 x 109 Btu/day plant (assumed) = 750.acres.
(13) Plant efficiency(A-6) = 75%.
79
-------
TABLE A-7. ENVIRONMENTAL DATA FOR MODULE
Module - Railroad Transportation of Coal
Unit - 106 Btu (output)
Environmental Parameters
Fuel Input, Coal
Air
NOX> Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10" Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10^ Btu
Acid (1I2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Kan Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
O.OOU<2)
0.015(3)
0.0015(4)
Negligible
0.0039(5)
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
0.083(6)
Negligible
Negligible
3.2 x 1
3.2 x 10-7(8)
2.2 x 10-^(9)
0.29<10>
100%(n>
80
-------
Footnotes for Table A-7:
C1) a. Total quantity of coal transportcd(A"7) = 695 x 106 tons/year.
b. Total shipment from rail and barge(A-8) = 8.13%.
c. Tot?l shipment from rail (assumed) = 7.13%.
d. NOX emission per 106 hp-hr(A-9) = 15.43 tons/106 hp-hr.
e. Assume a 3,000 horsepower required for each 2,000 tons of gross
load in a locomotive-train system.
f. Average horsepov;er of the locomotive-train system'A-10) = 74.9%
of the maximum horsepower.
g. Ratio of average gross tonnatc to average net tonnage(A-10) =
2.3481.
(2) a. S02 emission per 106 hp-hr^A~9) = 1.1 tons/106 hp-hr.
(3) a. CO emission per 106 hp-hr(A-9) = 11.9 tons/106 hp-hr.
(4) a. Particulate emission (assumed) = 10% of CO.
(5) a. Hp-hr required to move the ton-mill of coal transported by rail
per year = 7554.6 x 106 hp-hr/yr.
b. Definition and value of the brake thermal efficiency(A~H) =
Fuel flow/Brake fuel consumption (100/(0.456) _ 7Q ,.,
[Fuel flow] Fuel heating value (19 ,156) (3.929 x 10"^" ^'lf"
c. Energy that the fuel carries into the locomotive = 2.59 x 1010
hp-hr/y^ar.
(6) a. The fraction of intransit storage-handling dust loss = 0.1%
of the total coal transported.
(7) a. Number of death occurred on the railroad system^"10) = 2299
death/year.
b. Total ton-miles shipped by rail(A"^|_= 7.7 x 1011 tons/year.
c. Ton-miles shipped for coal by rail' ' = 1.26 x lO^/year.
(8) a. Number of injuries occurred on the railroad system(A-10) _
23356 injuries/year.
(9) a. Man days lost per death (assumed) = 6000 man days.
b. Man days lost per injury (assumed) = 100 man days.
(10) a. Current land rights of the railroad system(A"10) = 3760 sq miles.
(11) a. Module efficiency (assumed) = 100%.
81
-------
TABLE A-8. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler
Unit - 106 Btu (Input)
Environmental Parameters
Fuel Input. Eastern Coal
Air
HOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 100 Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Sol id
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/]06 Btu
Approx. Modulo Efficiency
0.75(1)
4.75(2)
0.013(5)
0.63(6)
o.oii(8)
Negligible after cooling tower
0
12.0(9)
0
0
0
3.3 x 10-1Q(10)
1.4 x 10-8d°)
5.1 x 1
377.U3)
82
-------
Footnotes for Table A-8:
(1) a. NOX emission factor^"1' = 18 Ib/ton of coal burned.
(2) a. S0? emission factor (A"1) = 38 S Ib/ton of coal burned.
b. Sulfur content, S (assumed) - 3%.
(3) a. CO emission factor™"*' = 1 Ib/ton coal burned.
(4) a. Particulate emission f actor ^-1 = 15^ Ib/ton coal burned.
b. Ash content, A (assumed) = 14.4%.
c. Electrostatic precipitator efficiency (assumed) = 99%.
(5) a. Hydrocarbons emission factor (A~l) = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler (assumed) = 37%.
(7) a. Total solid to water (A"12) = 0.036 lb/106 Btu.
b. Fraction of suspended solid (assumed) = 70%.
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of coal (assumed) = 14.4%
(10) a. Man-hours required per 10 Etu for conventional power plant (A~13'
» 2.4 x 10~3 man-hour /I 0& Btu.
b. Total injuries per 106 man hour^A~13' - 5.7.
c. Death rate^A"12^ = 2.4% of injuries.
(11) a. Days lost per death (assumed) = 6000 days/death.
b. Days lost per injury (assumed) 229 days/injury.
(12) a. Land required for a 1000 MH power plant (assumed) = 800 acres.
(13) a. Efficiency of conventional boiler (assumed) = 37%.
83
-------
TABLE A- 9. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler (Coal)
Unit - 106 Btu (Input)
Environmental Parameters
Fuel Input, Coal, West
-Air
KOX, Ib
S02, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, IQo Btu
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
n. - 1 M »
OUJ.J.U
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Kan Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0.98C1)
1.65(2)
0,07(4)
0.016(5)
0,63(6)
0.025(7)
0 ,_.
O.OH(8)
Negligible after cooling tower
0
0
9.0(9)
0
0
0
3.3 x l
1.4 x 10"8(10)
5.1 x 1
-------
Footnotes for Table A-9:
(1) &. NOX emission factor"-!) c is lb/ton coal burned.
b. Heating value of western coal (assumed) 9200 Etu/ib.
(2) a. S02 emission factor^"1) = 38 S lb/ton coal burned.
b. Sulfur content, S (assumed) = 0.8%.
(3) a. 00 emission factor(A-l) = i lb/ton coal burned.
(4) a. Particulate emission factor(A~D = 16A lb/ton coal burned.
b. Ash content, A (assumed) = 8.4%.
c. Electrostatic precipitator efficiency (assumed ) = 99%.
(5) a. Hydrocarbons emission factor(A~l) = 0.3 lb/ton coal burned.
(6) -a. Efficiency of conventional boiler (assumed) = 37%.
(7) a. Total solid to water(A-12) =0.036 lb/106 Btu.
b. Fraction of suspended solid (assumed) = 70%.
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of coal (assumed) = 8.4%.
(10) a. Man-hour required per 10^ Btu for conventional power plant
« 2.4 x 10"3 man hour.
h. Tnt-»l *".j"r*«5 --n '0° nan-hour^"^ = r. y
c. Death rate(A~l2^ = 2.4% of injuries.
(11) a. Days lost per death (assumed) = 6000 days/death.
b. Days lost per injury (assumed) = 229 days/death.
(12) a. Land required for a 1000 MW power plant (assumed) = 800 acres.
'(13) a. Efficiency of cc wentional boiler (assumed) = 37%.
85
-------
TABLE A-10. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler
Unit - 106 BCu (Input)
Environmental Parameters _ Fuel Input, Physically Clean
Air
NOV, Ib 0.68C1)
S02> lb 2'02(«x
CO, lb 0.038(3)
Particulate, lb 0.044(4)
Total organic material, lb 0.011^)
Heat, 106 Btu 0_63(6)
Water
Suspended solids, lb 0.025
Dissolved solids, lb 0
Total organic material, lb 0.01l(8)
Heat, 106 Btu Negligible after cooling to.wer
Acid (H2S04), lb 0
Solid
Slag, lb 0
Ash, Ib 5.4lO)
Sludge, lb 0
Tailings, lb 0
Hazardous , lb 0
By-Products 0
Occupational Health
Deaths 3.3 x l
Total Injuries LA x 1
Man Days Lost 5.1 x 1
Land Use, acre-hr/106 Btu O.l(12)
Approx. Module Efficiency 37%(13)
86
-------
Footnotes for Table A-10:
(1) a. NOX emission f actor (A~l) = L8 Ib ton coal burned.
b. Heating value of physically cleaned coal = 13,1SC BUu/lb.
(2) a. Sulfur content, S (assumed) = 1.4%.
b. Emission factor for SC^"1) - 38 S Ib/ton coal burned.
(3) a. CO emission factor^"1) = 1 Ib/ton coal burned.
(A) a. Ash content of coal, A (assumed) = 7.25%.
b. Particulate emission f actor (^-1) = 16A Ib/ton coal burned.
c. Electrostatic precipitator efficiency (assumed) = 99%.
(5) a. Hydrocarbon emission factor'^-l) = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler (assumed) = 37%.
(7) a. Total solid to water^A"12^ = 0.036 lb/106 Btu.
b. Fraction of suspended solid (assumed) = 70%.
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of coal (assumed) = 7.25%.
(10) a. Man-hour required per 10 Btu for conventional power plant (A-13)
» 2.4 x 10"3 man-hour/10^ Btu.
b. Total injuries^pcr 106 man hours(A~13) = 5.7.
c. licach ratcv'1"1^' = 2.47, ot injuries.
(11) a. Days lost per death (assumed) = 6000 days/death.
b. Days lost per injury (assumed) = 229 days/injury.
(12) a. Land required for a 1000 MM power plant (assumed) = 800 acres.
(13) a. Efficiency of conventional boiler (assumed) = 37%.
87
-------
TABLE A-11. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler
Unit - 106 Btu (input)
Environmental Parameters
Fuel Input, Chemically Cleaned
Air.
NOX, ib
S02, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, IQ
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10& Btu
Acid (lI2SO/j), Ib
0.63<6>
0.025(7)
Negligible after cooling tower
0
Slag, Ib
Ash, Ib
Sludge, Ib
Tailinga, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Han Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0
0
0
3.3 x 10-10(10)
l.A x 10"8dO)
5.1 x 10-6(11)
37%
<13>
-------
Footnotes for Table A-ll:
(1) a. NOX emission factor^"1) =18 Ib/ton coal burned.
b. Heating value of chemically cleaned coal = 12,000 Btu/lb.
(2) a. Sulfur content of eastern coal (assumed) = 3%.
b. Fraction of inorganic sulfur (assumed) 2.0%.
c. Removal efficiency (assumed) = 89% of inorganic sulfur.
d. Emission factor for 502^"*' = 38 S Ib/ton coal burned.
e. Sulfur content of chemically cleaned coal, S = 1.22%.
(3) a. CO emission factor'A~*' = 1 Ib/ton coal burned.
(4) a. Ash content of coal, A (assumed) - 14.4%.
b. Particulate emission factor(A-l) = 16 A Ib/ton coal burned.
c. Electrostatic precipitator efficiency (assumed) = 99%.
(5) a. Hydrocarbon emission factor'""*' = 0,3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler (assumed) = 37%.
(7) a. Total solid to water (A-12) = 0.036 lb/106 Btu.
b. Fraction of suspended solid (assumed) = 70%.
(8) a. Fraction of organic material in total solid (assumed) - 30%.
a. Ash content of coal (assured} = 14.4%.
(10) a. Han-hour required per 10^ Btu for conventional power plant™
•= 2.4 x 10"3 man hour/106 Btu.
b. Total injuries per 10^ man hour (A~ 13) = 5.7
c. Death rate(A~12) = 2.4% of injuries.
.(11) a. Days lost per death (assumed) = 6000 days/death.
b. Days lost per injury (assumed) = 229 days/injury.
(12) a. Land required for a 1000 MW power plant (assumed) = 800 acres.
(13) a. Efficiency of conventional boiler (assumed) = 37%.
89
-------
TABLE A- 12. ENVIRONMENTAL DATA FOR MODULE
Mbdul" - Conventional Boiler
Unit - 106 Btu (input)
Environmental Parameters
Fuel Input,
Solvent Refined Coal (Eastern)
NO , Ib
SO,, Ib
CO, Ib
^articulate, Ib
Total organic material, Ib
Heat, IQo Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid Clso>> lb
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous , Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
land Use. _acre-hr/106 Btu
Approx. Nodule Efficiency
0.71(2)
0.037(3)
0.0003
O.OlO)
0.011<8)
igible after cooling tower
0
0
0.031<9)
0
0
0
3.3 x 10-10(1°)
ft /i r\ \
.
5.1 x 10-6(11)
90
-------
Footnotes for Table A-12:
(1) a. NOX emissions factor^"1' = 18 Ib/ton coal burned.
b. Heating value of solvent refined coal (SRC) (assumed) -
16000 Btu/lb.
(2) a. Sulfur content of solvent refined coal, S (assumed) = 0.6%.
b. S02 emission factor(A-1) = 38 S Ib/ton coal burned.
(3) a. CO emission factor^'1) = 1 Ib/ton coal burned.
(4) a. Ash content of SRC, A (assumed) = 0.05%.
b. Particulate emission factor^"*' = 16 A Ib/ton coal burned.
c. Electrostatic precipitator efficiency (assumed) = 99%.
(5) a. Hydrocarbon emission factor^"1) = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler (assumed) = 37%.
(7) a. Total solid to water^A"12^ = 0.036 lb/106 Btu.
b. Fraction of suspended solids (assumed) = 70%.
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of coal (assumed) = 0.05%.
/1HA 'i \for> _%<-.• if v-f..., ii fr\.'. nr.i- 1 OO 'SI-., r*>*i f.....s>.-. I- : ,.,. o 1 no-.nv ^ T n^<- (A "13 )
\ ^^ t •• • • ••" •• ••*»•»* A«««Jh«^flBV«M ^ ^ m, ^^ «*••«•• *m*r ^ ^•^••v«««l^^%*a*»Adl fh^vlwfl. •^^•^••«>
= 2.4 x 10"3 man hour/106 Btu.
b. Total injuries per 106 man hour(A-13) = 5.7,
c. Death rate
-------
TABLE A- 13. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler and Limestone Scrubbing
Unit - 106 Btu (input)
Environmental Parameters
Fuel Input, Coal, East
Air
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (HoSO/,), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous , Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0.60(1)
0.50(2)
0.013(5)
0.65(6)
o.on(8)
Negligible after cooling tower
0
0
0
3.3 x l
1.4 x 10-8(11)
5.1 x 10-6(12)
0.1(13)
92
-------
Footnotes for Table A-13:
(1) a. NOX emission factor' ' = 18 Ib/ton coal burned.
b. Heating value of eastern coal (assumed) = 12000 Btu/lb.
c. NOX removal efficiency by limestone scrubber (assumed) = 20%.
(2) a. Sulfur content of eastern coal, 5 (assumed) =3%.
b. S02 emission factor(A~l) = 38 S Ib/ton coal burned.
c. Limestone scrubber efficiency (assumed) = 90%.
(3) a. CO emission factor'^""*-' = 1 Ib/ton coal burned.
(4) a. Ash content of eastern coal. A (assumed) - 14.4%.
b. Particulate emission factor(A-l) = jg A Ib/ton coal burned.
c. Scrubber efficiency for particulate removal (see App. S) = 99%.
(5) a. Hydrocarbon emission factor^"1) = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler with limestone scrubbing
(assumed) = 35%.
(7) a. Total solid to water^A"12^ - 0.036 lb/106 Btu.
b. Fraction of suspended solids (assumed) - 70%.
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of eastern coal (assumed) = 14.4%. 20% to bottom ash.
(10) a. Sulfur content of sludge (assumed) - 12%. Add fly ash collected.
(11) a. Man-hour required per 10^ Btu for conventional power plant^ '
18 2.4 x 10-3 man hour/106 Btu.
b. Total -injuries per 10$ Man hour^A~^) =5.7.
c. Death rate(A'12> = 2.4% of injuries.
(12) a. Days lost per death (assumed) = 6000 days/death.
b. Days lost per injury (assumed) = 229 days/injury.
(13) a. Land requirement for a 1000 MH power plant (assumed) = 800 acres.
(14) a. Efficiency of conventional boiler with limestone scrubbing
(assumed) = 35%.
93
-------
TABLE A-14. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler & MgO-Scrubbing
Unit - 106 Btu (Input)
Environmental Parameters
Input: Eastern Coal
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10" Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 !3tu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, -lb
Tailings, lb
Hazardous, lb
Byproducts
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Approx. Modulo Efficiency
'
0.50<«
0.042t3)
0.1(*)
0.013(5)
o.on(8)
Negligible after cooling tower
0
0
2.4(9)
l0.4d'oT
0
6.13 (ID
3.3 x I
1.4 x 10-8(12)
5.1 x 10-6(13)
94
-------
Footnotes for Table A-14:
(1) a. KOX emission factor(A"l) = 18 Ib/ton coal burned.
b. Healing value of eastern coal (assumed) = 12,000 Btu/lb.
C. KOX removal efficiency by KgO-scrubber (assumed) = 20%.
(2) a. Sulfur content of eastern coal, S (assumed) - 3%.
b. S02 emission factor(A-l) = 38 S Ib/ton coal burned.
c. MgO-scrubber efficiency (assumed) = 90%.
(3) a. CO emission factor(A~*) = 1 Ib/ton coal burned.
(4) a. Ash content of eastern coal. A (assumed) 14.4%.
b. Particulate emission factor.A-l) = 16 A Ib/ton coal burned.
c. Scrubber efficiency for particulate removal (see App. S) = 99%.
(5) a. Hydrocarbon emission factor* ' = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler with MgO-scrubbing (assumed)
•= 35%.
(7) a. Total solid to water(A~12> = 0.036 lb/106 Btu.
b. Fraction of suspended solids (assumed) - 70%.
(8) a. Fraction of organic material in total solid (assumed) = 307..
(9) a. Ash content of eastern coal (assumed) = 14.4%. 20% to bottom ash.
(10) a. MgO reacts with S02 to product 80% of MgS03-6H20 and 20% of
MgS04-71120 (assumption).
b. 1% blowdown of MgS03'61120 and MgS04«7H20 (assumed).
c. Loss in regeneration (assumed) = 5%. Add fly ash collected.
(11) a. Sulfur reacted with MgO is regenerated in the form of l^SC^.
b. Regeneration efficiency (assumed) = 100%.
(12) a. Man-hour required per 10" Btu for conventional power plant(A~13)
«= 2.4 x 10"3 man-hour/106 Btu.
b. Total injuries per 106 man hour(A-13) =5.7.
c. Death rate(A~12) = 2.4% of injuries.
(13) a. Days lost per death (assumed = 6000 days/death.
b. Days lost per injury (assumed) - 229 days/injury.
(14) a. Land requirement for a 1000 MW power plant (assumed) = 800 acres.
(15) a. Efficiency of conventional boiler with MgO-scrubbing
(assumed) = 35%.
95
-------
TABLE A-15. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler (Limestone Scrubb)
Unit - 106 Btu (input)
Environmental Parameters
Fuel Input, Coal, West
NOX, Ib
S02, Ib
CO, Ib
Participate, Ib
Total organic material, Ib
Heat, 10» Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Han Days Lost
Land Dsc, acre-hr/lO6 Btu
Approx. Module Efficiency
0.78^)
0.16<2)
0.054(3)
0.016(5)
0.65(6)
o.on(8)
Negligible after cooling tower
0
1.8(9)'
13.4UO)
0
0
3.3 x 10-10
-------
Footnotes for Table A-15:
(1) a. NOX emission factor(A-l) = 18 Ib/ton coal burned.
b. Heating value of western coal (assumed) = 9200 Btu/lb.
c. NOX removal efficiency by limestone scrubber (assumed) = 20%.
(2) a. S02 emission factor = 38 S Ib/ton coal burned.
b. Sulfur content of western coal, S (assumed) = 0.8%.
c. Limestone scrubber efficiency (assumed) - 90%.
(3) a. CO emission f actor (A-1) = 1 Ib/ton coal burned.
(4) a. Participate emission factor (A"^) = 16 A Ib/ton coal burned.
b. Ash content of western coal, A (assumed) = 8.4%.
c. Scrubber efficiency for particulate removal (see App. S) = 99%.
(5) a. Hydrocarbon emission factor'^-"^ = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler with limestone scrubbing
(assumed) = 35%.
(7) a. Total solid to water^A~12) = 0.036 lb/106 Btu.
b. Fraction of suspended solids (assumed) = 70%.
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of western coal (assumed) = 8.4%. 20% to bottom ash.
(10) a. Sulfur content of sludge (assumed) = 127.. Add tiy ash collected.
(11) a. Man-hour required per 10^ Btu for conventional power plant™"13'
= 2.4 x 10"3 man hour/106 Btu.
b. Total injuries per 10& man hourCA'1^) = 5.7.
c. Death rate
-------
TABLE A-16. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler - Limestone Scrubbing
Unit - 10& Btu (Input)
Environmental Parameters
Fuel Input,
Physically Cleaned Coal, East
NOX, Ib
SO,, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings,, Ib
Hazardous , Ib
By -Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/10^ Btu
Approx. Modulo Efficiency
0.55(D
0.2(2)
0.038(3)
0.011(5)
0.65(6)
0.025(7)
0
0.011(8)
Negligible after cooling tower
0
0
1.1(9)
U.9(10)
0
0
3.3 x 10-10(11)
1.4 x 1
5.1 x 1
35XC1A)
98
-------
Footnotes for Table A-16:
(1) a. NOX emission factor (A"l) = 18 Ib/ton coal burned.
b. Heating value of physically cleaned coal -• 13,180 Btu/lb.
c. NOX removal efficiency by limestone scrubber (assumed) - 20%.
(2) a. Sulfur content of physically cleaned coal, S (assumed) = 1.4%
b. Emission factor for SC^^"1^ = 38 S Ib/ton coal burned.
c. Limestone scrubber removal efficiency (assumed) = 90%.
(3) a. CO emission factor(A~*) = 1 Ib/ton coal burned.
(4) a. Ash content of physically cleaned coal, A (assumed) = 7.2%.
b. Farticulate emission factor'^-l) = 15^ Ib/ton coal burned.
c. Scrubber efficiency for participate removal (see App. S) = 99%.
(5) a. Hydrocarbon emission factor (A~l) = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler with limestone scrubbing
(assumed) = 35%.
(7) a. Total solid to water (A"!2) = 0.036 lb/106 Btu.
b. Fraction of suspended solids (assumed) = 70%.
(8) a. Fraction of organic material in total solids (assumed) = 30%.
(9) a. Ash content of physically cleaned coal (assumed) = 7.25%.
Of»7 t;r. hr»t-t-m «sh.
(10) a.'. Sulfur content of sludge (assumed) = 12%. Add particulate collected.
(11) a. Man hour required per 10^ Btu for conventional power plant^
= 2.4 x 10"3 man hour /lO^ Btu. . .
b. Total injuries per 106 man hours CA~iJJ =5.7.
c. Death ratetA~12) = 2.4% of injuries.
(12) a. Days lost per death (assumed) = 6000 days/death.
b. Days lost per injury (assumed) = 229 days/injury.
(13) a. Land requirement for a 1000 MW power plant (assumed) = 800 acres.
(14) a. Efficiency of conventional boiler with limestone scrubbing
(assumed) = 35%.
99
-------
TABLE A- 17. ENVIRONMENTAL DATA FOR MODULE
Module - Lurgl Gasificr and Conventional Boiler
Unit - 10^ Btu (input to conventional boiler)
Environmental Parameters
Fuel Input, Coal,, East
NOX, Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Phenols, Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
_Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.93(2)
0
0.015(3)
0.11(4)
0.92(5)
0.016(6)
0
Negligible after cooling tower
0.0029(8)
0
9.82(9)
0
0
0
1.9(1°)
1.5 x 1
3.6 x 10-8(12)
9.4 x 1
25.9%
(15)
100
-------
Footnotes for Table A-17:
(1) a. KOX comes from gas-fired boiler In gasiflor plant and gas-fired power plant.
b. I.'0X emission factor(A'l) - 0.39 Ib/I0& Bcu for natural gas.
C. The emission factor Is value t'or Lurgl gas combustion on the basis of heating value
(assumed).
(2) o. Basis: 1COO MM nominal togas power plant.(A-6)
b. Coal input rateC*"6) = 341 tons/hr.
C. S02 emission cones from gas-fired boiler In gasifier plant and gas-fired power plant.<*•*)
d. 11 of sulfur lost to atr.osphcre from gasificr plant b/ leaking (assumption).
e. Content of 1I2S in Lurgl gas produced^'6) = o.!05« by volunc.
f. Lurgi gas production rate from the plant - 112600 Ib-males/hr.
(3) a. Paniculate emission cc-aes from gas-fired power plant (assumed).
b. Emission factor for natural gas(A"l) - 0.015 lg/106 Etu.
c. Assumed that the emission factor for natural gas combustion Is valid to Lurgl gas combus-
tion on the basis of heating v: lue.
(4) a. \"i of total organic matter (COS and CH^) Is lost from gasifier by leaking (assumed).
(5) a. 631 of the total input energy to gas-fired power plant is lost to atmosphere (based on the
assumed efficiency of the power plant).
b. Efficiency of Lurgi gasifier plant (assumed) - 70%.
c. Efficiency loss due to material loss in Lurgl gasifier plant (assumed) - 101.
(6) a. Suspended solio emission comes from gas-fired power plant (assured).
b. Emission from a 1000 !W plant(A'12) = 543 tons.
(7) a.' Total organic material comes from gas-fired power plant (a sumed).
b. Emission factor^*'12) - 73 tons/year for a 1000 MM plant.
(8) a. From data supplied by T. K. Janes, EPA.
(9) a. Ash content of coal (assumed) «• 14.4%.
(10) a. The by-product of Lurgi gasifier plant is sulfur from Claus unit.
(11) a. Injuries are combined for Lurgi gasifict plant and gas-fired power plant operations.
b. 40 men operate a 500-ton coal/hr capacity Lurgi gasifier plant (assuned).
C. Using chemical industry data, injuries pci man-hour^*0' = 8.1 Injuries/106 man-hours.
4. Death rate (assumed) «= iZ of total Injuries.
c. Death attributed to a 1000 MW gas-fired power plantt*'12' • 0.01 death/year.
(12) a. Injuries attributed to a 1000 MW p.as-fired power plant
-------
TABLE A-18. ENVIRONMENTAL DATA FOR MODULE
Module - Hygas (Gasification of Coal-High Btu)
Unit - 106 Btu (output)
Environmental Parameters
Fuel Input, Coal, East
Air
NOX, Ib
S02, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, 10» BCu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Phenols, Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acro-hr/lO6 Btu
Approx. Modulo Efficiency
0.25 CD
0.55(2>
0-
0.120)
0.0014(4)
0.34(5)
0
0
Negligible
Negligible after cooling tower
4.6 x 10-5(6)
25.8(8)
0
0
2.0(9)
5 x 10-9(10)
1.7 x 10-7(10)
4.6 x 10-5(n)
0.02^2)
102
-------
Footnotes for Table A-18.
(1) a. NO,, emission comes from a 110 NW power plant in the Hygas
plant. *
b. NOX emission factor (assumed) = 0.72 lb/10^ Btu generated by
the power plant.
c. Hygas plant capacity^"**) = 80 x 10^ scfd.
d. Keating value of gas produced(A~6) = 950 Btu/ft^.
(2) a. S02 emission comes from tvio limestone scrubbers.
b. Sulfur from limestone scrubbers(A~6) = 1300 Ib/hr.
c. Sulfur content of coal used in this calculation (assumed) =37*.
d. Adjustment factor for sulfur content^A~&^ = 0.68.
(3) a. Ash content of coal used in this calculation (assumed) = 1
b. Adjustment factor for ash content(A-&) = 1.31.
c. 657, of total ash goes to scrubber as parciculate (assumed).
A. Limestone scrubber efficiency for removal of particulatc
(assumed) = 99%.
(4) a. Hydrocarbon emission comes from a 110 1-2-J power plant.
b. Hydrocarbon emission factor (assumed) = 0.04 lb/105 Btu.
(5) a. Efficiency of Hygas plant(A~6^ - 66%.
(6) a. Assumed to be same as for C02 acceptor (see C02 Acceptor for
the detail).
(7) a. Ash comes from be. Ler (bottom ash).
(8) a. Sulfur from Limcstona scrubbers^"6* - 7600 Ib/hr.
b. Sulfur content of sludge = 12%.
c. Adjustment factor for sulfur content in fuel™"6' = 0.58.
d. Sludge-comes from limestone scrubbers (limestone slurry plus
particulate collected).
(9) a. Elemental sulfur from Glaus plant is the sole by-product
(assumed).
b. Adjustment factor for sulfur content in coal = 0.6B.
(10) a. Han-hours required for a IxlO10 Btu/hr capacity Hygas plant
(assumed) - 4000 man hours/day.
b. Injury rate (assumed) = 10 injuries/106 man hours.
c. 3% of injury assumed fatal.
(11) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 95 days/injury.
(12) a. Personal communication with EPA.
(13) a. Reported by Processes Research.^A~6^
103
-------
TABLE A-19. ENVIRONMENTAL DATA FOR MODULE
Module - COp Acceptor (Gasification-High Btu)
Unit - 106 litu (output)
Environmental Parameters
Fuel Input, Lignite
.ALT.
NOX> Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10^ Btu
Phenols, Ib
Sol id
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Prodnets
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acro-hr/106 Dtu
Approx. Modulo efficiency
0
0.02(2)
0
0
Negligible
Negligible after cooling tower
4.6 x 10-5(4)
0
39.9(5)
0
0
0
(6)
1.8
5 x 1
1.7 x 1(T7<7)
4.6 x 10-5(8)
0.02(9)
104
-------
Footnotes for Table A-19:
(1) a. SO? emission comes from lignite dryer, regenerator and Claus
-
b. S02 from lignite dryer(A~6) = 3600 Ib/hr.
c. S02 from regenerator of f-gas(A"6) = 2400 Ib/hr.
d. S02 from Claus unit(A"6) = 120 Ib/hr.
e. C02 Acceptor plant capacity = 10,AOO x 106 Btu/hr.
f. Lignite sulfur content (assumed )= 1%.
g. Adjustment factor for sulfur^"") = 1.7.
(2) a. Fly ash from lignite dryer(A'6) = 16,000 Ib/hr.
b. Ash content of lignite in this calculation (assumed) = 10%.
c. Adjustment factor for ash(A-6) = 1.4.
d. Efficiency of electrostatic precipitator (assumed) = 99%.
(3) a. Efficiency of the plant = 62% (personal communication with
T. K. Janes of EPA).
(4) a. Total wastcwater from spray tower acid gas cemover, and com-
pressor (A-6) = 481,500 Ib/hr.
b. Phenol concentration (assumed) = 1 ppm.
(5) a. Ash from acceptor stripper^"6) = 154,000 Ib/hr.
b. Acceptor from acceptor stripper (A-6) = 60,000 Ib/hr.
c. Adjustment factor for ash(A-6) =1.4.
d. Adjustment factor for acceptor^"6) = 1.7.
e. Fly ash collected from precipitator =2.13 lb/106 Btu.
(6) a. Elemental sulfur from Claus unit^A~6^ = 10,840 Ib/hr.
b. Adjustment factor for sulfur (A~6) = 1.7.
(7) a. Man hours required for a 1 x 1010 Btu/hr capacity C02 acceptor
plant (assumed) = 4000 man hours/day.
b. Injury rate (assumed) = 10 injuries/106 man hours.
c. 3% of injury assumed fatal.
(8) a. Man days lost per death (assumed) = 6000 days/death.
b. Man days lost per injury (assumed) = 95 days/injury.
(9) a. Personal communication with EPA.
(10) a. Personal communication with T. K. Janes of EPA.
105
-------
TABLE A-20. ENVIRONMENTAL DATA TOR MODULE
Module - Molten Iron Combustion Plus Conventional
Unit - 106 Btu (input to boiler) Boiler
.Environmental Parameters Fuel Input, Coal, East
NO , Ib 0.39^)
SO,, Ib 0.017(2)
CO, Ib 0
Particular, Ib 0.034<3)
Total organic material, Ib 0.04(4)
Heat, 100 Btu 0.65(5)
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib 0
Heat, 10^ Btu Negligible after cooling tower
Acid (I12S04), Ib 0
.Solid
Slag, Ib 10(6>
Ash, Ib 0
Sludge, Ib 0
Tailings', Ib 0
Hazardous, Ib 0
ByProdiicts 3.1 Processes Research Report
Occupational Health
Deaths 1.5 x 10"9(7)
Total Injuries 3.6 x 10"8(8)
Man Days Lost 9.4 x 10'6(9)
Land Use, acrc-hr/106 Btu 0.12(10>
Approx. Module Efficiency 357.(11)
106
-------
Footnotes for Table A-20:
(1) a. NOX emission comes from burning of product gas in a conven-
tional boiler (assumed).
b. NOX emission factor for product gas (assumed) = 390 lb/10^ ft3.
c. Heating value of product gas (assumed) = 1000 Btu/ft3.
(2) a. S02 from conventional boiler(A~6) = 142 Ib/hr.
b. Capacity of power plant(A~6' = 1000 Mtf
c. S02 from Claus unit(A~6) = 60 Ib/hr.
d. Adjustment factor for sulfur = 0.833 (i.e., ~?)
3.6
(3) a. Assume 0.02 gr/ft3 of particulate in exit gas.
b. Stack gas flow rate (assumed) = 2000 ft3/MW-min.
(4) a. Hydrocarbon emission for burning product gas (assumed) =
40 lb/106 ft3.
(5) a. Approximate module efficiency (assumed) = 35%.
(6) a. Slag from slag desulfurizer^"6) « 120,000 Ib/hr.
b. Adjustment factor for slag
-------
TABLE A- 21. ENVIRONMENTAL DATA FOR MODULE
Module - Crude Oil Gasification
Unit - 106 litu (output)
Environmental Parameters
Fuel Input,
Crude Oil
NOX, Ib
SO,, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, 10" Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Beat, 106 Btu
Acid (lSO), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings', Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/10^ Dtu
Approx. Module; Efficiency
-,«
0.03-0. 05(2)
Negligible
0.002(3)
0.3(5)
0.02(6)
Negligible
Negligible after cooling tower
0.06-0.12('7)
0.06-0.12(8>
1.3-2.5(9)
Not determined
Not determined
Not determined
0.03-0.05
777.01)
(10)
108
-------
Footnotes for Table A-21:
(1) a. Plant efficiency of crude oil SNC plant (assumed) = 77%
b. 23% of input is consumed as liquid fuel for plant operation
(assumed).
c. N0y emission factor^A~l) = AO lb/103 gal.
d. Heating value of input crude = 6.3 x 106'Btu/barrel (assumed).
(2) a. Sulfur content of crude oil (assumed) = 2 to 4%.
b. Sulfur removal efficiency of Glaus plant and tail gas
treatment (assumed) = 99%.
c. Density of crude oil - 7.3 Ib/gal.
(3) a\ ?A-nCUlate emis*ion factor for fluid catalytic cracking
uni^A l> = 61 lb/103 bbl fresh feed.
«'i/^raCti0tl °f frCSh feed t0 be cracked in Lhis Process (assumed)
I/ 3»
c. Particulate removal efficiency of cyclone (assumed) = 50%.
(4) a. Losses of crude oil to atmosphere (assumed) = 20 lb/103 bbl
input.
(5) a. 23% of input fuel is consumed for plant operation (assumed) .
(6) a. Salt content of crude oil (assumed) = 100 lb/103 bbl.
catalyst °ot "orth rcclaiml"E
(8) a. Sludges from water treatment -(assumed) = 300 to 600 lb/103 bbl.
(9) a. By-product is sulfur. Quantity derived from assumed sulfur
content of input crude (2 to 4%) and 99% recovery in Claus unit
and tail-gas treatment.
(10) a. Land required for a 100,000 bbl/day plant (assumed) =
600 to 1000 acres.
(11) a. Efficiency of plant (assumed) = 77%.
109
-------
TABLE A- 22. ENVIRONMENT DATA FOR MODULE
Module - Fluid-Bed Combustion Plus Combined Cycle
Unit - 106 Btu (input to combustion cycle)
Environmental Parameters
Fuel Input, Coal, East
Air
NOX> Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10» BCU
0.14 CD
0.7U)
0
0.02(3)
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (112804), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use. acrc-hr/106 Btu
Approx . Module Efficiency
0
0
0
Negligible after cooling tower
0
(5)
(6)
17.3
0
0
0
1.9
1.5 x 1
3.6 x 10-8(8)
1.4 x 10-5(9)
0.12(10)
38%(H)
no
-------
Footnotes for Table A-22:
(1) a. Average value of 0.07 and 0.22 lb/106 Btu reported in
Westinghouse Report.(A-23)
(2) a. SO-j emission factor reported^"23) = 1 lb/106 Btu.
b. Adjustment factor for sulfur content^"23' =0.7 (i.e.,3-—).
*f • «J
(3) a. Particulatc emission factor reported(A~23) = 0.02 lb/10^ Btu.
(A) a. Efficiency of the module (assumed) = 38%.
(5) a. Ash content of eastern coal (assumed) = 14.4%.
b. Heating value of coal (assumed) = 24 x 106 Btu/ton.
c. Limestone requirement per pound of sulfur = 1.75 Ib.
(6) a. The sole by-product is elemental sulfur.
b. Sulfur content of coal (assumed) = 3%.
c. 90% of sulfur is collected by limestone (assumed).
d. Sulfur loss from Claus unit(A"23) = 0.35 lb/lQ6 Btu.
(7) a. Injuries calculated from fluid-bed combustion plant and gas-
fired power plant operations.
b. 40 men operate a 500 ton coal/hr capacity combustion plant
(assumed).
C. Using chemical industry data for gasification plant, injuries
per man hour(A"5) = 8.1 injuries/10^ man hours.
d. Death rate (assumed) = 5% of injuries.
e. Death attributed to a 100 MW gas-fired power plant(A~12) c
V.VJL ULTctLllb/^f -li
(8) a. Injuries attributed to a 1000 Ktf gas fired power plant^A~12^ =
0.6 injuries/year.
(9) a. Using chemical industry data for gasification plant, man-days
lost per man hour(A~^' = 528 days/10^ man hours.
b. Man days lost per death (assumed) = 6000 days/death.
c. Man days lost attributed to a 1000 MW gas fired power plantCA~
c 197 man-days/year.
(10) a. Land requirement for a 1000 MW coal fired power plant (assumed)
B 800 acres.
b. Additional land requirement for fluid-bed combustion unit
(assumed) = 150 acres.
(11) a. Efficiency(A"23) = 38%.
Ill
-------
TABLE A- 23. ENVIRONMENTAL DATA FOR MODULE
Module - CAFB Boiler (Residual Oil) -f Combined Cycle
Unit - 1C6 Btu (input)
Environmental Parameters
Fuel Input,
Residual Oil (Imported)
NO , Ib
SO,, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, 10» Btu
VJater
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10& Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-I?roducts
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/lO** Btu
Approx. Modulo Efficiency
.
0.45<2>
0.04
0.62(5)
0
0
0
Negligible after cooling tqwer
0
0
3.0(6)
0
0
0
2 x 10-9(8)
7 x 10-8(8)
1.7 x 10-5(9)
112
-------
Footnotes for Table A-23:
(1) a. Experimental data obtained by Westinghousc.
(2) a. S02 from boiler = 0.1 lb/106 Btu.
(3) a. Electrostatic precipitator is employed to control particulate
emission (assumed).
b. Particulate emission factor'A~23' = 0.01 lb/10 Btu.
(4) a. Hydrocarbon emission factor for burning CAFB gas (assumed) =
40 lb/106 ft3.
(5) a. Efficiency of the module (assumed) = 38%.
(6) a. Sulfur content of oil (assumed) = 3%.
b. Limestone requirement per pound of sulfur =1.75 Ib.
c. Heating value of oil (assumed) = 6.3 x 10° Btu/bbl.
(7) a. Sulfur content of oil (assumed) = 3%.
b. Sulfur emission = 0.225.
(8) a. Injury rate per man hour (assumed) = 10 injuries/10" man hours.
b. Death rate of injury = 3%.
c. 70 men operate a 1000 MW plant (assumed).
j. Ms-.. H.-ivc 1r.cr- nti-.- for.f\\ rnccumoH^ = ADDfi rls-j
rf - - i ••— -^-— _., .^
b. Man days lost per injury (assumed) = 95 days/injury.
(10) a. Land requirement for a 1000 MH oil-fired power plant (assumed)
•= 300 acres.
b. Additional land requirement for CAFB gas unit (assumed) =
150 acics.
(11) a. Assumed efficiency = 38%.
113
-------
TABLE A-24. ENVIRONMENTAL DATA FOR MODULE
Module - Gas Well
Unit - 106 Btu
Environmental Parameters _ Fuel Input, Natural Gas
NOX, Ib 0.23(1)
SO,, Ib 0
CO, Ib 0
Particulate, Ib 0
Total organic material, Ib O.l(2)
Heat, 10^ Btu 0
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib 0
Heat, 10^ Btu 0
Acid (1I2S04), Ib 0
Solid
Slag, Ib 0
Ash, Ib 0
Sludge, Ib 0
Tailings', Ib 0
Hazardous, Ib 0
By-Products 12.
Occupational Health
Deaths 2.2 x
Total Injuries 2.1 x 10"7(5)
Man Days Lost 3.5 x 10-5(6)
Land Use, acrc-hr/106 Btu 0.06<7>
Approx. Module Efficiency
114
-------
Footnotes for Table A-24:
(1) a. Natural gas consumed to maintain pumping power in gas well'
• 0.032 ft3/ft3 recovered.
b. NOX emission factor^'1) = 7.3 x 10"3 lb/ft3 consumed.
c. Heating value of natural gas (assumed) = 1000 Btu/ft .
(2) a. Natural gas loss in gas well operation^"15) = 0.0022 ft3/ft3
recovered.
b. Density of natural gas = 0.045 lb/ft3.
(3) a. Hydrocarbon recovered (liquid phase) (A~J5) = 0.047 ft3 (equi-
valent gas volume) /ft3M'ecovered.
b. The hydrocarbon is assumed as heptane (Molecular weight = 96).
(4) a. Total number of fatal injuries in oil and gas production^"17 '
(A-19) = 95.
b. Total energy from oil and gas production^"^' A-18) _
43 x 1015 Btu.
(5) a. Total number of nonfatal injury in oil and gas production in
-17, A-19)
(6) a. Total man-days lost in oil and gas production in
(A-19) = 1<49 x 10b man.days.
(7) a. Land requirement for gas well is assumed to be the same as
that for oil well.
b. Land use for oil well (see Table A-36) = 0.06 acre-hour/10^
Btu.
(8) a. Efficient (assumed) = 96%.
115
-------
TABLE A-25 ENVIRONMENTAL DATA FOR MODULE
Module - Removal of Sulfur from Natural Gas
Unit - 106 Btu (output)
Environmental Paramcters
Fuel Input,
Natural Gas
NO , Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10" Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
.By-Products
Occupational Health
Deaths
Total Injuries
Han Days Lost
Land Use, acre-hr/10^ Btu
Approx. Module Efficiency
Nil
0.025^ ;
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
0
Nil
Nil
Nil
Nil
Nil
0.24<2>
Not determined
Not determined
Not determined
Not determined
0.005
100%'
(3)
116
-------
Footnotes for Table A-25:
(I) a. Table K-2 (Appendix K) gives the following 1970 data from
6 states:
S(>2 in Claus plants tail gas at 90% eff. = 441 T/D
S02 purged from plants not recovering sulfur = 2,335 T/D
Total gas production = 26.76 x 109 ;t3/d.
b. Assume 95% efficiency for Claus plants applied to all sour
gas treatment plants, then:
(441/0.1 + 2335) ton S0?/day x 05 x 2000 Ib/ton J.b SO
26.76 x ID1-1 ft^/day x 10-> Btu/ft-> " ' 5 10
2-
Btu
(2) a. at 95% efficiency for the Claus plants, the amount of S02
converted to sulfur is 19 times the amount of S02 emitted.
Therefore, the amount of by-product sulfur produced is:
.025 Ib S02 emitted x 19 x
SO2
(3) a. Land requirement for a 100 million ft^/day plant (assumed)
= 20 acres.
(4) a. Energy requirements for desulfurization process were not
determined.
117
-------
TABLE A- 26. ENVIRONMENTAL DATA FOR MODULE
Module -- Gas Pipeline
Unit - - 106 Btu
Environmental Parameters
Fuel Input,
Natural Gas
Ms.
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10& Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
land Use, acrc-hr/lO^ Btu
Appro;:. Module Efficiency
0.304
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
(1)
Not determined
Not determined
Not determined
1.0
(2)
95.97.
(3)
118
-------
Footnotes for Table A-26:
(1) a. Natural gas consumed fo maintain a compressor at 750 psia'A~15*
c 0.042 ft /ftj transmitted.
b. NOX emission factor for running gss engines' ' = 7300 lb/106
burned.
o?nd requirement for pipelines to run a 1000 MW Power Plant
2; = 213 acres.
(3) a. Efficiency (assumed) = 95.9%.
119
-------
TABLE A- 27. ENVIRONMENTAL DATA FOR MODULE
Module - " Underground Gas Storage
Unit - - Output 106 Btu
Environmental Parameters
Fuel Input,
Natural Gas
Air
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Sol id
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occ-upational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/lO^ Btu
Approx. Module Efficiency
0.06
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
(1)
Not determined
Not determined
Not determined
100%
(2)
120
-------
Footnotes for Table A-27:
(1) a. Natural gas burned to compress 1 scf of natural gas from 550
psl to 1800 psi with 257. efficiency = 0.014 ft3.
b. NOv emission factor for running gas engines'A~*5) = 4300 lb/
106 ft3.
(2) a. Efficiency of storage operation (assumed) = 100%.
121
-------
TABLE A-28. ENVIRONMENTAL DATA FOR MODULE
Module -- Conventional Boiler
Unit -- 10b Btu (input)
Environmental Parameters
Fuel Input,
Natural Gas
Air
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10& Btu
Acid (H2SO/i), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, ncrc-hr/106 Eta
Approx. Modulo Efficiency
0.39<>>
O.OOOGpJ
0.000;
0.04(5
0.63(6>
0.016<7>
0
0
Negligible after cooling tower
0
0
0
0
0
0
1.5 x 10"J .
8.9 x 10-9<«
2.9 x 10-6(10)
0.02
37%(12>
122
-------
Footnotes for Table A-28:
(?) a. NOX emission factor^"1* = 39 lb/106 ft3 of natural gas.
b. Heating value of natural gas (assumed) = 1000 Btu/ft .
(2) a. S02 emission factor for burning natural gas =0.6 lb/10^
ft3.
(3) a. CO emission factor for burning natural gas = 0.4 Ib/lO^
ft3.
(4) a. Particulate emission factor for burning natural gas = 15 lb/
106 ft3.
(5) a. Hydrocarbon emission factor for burning natural gas = 40 lb/
106 ft3.
(6) a. Efficiency of gas fired conventional boiler • 37%.
(7) a. Suspended solid emission from a 1000 MW gas fired Power Plant
(A-12) = 548 tons.
(8) a. Deaths attributed to a 1000 MW gas fired Power Plant*A~12'
» 0.01 death/year.
(9) a. Injuries attributed to a 1000 MW gas fired Power Plant^ '
c 0.6 injuries/year.
(10) a. Kan-days lost attributed to a -1000 MW gas fired Power
~12}
= 197 man-days/year.
(11) a. Land requirement for a 1000 MW gas fired Power Plant' ~ '
e 150 acres.
(12) a. Efficiency of gas fired Power Plant (assumed) = 37%.
123
-------
TABLE A-29 ENVIRONMENTAL DATA FOR MODULE
Module - LNG Tanker
Unit - 106 BLu
Environmental Parameters
Air
NOV, Ib
C-ft 1U
Negligible
n
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
it
ii
ii
Nil
Nil-
Nil
Not applicable
0
Nil
Negligible
Nil
Nil
Nil
Nil
Usual maritime, fire asphyxiation
Not determined
Not determined
Not determined
None
124
-------
Footnote for Table A-29:
(I) a. Efficiency of LNG tanker (assumed) = 977. based on use of
boil-off gas as fuel at the rate of 0.3% of the cargo per day
for an average trip of 10 days. Supplemental use of fuel oil
as fuel is not included.
125
-------
TABLE A-30 ENVIRONMENTAL DATA FOR MODULE
Module - LNG Port Facilities
Unit - 10 Btu
(Exclusive of storage or gasification)
Fuel Input,
Environmental Parameters Natural Gas
NO , Ib 0
SO,, Ib 0
CO, Ib 0
Particulate, Ib 0
Total organic material, Ib 0
Heat, 10" Btu 0
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib 0
Heat, 106 Btu 0
Acid (H2S04>, Ib 0
Solid
Slag, Ib 0
Ash, Ib 0
Sludge, Ib 0
Tailings, Ib 0
Hazardous, Ib 0
By-Products 0
Occupational Health Fire, asphyxiation
Deaths Not determined
Total Injuries Not determined
Man Days Lost Not determined
Land Use, acre-hr/106 Btu Very small
(2)
Approx. Module Efficiency 100%
126
-------
Footnotes for Table A-30:
'!) Land use required by port facilities is small compared to
storage tanks and gasification facilities.
(2) Energy requirements and gas losses are minimal compared with
total throughput.
127
-------
TABLE A-31. ENVIRONMENTAL DATA FOR MODULE
Module - LNG Storage
Unit - 106 Btu
Environmental Parameters
Fuel Input,
Natural Gas
NOX, Ib
S02, Ib
co; ib
Particulate, Ib
Total organic material, Ib
Heat, 100
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid OI2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Modulo Efficiency
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Fire, asphyxiation
Not determined
Not determined
Not determined
0.002(1)
I007.(2)
128
-------
Footnotes for Table A-31:
(I) a. Approximately 200 million cubic feet of gas per day are
required to fuel a 1000 MW power plant. A medium-sized tanker
carries the equivalent of about 109 cubic feet of gas, or about
5 days supply. The equivalent liquid volume is 1.7 million
cubic feet. A 50-foot deep tank of this volume would have a
cross-sectional area of 0.78 acre.
b. The overall land requirement for the storage of LNG for a
1000 MW power plant is estimated to be 20 acres.
(2) a. Boil-off is compressed and added to the lines. The energy
required is minimal.
129
-------
TABLE A-32. ENVIRONMENTAL DATA FOR MODULE
Module - LNG Gasification
Unit - 106 Btu
Fuel Input,
Environmental Parameters Natural Gas
NO , Ib l.l x 10' 3
S02, Ib Nil
CO, Ib Nil
Particulatc, Ib Nil
Total organic material, Ib Nil
Heat, 10» Btu 0
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib 0
Heat, 106 Btu 0
Add (H2S04), Ib 0
Solid
Slag, Ib 0
Ash, Ib 0
Sludge, Ib 0
Tailings, Ib 0
Hazardous, Ib 0
By-Products 0
Occupational Health Fire, asphyxiation
Deaths Not determined
Total Injuries Not determined
Man Days Lost Not determined
Land Use, acrc-hr/106 Btu Ni
Approx. Module Efficiency 997. '
130
-------
Footnotes for Table A-32:
(1) a. Heat of vaporization of liquified natural gas (assumed)
= 220 Btu/lb
b. Density of natural gas (assumed) = 0.045 Ib/ft
c. Heating value of natural gas (assumed = 1COO Btu/ft
d. Efficiency of heating unit (assumed) = 907. ,. ..
e. NOX emission factor for natural gas burning^ ' = 100
Ib/106/ft3
(2) a. No additional land required for gasification.
(3) a. Heat requirement for vaporization (same gases as footnote 1)
•= 11000 Btu/106 Btu.
131
-------
TABLE A-33. ENVIRONMENTAL DATA FOR MODULE
Module - Oil Shale Extraction and Processing
Unit - 106 Btu (output)
Environmental Parameters
Surface
Underground
.Ail
NOX, Ib
SO,, Ib
CO, Ib
Participate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (1180), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Overburden, Ib
By-Products (Ammonia/Sulfur), Ib
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0.025-0.038(1)
0.15 -0.22 (2)
0.14
(3)
Negligible
0
370
(6)
180-1000
0.9/0.3(7)
0.025-0.038
0.15 -0.22
0.14
O.I
Negligible
0
370
Not determined
•0.9/0.3
Not determined Not determined
Not determined Not determined
132
-------
Footnotes for Table A-33:
(1) a. NOX emission from a 10" bbl/day capacity oil shale processing
unit(A-27) = 80 to 120 tons/day.
b. Heating value of oil (assumed) = 6.3 x 106 Btu/bbl.
(2) a. S02 emission from a 10" bbl/day capacity oil shale processing
unit(A-27) = 460 to 680 tons/day.
(3) a. Participate emission from a 10^ bbl/day capacity oil shale
operation(A-27) = 440 tons/day.
b. Assumes 98% primary dust capture efficiency.
(4) a. Volume of water discharged will be highly variable due to
variations in mine water produced. Assume a discharge of 10^
gal/day for a 10-* bbl/day capacity oil shale operation.
b. Average salinity of the effluent from oil shale processing
(assumed) = 740 mg/ liter.
(5) a. From Figure D-2, Appendix D, spent shale and dust production
from a 50,000 bbl/day capacity oil shale processing = 58,960 tons/
day.
(6) a. The ratio of overburden oil shale seam thickness and quality
Is expected to vary widely. The following ranges were assumed:
235 feet of overburden with 450 feet of shale, and 450 feet of
overburden with 150 feet of shale.
a 450 foot seam would yield approximately 900,000 bbl/acre and
a 150 foot seam would yield approximately 300,000 bbl/acre.
c. Assume overburden density = 100 Ib/ft .
(7) a. Ammonia production from a 50,000 bbl/day capacity oil shale
processing^'27) = 138 tons/day
b. Sulfur production from a 50,000 bbl/day capacity oil shale
= 43 tons/day.
133
-------
TABLE A-34. ENVIRONMENTAL DATA FOR MODULE
Module -- Oil/Gas Well, Onshore
Unit -- 1Q6 uti- (output)
Environmental Parameters
Fuel Input",
Crude Oil
NOX, Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H?SO^), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/10^ Btu
Approx. Module Efficiency
8-x 10-6m
6 x 10-5(2
3 x 10-8(3)
3 x 10'
4 x 10-
0
6.2
(6)
0.008(7)
0
0
0
0
0
0
0
.0(8)
2.2 x 10 ' }
2.1 x 10-7)^
3.5 x 10-5(10>
0.06
100%
(11)
134
-------
Footnotes for Table A- 34:
(1) a. Amount of oil that becomes air pollutants per barrel of oil
produced (assumed) = 2 x 10~5 barrels.
bn Heating value of oil (assumed) = 6.3 x 106 Btu/bbl.
c. NOX emission factor^"1) = 60 lb/103 gal.
d. Oil is assumed to be the same as industrial residual oil.
(2) a. S02 emission factor**"1' = 157S lb/103 gal.
b. Sulfur content of oil, S (assumed) = 2.88%.
(3) a. CO emission factor* ' = 0.2 lb/103 gal.
(4) a. Particulate emission factor* ' = 23 lb/103 gal.
(5) a.. Hydrocarbon emission factor* ' = 3 lb/103 gal.
(6) a. Dissolved solid emission comes from saltwater brine.
b. Total brine product ion CA~16) = 25 million bbls/day.
c. Total on shore oil production rate^A"17' = 3.3 x 109 bbls/year.
d. 4% of 'brine goes to streams (assumed).
e. There are 100 Ib of dissolved solids per barrel of oil (assumed)
(7) a. The brine is cleaned to remove all but 50 ppn oil (assumed).
(8) a. Total number of fatal injury in oil and gas production in
1969^A"l/» A'19> = 95.
(9) a. Total nunber of nonfatal injury in oil and gas production in
1969 = 9C22.
(10) a. Total man-days lost(A"17'A"19^ • 1.49 x 106 man-days.
f
(11) a. Land requirement for an oil well producing 6200 barrels of oil
per year (assumed) = 1/4 acres.
(12) a. Efficiency of operation (assumed) = 100%.
135
-------
TABLE A-35. ENVIRONMENTAL DATA FOR MODULE
Module -- Oil/Gas Well-Offshore
Unit ••- 10° Btu (output)
Fuel Input,
Environmental Parameters Crude Oil
NOX, Ib 8 x 10~6(1J
S02, Ib 6 >: 10-5 *
CO, Ib 3 x 10-8<3'
Particulate, Ib 3 x lQ-
Total organic material, Ib 4 x lO"
Heat, 100 Btu 0
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib 0.002^6'
Heat, 106 Btu 0
Acid (112804), Ib 0
Solid
Slag, Ib 0
Ash, Ib 0
Sludge, Ib 0
Tailings, Ib 0
Hazardous, Ib 0
By-Products 0
Occupational Health
Deaths 2.2 x lO'
Total Injuries 2.1 x lO'
Man Days Lost 3.5 x 10~
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
136
-------
Footnotes for Table A- 35:
(1) a. Amount of oil that becomes air pollutants per barrel of oil
produced (assumed) = 2 x 10 barrels.
b. Oil is assumed to be the same as industrial residual oil.
c. He&ting value of oil (assumed) = 6.3 x 10^ Btu/bbl.
d. NOX emission factor^'1) = 60 lb/103 gal of oil.
(2) a. Sulfur content of oil, S (assumed) = 2,887..
b. S02 emission factor^'1) = 157 S lb/103 gal burned.
(3) a. CO emission factor * ^ = 0.2 lb/103 gal burned.
(4) a. Particulate emission factor™"1' = 23 lb/103 burned.
(5) a. Hydrocarbon emission factor = 3 lb/10 burned.
(6) a. Amount of oil discharged to water per barrel of oil pro-
duced (assumed) = 4 x 10"-' barrels.
b. Density of crude oil (assumed) =7.3 lb/gal.
(7) a. Total number of fatal injury in oil and gas production in
1969(A-17,A-19) = 95
(A-17 A-18)
b. Total energy from oil and gas production ' =
43 x 1015 Btu.
(8) a. Total number of nonfatal injury in oil and gas production
in 1969(A-17.A-19> = 023
in 1969-.- = 9023.
(9) a. Total man-days lost in oil and gas production in 1969 " '
A-19) = 1.49 x 106 man-days.
(10) a. Land requirement for an oil well producing 6200 barrels of
oil per year (assumed) = 1/4 acres.
(11) a. Efficiency of operation (assumed) = 100%.
137
-------
TABLE A-36. ENVIRONMENTAL DATA FOR MODULE
Module - - Oil Tanker
Unit -- 106 Btu (Output)
Environmental Parameters
Fuel Input,
Crude Oil
Air,
NO , Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 30& Btu
• Acid (H2SO/,), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Rtu
Approx. Module Efficiency
9 x 1-5<5>
0.005
0-5
(6)
0
0
0.015
0
0
0
0
0
0
0
(7)
9 x 10 ,
138
-------
Footnotes for Table A-36:
(1) a. NOX emission by oil tanker to transport crude oil for a
1000 1IW Power Plant^'12-- = 51 tonS/year.
(2) a. S02 emission by oil tanker to transport crude oil for a
1000 MW Power Plant
-------
TABLE A-37. ENVIRONMENTAL DATA FOR MODULE
Module -• Oil Pipeline
Unit -- 106 Btu (output)
Environmental Parameters
Fuel Input,
Crude Oil
NOX> Ib
S02, Ib
co; ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10& Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
JBy-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acro-hr/106 Btu
Approx. Module Efficiency
0.009
0.016
2 x 1
^
U'
0.0003 (5)
0.009<6>
0
0
0
0
0
0
0
0
0
0
9 x 10 r^
8 x 10"8(8)
1.1 i 10-5<»
0.3
99.1
(10)
(11)
-------
Footnotes for Table A-37:
(1) a. Fraction of crude oil transported by pipeline^"20? =
77.4%. i \
b. Total crude oil transported in 1970* ' = 1.58 x 109
barrels.
c. Fraction of crude oil transported by diesel powered
c 16.3% of crude oil transported by pipeline.
d. Crude oil consumed to supply power for pumping^ '
1.45 x 108 gel/year.
e. NOX emission factor^"1) - 80 lb/103 gal burned.
f. Heating value of crude oil (assumed) = 6.3 x 106 Btu/bbl.
(2) a. S02 emission factor^'1) <= 142 lb/103 gal burned.
(3) a. . CO emission factor *A"1' = 0.2 lb/103 gal burned.
(4) a. Particulate emission factor^"1^ = 16 lb/103 gal burned.
(5) a. Hydrocarbon emission f actor ^A"1^ = 3 lb/103 gal burned.
'(6) a. Assumed efficiency of oil pipeline = 99.1%.
(7) a. Death rate in oil transportation by pipeline (assumed) =
0.08 deaths/10b man-hours.
b. Man-hours required to transport the amount of oil for running
a 1000 MW Power Plant (assumed) = 7 x 105 man-hours.
(8) a. Injury rate in oil transportation by pipeline (assumed) =
7.22 injuries/106 man-hours.
(9) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 125 days/injury.
. Land usage for pipeline^"12' = 65 acres/year.
b. Period of land use (assumed) = 35 years.
(11) a. Efficiency of pipeline operation (assumed) = 99.1%.
141
-------
TABLE A-38. ENVIRONMENTAL DATA FOR MODULE
Module -- Oil Barge
Unit -- IQ6 Btu (Output)
Environmental Parameter;
Fuel Input,
Residual Oil
NO , Ib
S02, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, IQ
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10^ Btu
Acid (IlSO/), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-lir/lO6 Btu
Approx. Module Efficiency
0.0013^
0.0014<2>
0.001l(3>
0.0018(A)
0.0008(5)
nil
nilm
0.015(7;
nil
nil
nil
nil
nil
nil
nil
nil
.10(8)
9 x 10 rcn
8 x 10-8(9)
1.5 x 10-5(10)
,(11)
99.67.
(12)
142
-------
Footnotes for Table A-38:
(1) a. Assume 20,000 tons per shipment. .
b. NOX emission factor for motor ship* ' = 1.4 Ib/mi.
c. Trip distance per shipment (assumed) = 325 miles.
\ m
(2) a. S02 emission factor for motor ship^"1^ - 1.5 Ib/mi for 0.5%
sulfur content for fuel.
(A-l)
(3) a. CO emission factor for motor ship* =1.2 Ib/mi.
(A-l)
(4) a. Particulate emission factor for motor ship = 2Ib/mi.
(A-l)
(5) a. Hydrocarbon emission factor for motor ship = 0.9 Ib/mi.
(6) a.. Total heat required per 10" Btu transported (assumed) =
3800 Btu.
(7) a. Total oil discharge in oil transport and in tank cleaning
operations^"12) = 0.277. of shipment.
(8) a. Death rate in oil transportation by barge^ (assume that
barge operation is similar to tanker operation) = 0.08 deaths/
10 man-hours.
b. Man-hour required to transport the amount of crude oil -to
operate a 1000 MW Power Plant^' = 7 x 10^ man-hours.
(9) a. Injury rate in oil transportation by barge* ' (assume that
barge operation is similar to tanker operation) =7.22 injuries/
10° man-hours.
(10) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 125 days/injury.
(11) a. Land requirement for port facilities not estimated.
(12) a. Energy consumption rate per 10^ Btu of crude oil transported
(assumed) = 3800 Btu.
143
-------
TABLE A-39. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Refinery, Domestic Crude
Unit - 10b Btu (output)
jSnvirorenontal Parameters
Fuel Input,
Domestic Crudc(0.76%
ALT.
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (112804), Ib
0.002(5)
0.025(6)
0.10(7)
0.004
(8)
'
0.001<10>
Negligible after cooling tower
'
Slag, Ib
Ash, Ib
Sludge (dry weight), Ib
Tailings, Ib
Hazardous, Ib
By-Products. Ib
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Modulo Efficiency
0
0
o.oo?(12>
0
0
1 3 x
ItJ X
9.6 x
2.3 x
o.oos(17)
90%(18)
144
-------
Footnotes for Table A- 39:
bbl crude oil
(3) a. Assume 0.75X S residual burned as refinery fuel
C » r« r lb/1°3 bbl «udc °11 Processed.
C. 93Z removal, no Claus plant tail gas treatment.
cracklng catalyst *••»««« c- Appendix « . » ib/103
ca"ioyne1se)racktn8 (see Appendix L> • iz ib/i°3 b
(6) a. Hydrocarbon emission (see Appendix L) - 140 lb/l(>3 bbl crude oil processed.
(6) a. Suspended solids emission (assuned) - 20 Ib/lO* bbl processed.
(9) «. Dissolved solids emission (assuoed) - 500 Ib/llP bbl processed.
(10) a. Total organic material emission (assumed) - 8 Ib/lo' bbl processed.
(11) a. Phenol enission (assumed) - 2 lb/103 bbl processed.
f!2\ A A**o«-tnA *l..j.. ,_. • . . ^* te\ •« *
• • b.- -De^it; ;r^^™»a?nw
-------
TABLE A-40. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Refinery, Imported Crude
Unic - 10 Btu
Fuel Input,
Environmental Parameters
Arabian Crude
(1.63% S)O)
Kuwait Crude
(2.5% S)<2)
Air
NOX, Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids;, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge (dry weight), Ib
Tailings, Ib
Hazardous, Ib
By-Products, Ib
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/lO^ Btu
Approx. Module Efficiency
0.023
0.15(5)
0.003(6) 0.003
0.002^) 0.002
0.025(8) 0.025
0.1(9) o.l
0.0040°) Oi004
0.09( ) 0.09
0.001(12) 0.001
Negligible after cooling tower
0.0004(13) 0.0004
0
0
o.oo?(14)
0
0
0.7105)
1.3 x i
9.6 x 10-
2.3 x 10-508)
0.008
9W<20)
(19)
0
0
0.007
0
0
1.17
05)
1.3 x 10"^
9.6 x 10"8
2,3 x ID'5
0.008
90%
146
-------
Footnotes for Table A- 40:
(1) a. Sulfur content of Arabian crude (assumed) » 1.63%.
(2) a. Sulfur content of Kuwait crude (assumed) - 2.5%.
(3) a. Refinery energy consumption (assume 0.75% rcsld)* " - 704,000 Btu/bbl crude oil
processed.
b. IIOX emission from combustion operations (see Appendix L) - 130 lb/103 bbl crude oil
processed.
c. Keating value of crude oil (assumed) » 6.3 x 106 Btu/bbl.
(4) a. S02 emission (see Figure L-3, Appendix L) « 742 lb/103 bbl crude oil processed.
b. 99% removal with Glaus plant tail-gas treatment.
(5) a. S02 emission (see Table L-3) • 950 lb/103 bbl crude oil processed.
b. 99Z removal with Claus plant tail-gas treatment.
(6) a. CO emission from catalytic cracking catalyst regenerator (assumed) *> IS lb/103 bbl crude
oil processed.
(7) a. Partlculate emission from catalytic cracking (assumed) - 12 lb/103 bbl crude oil
processed.
(8) a. Hydrocarbon emission (assumed) - 140 lb/103 bbl crude oil processed.
(9) a. Keac consumption rate(A~24) = 704,000 Btu/bbl crude oil processed.
b. Heating value of crude oil assumed to be 6.3 x 10*> Btu/bbl.
(10) a. Suspended solid emission (assumed) • 20 lb/103 bbl crude oil processed.
(11) a. Dissolved solids emission (assumed) » SOO lb/103 bbl crude oil processed.
(12) a. Total organic material emission (assumed) = 8 lb/103 bbl processed.
i ("i*-"- <=u) - 2 lu/lG- "uul piuioauu.
(14) a. Average sludge production rate(A~25) = o_o8 yd^/103 bbl processed.
b. Density of sludge (assumed) = 60 lb/ft3.
c. Solid content of sludge (assumed) • 30%.
(15) a. Assume an average 0.2% sulfur in the products (see Appendix L) .
b. Density of crude oil (assumed) - 7.3 Ib/gal.
(16) a. Deaths attributed to the operation of a refinery supplying fuel to a 1000 MW power
' plant (A- 12) = 0.09 deaths.
(17) a. Injuries attributed to the operation of a refinery supplying fuel to a 1000 MH power
plant (A- 12) t> 6.4 injuries.
(18) a. Total man- days lost attributed to the operation of a refinery supplying fuel to a 1000 HW
power plant (A" 12; = 1530 man-days.
(19) a. Minimum land requirement for refinery processing units (assumed) * 2 acres/1000 bbl/day.
(20) a. Heat loss for operation of a plant(A'24) „ 706,000 Btu/bbl crude oil processed.
147
-------
TABLE A- 41. ENVIRONMENTAL DATA FOR MODULE
Module - Topping Refinery, Kuwait Crude
Unit -
Btu
Environmental Parameters
Fuel Input,
Kuwait Crude (2.5%
HOX, lb
SO,, lb
CO, lb
Particulate, lb
Total organic material, lb
Heat, 10» Btu
Water
Suspended solid;;, lb
Dissolved solids, lb
Total organic material, lb
Heat, 106 Btu
Acid (H2S04), lb
Sol id
Slag, lb
Ash, lb
Sludge, lb
Tailings, lb
Hazardous, lb
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0.031
0.071
(2)
(3)
0.009
0.013(5)
0.08(6)
0.09(8)
Negligible after cooling tower
0.000l4(l°) '
0
0
1.21
(12)
1 3 x 10-9(13)
9*6 x 0-8(14)
9.6 x 10 „..
2.3 x 1
o.oos(16)
927.U?)
148
-------
Footnotes for Table A-41:
(1) a. Sulfur content of Kuwait crude (assumed) » 2.57.
(2) a. Refinery energy consumption (assume 0.75X S resid) = 500,000
Btu/bbl crude oil processed).
b. NOX emission from combustion operations (see Appendix L) «
170 lb/103 bbl crude oil processed.
C. Heating value of crude oil (assumed) = 6.3 x 10^ Btu/bbl.
(3) a. S02 emission from combustion (see Appendix L) = 580 lb/10^
bbl crude oil processed.
b. Assume 707. of sulfur in input crude is converted to H2S
during processing. Assume Claus plant tail-gas treatment to
99187. removal. Residual S02 emission = 25 lb/1000 bbl crude.
(4) a. Particulate emission from catalytic cracking catalysis re-
generation (sec Appendix L) = 49 lb/10 bbl crude oil processed.
(5) a. Hydrocarbon emission (see Appendix L) •> 84 lb/10 bbl
processed.
(6) a. Heat consumption rate, assumed 707. of conventional refinery)
• 500,000 Btu/bbl crude oil processed.
b. Heating value of crude oil (assumed) • 6.3 x 10° Btu/bbl
(7) a. Suspended solids emission (assumed) *> 20 lb/103 bbl processed.
(8) a. Dissolved solids emission (assumed) ° 500 lb/10-' bbl processed.
(9) a. Total organic material emission (assumed) = 8 lb/103 bbl
processed.
(10) a. Phenols emission (assumed) = 0.8 lb/10J bbl processed.
(11) a. Average sludge production rate(A'25) - 0.08 yd3/103 bbl
processed.
b. Density of sludge (assumed) = 60 lb/fc3.
C. Solid content of sludge (assumed) • 30%.
(12) a. Assume an average of 0.27. S in the products (see Appendix L).
b. Density of crude oil (assumed) = 7.3 Ib/gal.
(13) a. Deaths attributed to the operation of a refinery supplying
fuel to a 1000 MW power plant^'12* = 0.09 deaths.
(14) a. Injuries attributed to the operation of a refinery supplying
fuel to a 1000 MW power plant(A-12) = 6.4 injuries.
(15) a. Total man-days lost attributed to the operation of a refinery
supplying fuel to a 1000 MW power plant(A"") = 1530 man-days.
(16) a. Minimum land requirement for refinery processing units (assumed)
2 acres/103 bbl/day.
(17) a. Energy requirement for operation of a plant assumed to be 70X of
conventional refinery = 500,000 Btu/bbl processed.
149
-------
TABLE A-42. ENVIRONMENTAL DATA FOR MODULE
Module - - Conventional Boiler
Unit -- 10b Btu (input)
Environmental Parameters
Fuel Input,
Resid from Domestic Crude
ALE
NOX> Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10& Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-lir/106 Btu
Approx. Modulo Efficiency
(S = 1.7f>7.)U)
^2)
o
o
0
Negligible after cooling tower
0
0
0
0
0
0
1.5 x 10
o q „ io
8.9 x 10
2.9 x 10
-10
(7)
0.04
(10)
37%
(11)
150
-------
Footnotes for Table A-42:
(1) a. Sulfur content of resid from domestic crude, S, i* assumed to
be 1.75%.
(2) a. NOX emission factor^'1) = 105 lb/103 gal.
b. Heating value of rcsid (assumed). = 6.3 x 106 Btu/bbl.
(3) a. S02 emission factor**"1' = 157 S lb/103 gal.
(4) a. Particulate emission factor* ' = 8 lb/103 gal.
(5) a. Hydrocarbon emission factor* ' = 2 lb/103 gal.
(6) a. Efficiency of oil fired Power Plant (assumed) = 37%.
(7) a. Deaths attributed to a 1000 MW Power Plant*A~12' = 0.01 death.
(8) a. Injuries attributed to a 1000 MW Power Plant* ' = 0.6
injuries.
(9) a. Man-days lost per death (assumed) = 6000 days/injury.
b. Man-days lost per injury (assumed) = 230 days/injury.
(10) a. Land requirement for a 1000 MW oil fired Power Plant^ ' =
300 acres.
151
-------
TABLE A-43. ENVIRONi-ENTAL DATA FOR MODULE
Module - - Conventional Boiler
Unit - - 106 Btu (input)
Fuel Input,
Resid from Topping Refinery
Air
NOX> Ib
sn~_ ih
(S
0.
0.
= 0.70%)(1)
70<2>
73(3)
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, 10? Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2SOi), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
fry-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0
0
0
Negligible after cooling tower
0
0
0
0
0
0
1.5 x 10
8.9 x 10
2.9 x 10
-10(7)
-9(8)
-6(9)
0.04
(10)
377.
-------
Footnotes for Table A-43:
(1) a. Sulfur content of resid from topping refinery, S, is assumed
as 0.7%.
(2) a. NOX emission factorA"1^ = 105 lb/103 gal.
b. Heating value of resid (assumed) = 6.3 x 10 Btu/bbl.
(3) a. S02 emission factor(A~^ = 157 S lb/103 gal.
(4) a. Particulate emission factor^"1' = 8 lb/103 gal.
(5) a. Hydrocarbon emission factor^"1' = 2 lb/103 gal.
(6) a. Efficiency of oil fired Power Plant (assumed) = 37%.
(7) a. Death attributed to a 1000 MW Power Plant^A~12' = 0.01 death.
(8) a. Injuries attributed to a 1000 MW Power Plant'A~12' =0.6
injuries.
(9) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 230 days/injury.
(10) a. Land requirement for a 1000 MW oil fired Power Plant^
« 300 acres.
(11) a. Efficiency of oil fired Power Plant (assumed) = 37%.
153
-------
TABLE A- 44. ENVIRONMENTAL DATA FOR MODULE
Module - Municipal Refuse Processing (St. Louis Method)
Unit - IQ6 Btu (output)
Environmental Parameters
KOX, Ib
SO,, Ib
CO, Ib
Particulatc, Ib
Total organic material, Ib
Heat, 10& Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04)» Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
land Use, ncrc-hr/lO^ Btu
Approx. Module Efficiency
0
0
0
ND
ND
ND
0
0
0
0
0
0
0
0
0
0
21.4 Ib steel/106 Btu(1)
ND
ND
ND
100
ND = Not determined.
154
-------
Footnotes for Table A-44:
(1) Assume "as received" refuse has an average heating value of 3500
Btu/lb and contains 7.5% metal recoverable by magnetic separation.
• *
(2) Assume 10 acres are required for a 1000 T/day refuse processing plant
155
-------
TABLE A-45. ENVIRONMENTAL DATA FOR MODULE
Module - Municipal Refuse Burning Conv. Boiler,
"°?uic Limestone Scrubber
Unit - 106 Btu (input to boiler)
Environmental Parameters
Fuel Input
jreparcd Municipal RcfuseO)
.Mr
NOX, Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10& Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.066(3)
ND
0.65^)
Negligible
Negligible
Negligible
Negligible after cooling tower
0
.
28.6
-------
Footnotes for Table A-45:
(1) Assume the as-received refuse has the following composition: 0.23%
sulfur, 3500,Btu/lb.(A-30) Assume that 7.5%
of the refuse is removed by magnetic separation. Processed refuse
composition would then be: 0.25% S, 20% ash, and 3785 Btu/lb.
(2) Assume equal to value for coal-fired power plant.
(3) a. Assume 50% of input sulfur appears in flue gas^"^
b. Assume 90% scrubber efficiency.
(4) a. Assume 50% of ash content appears in flue gas particulate.
(Lower than for coal due to presence of noncombuscibles).
b. Assume 99% particulate collection efficiency.
(5) Boiler efficiency (assumed) = 35%, balance to waste heat.
(6) Assume 50% of input ash remains as bottom ash.
(7) a. Sludge from S02 removal plus fly ash collected.
b. Sulfur'content of sludge (assumed) - 12%.
c. Fly ash collected by scrubber = .99 x 50% of input ash.
(8) Credit quantity of original refuse processed and burned rather than
landfilled = 1 lb/3500 Btu x 106 = 285 lb/106 Btu.
(9) Assume equal to coal-fired power plant.
157
-------
TABLE A- 46. ENVIRONMENTAL DATA FOR MODULE
Module - Space Heating- '
Unit - 106 Btu Useful Energy Delivered
Fuel Input,
Environmental Parameters Electricity Nr.tural Gas Oil
MX.
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10& Btu
Acid (112804), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
ND
0.115
0.001
0.022
0.007
0.006
0.43
0
0
0
0
0
0
0
0
0
0
ND
0.193
0.043
0.024
0.006
0.43
0
0
0
0
0
0
0
0
0
0
ND
Coal
0.233
) 4.42(3)
6.98
1.55
1.55
1.0
0
0
0
0
0'
ND
ND
0
0
0
ND
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/lO^ Btu
Approx. Module Efficiency
ND
1007.
ND
70%
ND
70%
ND
50%
ND = Not determined.
158
-------
Footnotes for Table A-46:
(1) Data taken from Table X-7, Appendix X, for Residential Case II.
All emissions calculated per million Btu of useful energy delivered.
(2) Assume 0.3% S in oil.
(3) Assume 1.5% S in coal.
(4) Non-useful energy lost as flue gas heat.
159
-------
TABLE A-47. ENVIRONMENTAL DATA FOR MODULE
Module - Nuclear Fission (overall system)
Unit - 10 Btu (input 'to power plant)
Environmental Parameter r.
NO lb 0.003(l)
S02' lb J
co? ib o.
Participate, lb
Total organic mat.eri.al, lb ""
Heat, 10» Btu 0.68
Water
Suspended solids, lb 0.022
Dissolved solids, lb
Total organic material, lb
Heat, 106 Btu Negligible after cooling tower
Acid '(112804), lb 9
Solid
Slag, Ib 0
Ash, lb 0
Sludge, lb O^j
Tailings, lb 4
Hazardous, lb Not estimated
By-Products °
Occupational Health
Deaths l-5 x L0~7
Total Injuries 0.9 x 10
Man Days Lost 1.3 x 10"
(b)
Land Use, acre-hr/106 Btu °'37
Approx. Module Efficiency 30% (overall)
160
-------
Footnotes for Table A-47:
(1) a. Equivalent pounds of NO , see Appendix B, for derivation of
conversion factor of 0.7 Ib/curie.
b. Table V-l, Appendix V, gives total annual radiological emis-
sions to air from the production of 50 gigawact-years of energy as
1.94 x 10^ curies/year. The efficiency of the reaction is about
32%. Hence, (1.94 x 107)/(50 x 106 x 3413/0.32 x 8760) = 4.15 x
10'9 Ci/Btu, or 4.15 x 10-3 Ci/106 Btu. This value times the con-
version factor, 0.7 Ib/Ci = 3 x 10" 3 equivalent pounds of NOX/106
Btu input to the power plant.
(2) a. Thermal efficiency of the power plant is assumed to be 32%.
(3) a. Equivalent pounds of D.O., see Appendix B for derivation of
conversion factor of 7 Ib/curie.
b. -Table V-2, Appendix V, gives total annual radiological emis-
sions water for nuclear power production as given in Footnote Ib
above as 2.7 x 10^ curies/year.
(4) a. Table V-3, Appendix V, gives 1.3 x 108 cubic yards of waste
rock produced annually from open pit and underground mining. All
other solid wastes are small in comparison. '
b. The surface mining operation is assumed to practice land recla-
mation. The ratio of solid waste produced by deep mining to that
produced from open pit is taken as 1 to 30, and the amount of
uranium mined by each method is roughly equal (see Appendix V).
Hence, 4.2 x 10° cubic yards of waste can be attributed to deep
n.«ninr> nf ii »• an •!••-> a ccf»r i sit-er! ui Hi tho 1 PUP 1 of nOWPT nroduction
••••.•»-«o— ——-—.. — — — — — >- — —.. . .
stated in footnote Ib above.
(5) a. Occupational health estimates associated with a 1000 Mtf nuclear
plant (8.7 x 1013 Btu input) are: fatalities = 0.135, injuries =
7.26, and man-days lost = 1125.(A'12)
(6) a. The value represents the summation of the following estimates:
mining and milling 0.01, processing 0.06, transportation 0.2, and
power plant 0.1.
(7) a. Hilling losses are estimated at 5%. Power generation effici-
ency is estimated at 32%. Net overall efficiency = 30%.
161
-------
References
A-l. "Compilation of Air Pollutant Emission Factors", U.S. Environ-
mental Protection Agency, Office of Air Programs, Research Triangle
Park, North Carolina, February, 1972.
A-2. Anon, Coal Age, 77(10), 122-138, 1972.
A-3. Leonard, J. W., and D. R. Mitchell, editors, "Coal Preparation",
3rd edition, AIME, New York, 1968.
A-4. Barthauer, G. L., A IMF. Environmental Quality Conference,
Washington, D.C., June 7-9.
A-5. U.S. Department of Labor, Bureau of Labor Statistics, Handbook
of Labor Statistics 1971, Bulletin 1705.
A-6. Process Research Inc., "Evaluation of Fuel Treatment and Con-
version Processes", report prepared for the EPA, Contract No.
68-02-0242, and CPA-70-1, July 7, 1972.
A-7. Battelle Memorial Institute, "Task Report on EPA Energy Quality
Model Exercise for 1975, Series B, Supplement V", report prepared
for EPA, Office of Air Programs, 1972.
A-8. "Coal-Bituminous and Lignite", Bureau of Mines Minerals Yearbooks,
U.S. Department of Interior, 1970.
A-9. Ephraim, M., "Status Report on Locomotives as Sources of Air Pol-
lution", International Conference on Transportation and Environ-
ment, Washington, D.C., May, 1972.
A-10. Battelle Memorial Institute, "A Study of the Environmental Impact
of Projected Increases in Intercity Freight Traffic", a report
prepared for Association of American Railroads, August, 1971.
A-ll. Hare, C. T., and Sprinler, "Exhaust Emissions from Uncontrolled
Vehicles and Related Equipment Using Internal Combustion Engines",
Southwest Research Report to EPA, October, 1972.
A-12. Environmental Quality. Third Annual Report of the Council on
Environmental Quality. August, 1972.
A-13. "Handbook of Labor Statistics", U.S. Department of Labor,
Bureau of Statistics, 1971.
A-14. Department of the Interior, "Environmental Effects of Underground
Mining and Mineral Processing", an unpublished report.
162
-------
A-15. Private communication, R. B. Foster, Manager, Industrial Planning
Institute of Gas Technology, Chicago, Illinois.
«
A-16. The Interstate Oil Compact Commission (IOCC) Study.
A-17. "Statistical Abstract of the United States", U.S. Department of
Commerce (1971).
A-18. "U.S. Energy Outlook. An Initial Appraisal 1971-1985", an.interim
report of the National Petroleum Council, Vol. 1, July (1971).
A-19. "Handbook of Labor Statistics", U.S. Department of Labor (1971).
A-20. "Crude Petroleum and Petroleum Products", Bureau of Mines
Minerals Yearbook, U.S. Department of the Interior (1970).
A-21. "Crude Oil Pipelines", Pipe Line News, Oildam Publishing Co.,
1971-1972 edition.
A-22. Marks, L. S., editor, "Mechanical Engineers' Handbook".
A-23. "Evaluation of the Fluidized Bed Combustion Boiler", Final Report
prepared by Westinghouse, Contract No. CPA 70-9.
A-24. American Petroleum Institute, "Petroleum Facts and Figures",
1971 edition.
A-25. Private communication with industry.
A-26. Process Research Inc., "Sulfur Dioxide from Natural Gas Fields",
Task Order No. 30, Contract No. CPA 70-1, prepared for Office of
Air Program, EPA, July 21, 1972.
A-27. Draft Environmental Statement for the Proposed Prototype Oil
Shale Leasing Program (3 volumes), U. S. Department of the
Interior, September, 1972.
A-28. "Water Pollution Potential of Spent Oil Shale Residues", Colorado
State University for the Environmental Protection Agency, Grant
No. 14030 EDB, December, 1971.
A-29. "Technology for the Future to Control Industrial and Urban Wastes",
Proceedings of Symposium, University of Missouri, Rolla, Continu-
ing Education Series, February 8-9, 1971.
A-30. Keller, D. J., "Utilization of Solid Waste as Fuel", Draft for
inclusion in OR&M Technology Division's "Federal Energy Study",
November, 1972.
163
-------
A-31. Roberts, R. M., and Wilson, E. M., "System Evaluation of Refuse
as a Low Sulfur ruel", presented at the ASME Winter Annual
MeetJng, Washington, D. C., November 28-December 2, 1971.
164
-------
APPENDIX B
METHODOLOGY FOR PINKING OF ENERGY SYSTEMS
Table of Contents
Approach 166
Derivation of Weighting Factors }67
Computer Program for Environmental Index Calculation 174
Sensitivity Analyses 175
References
List of Tables
B-l. Sensitivity of Ranking to Variations in Weighting
Factors 177
165
-------
APPENDIX B
METHODOLOGY FOR RANKING OF ENERGY SYSTEMS
Approach
The evaluation of alternative systems for the production of useful energy
and the modules contained within these systems required the comparison
of a variety of environmental burdens. These burdens can arise through
different steps in the process, and various components of the environ-
ment can be affected. Some system of ranking which attempts to collect
these complex burdens into a single number or set of numbers is desir-
able as part of the evaluation scheme. An attempt has been made during
this phase of the study to develop a method for the initial ranking of
energy systems.
In concept, the ranking system used is based upon methodology developed
for the Bureau of Reclamation, U.S. Department of the Interior.v8'!'
This concept involves a hierarchy of environmental burdens under four
major environmental categories. Each of these categories is divided
into environmental components, which in turn can be separated into
environmental parameters. An environmental parameter is a single
measurement or a series of measurements of the burden. If the environ-
mental burden for the system or activity under consideration is to be
derived properly, it is necessary to combine the environmental burdens
at each level of this hierarchy. Weighting factors are assigned as a
measure of the importance of a burden at any particular level of the
hierarchy and can be used to accommodate the different units used in the
measurement of the various burdens.
Due to the limited time for the present study, a complete hierarchy"of
environmental burdens was not developed. An attempt has been made to
develop a quantitative system utilizing five environmental components.
The components assumed to be of significance to the evaluation of energy
systems are
Air
Water
Solid Waste
Land Use
Radiation
Various parameters within each component were quantified as appropriate
to each module. The goal of the ranking procedure used was to derive
a single environmental index for the energy system under consideration.
166
-------
This index is represented as follows:
I. = F W EWLWQ,
i m m. n n p p p
I. = Environmental index for energy system i
W = Weight of module m in system i
W = Weight of environmental component n
W = Weight of parameter p
P
Q = Quantity of p produced per unit of energy.
P
A computer code was written to facilitate the calculation of the environ-
mental indices for the relatively large numbers of modules jind for the
combination of these modules into systems. The computer coJc also
permitted the performance of sensitivity calculations to Ruin an appre-
ciation of the dependence of the environmental index on uncertainties
in input data. The assignment of weighting factors, the development of
the computer code, and the sensitivity calculations are discussed in the
following sections.
Derivation of Weight ins Factors
Weighting Factors for Air Parameters
The air pollution index is based on the primary emission standards and
pollutant levels in terms of emissions in pounds per million Btu. The
following primary standard values were employed.
3
SO 80ug/m
NO n f .
x 3 I annual average value
Particulate 75 ug/m
3
CO 1000 u8/m annual avcrjp.c value
extrapolation from
10,000 mg/m'J/3 hr
3
Hydrocarbons 160ug/m 1 hr - used as annual
average value
Trace metals -
Be O.lp,g/nu
Hg 1.0ug/m-
Pb 2.0y,g/n»
Fine particles (< Ig,) and thermal emissions also should be included in
the consideration of air emissions. Standard values which rould be used
in the same manner as the values above were not identified for these
pollutants in this study, so these emissions wore not included in the
calculations of the environmental index. Their omission from the current
167
-------
assessment is not meant to minimize their importance, however.
The above values were referenced to the NO value. The resulting
weighting factors are:
Pollutant
NO
x
S°x
ISP
CO
HC
Trace metals
Be
Hg
Pb
Factor (W )
P_
1 (reference)
1.25
1.33
0.10
100 =
80
]QO >
75
100 •
1000
100 = 0.63
160
10*
ioz
50
Babcock's Factors (normalized)
514/514 - 1.00
514/1430 = 0.36
514/375 = 1.37
514/40,000 =0.01
514/19,300 = 0.03
Thus, the assumption is made that an increase of 1
-------
The weighting factors were derived by normalizing to the value of
dissolved oxygen.
Weighting Factors Tor Solid Waste
Many modules produce some solid waste. Consideration of the quantity of
this waste also can be assessed as part of the environmental impact.
The weighting factors were assigned on the basis of a gross scale of
importance based on the composition of the solid waste.
Importance Weightins Factor
Stable solid, leaching not important 1
Environmental pollution potential if
leached or eroded 2
Hazardous if leached or eroded 3
Directly hazardous (contact, proximity, etc.) 4
Land Use Parameters
The land use parameter includes the land area involved and a time factor.
For the processing and utilization modules the proper unit arises from
the fact that a certain land area is associated with a plant with a
stated throughput, say tons of coal per hour or the equivalent heating
value (Btu per hour). When the area in acres is divided by this energy
rate the resulting' linitt, U'L« cn-fK-iiuuf/iO'" Ecu. For che extraction
modules the area is associated with a total energy (e.g., tons of coal
per acre). The resulting value in acres/106 Btu is converted to con-
sistent units by multiplying the value fay the length of time assumed
for the operation.
Different weighting factors could be applied to reflect geographical
location, compatibility with surroundings, dedicated or temporary use,
and other related factors. However, weighting factors for land use
have been taken as unity for all calculations performed to date.
_WeifilitinR Factors for Radioactivity
A rigorous comparison of the environmental effects of material emissions
and radioactive emissions from energy generation is beyond the scope of
this present study. One of the major difficulties is the need to
consider both somatic and genetic effects for radioactivity against
only somatic effects of material emissions, l.'hilc lethal levels of
radioactive and nonradioactive pollutants arc reasonably well known,
the exposures to the public encountered in energy generation are well
below these lethal values. Dose-effects relationships down to the near
background or natural concentrations arc not known with certainty for
either type of pollutant and the comparability between the assumed relation-
ships of both types of pollutants is strictly hypothetical.
169
-------
Nevertheless, in this attempt to compare the environmental burden of a
number of energy systems, it was desirable to develop some appreciation
of magnitudes of the relative effects and to apply an internally
consistent set of weighting factors to the emissions. Several approaches
to derive a factor which would permit a comparison of nuclear and fossil
fuel systems based upon effects were examined, and a method to include
radioactive emissions under the air and water components was derived.
/p_g
Health Costs Data. According to the Council on Environmental Quality,
the total annual health costs due to air pollution is $6 billion. For a
population of 200 million, the cost is $30 per person per year.
Not all air pollution, however, is attributable to stationary sources.
A simple estimate of the fraction of air pollution from stationary
sources can be derived on a weight basis. The total, air emissions in
1970 are:(B'7)
Emissions, Millions of Tons Per Year
As Reported Normalized to NOX
Fuel Combustion Fuel Combustion
in Stationary in Stationary
Sources" Total Sources(a) Total
CO 0.8 147.2 0.08 14.7
Particles 6.8 25.4 8.9 33.8
SOX 26.5 33.9 33.1 42.4
riC 0.6 34.7 0.4 2i.S
NOX 10.0 22.7 10.0 22.7
44.7 263.9 52.48 135.4
(a) Although stationary sources include more than the energy gener-
ation systems under consideration, there is little to be gained
in this order-of-magnitude estimate of weighting factors to
further subdivide the emissions.
The weight fraction due to stationary sources is (44.7)7(263.9) = 0.17
if the as reported data arc used, and is (52.5)7(135.4) = 0.39 if the
data are normalized to the NOX values.
By applying the weight fraction data to the health costs, the annual
costs are $5 to $12 per person due to energy generation (stationary
sources). The electric utilities used 13,750 x 10i2 Btu of fossil fuel
in 1970.CB-O) Annual health costs per person for the burning of fossil
fuels to produce electricity are between $0.36 to $0.87 x 10~9 per 106 Btu.
Sagan has analyzed the risk to the U.S. population from all steps
of the nuclear fuel cycle-occupational exposures in uranium mining and
milling, manufacturing, reactor operation, and fuel reprocessing, and
exposure to the public near an operating reactor. His cost data are
170
-------
based upon the assumption that 1 rcm produces 100 cases of cancer per
million persons exposed and that the cost per human life is $300,000.
This places the risk-cost per rem per person at $30. The annual cost
from all activities is $0.011 per person.
For 10,030 megawatts of nuclear power produced by plants now operating
in the United States, the human costs for the entire U.S. population
of generating that electric power are derived to be about 0.026 mill per
kilowatt hour. This is equal to $1.1 x 10"^ per 10& Btu per person.
If health and human economic costs are used as the basis of comparison
of emissions from nuclear systems and fossil systems, then emissions
from the fossil fuel systems are about 100 to 300 times greater in
importance than emissions from nuclear systems.
Lethality Data. For accidental or occupational exposures to N02, death
within 3 to 5 weeks following exposure from broncheolites fibres is
obliterons results from concentrations in the range of 282 to 376 mg
per m3.(B-10) The primary ambient NOX standard is 100 microgram per
nr on an annual basis. If a breathing rate of 20 m3 per day is used,
the annual dose from an exposure to NC>2 at the allowed maximum ambient
level is 730 mg/yr. If a mid-range lethal exposure value of 327 mg
per mr is selected, then the ratio of an instantaneous lethal concen-
tration to allowable'ambient concentrations is about 0.4.
For acute exposure to radiation, a value of 300 to 600 Rads is considered
lethalJB~H) The maximum acceptable permissible dose to the general
population from manmade sources is 170 mrem on an annual basis. If a
tnid-raugu iei/uai dost; uL 430 rvaub is> bdluuLtu, Ihei'i Liie L'dLiu ol i'eLiidi
dose to allowable ambient doses is about 2600.
Thus, if the assumptions are made that the ambient or general population
exposure standards are set to limit health effects, that the effects
they arc set to limit are equally severe, and that dose and close-rate
relationships can be extrapolated to ambient levels with the same degree
of com-arability, then using this lethality approach, fossil-fuel
emissions are about 6500 times more important than emissions from nuclear
systems. The validity of these assumptions is not known.
Comparison of Nuclear and Oil-fired Power Plants. An analysis has been
performed by Starr, et al^-i^; to compare emissions from nuclear and oil-
fired power plants in the Los Angeles basin. The analysis was restricted
to the comparative public health aspects of oil-fired and nuclear power
plants and their associated activities in a typical urban setting.
Operation of these plants under conditions up to the present federal
regulatory limits was estimated to cause 60 times more respiratory
deaths due to fossil fuel pollution than cancer deaths due to nuclear
plant effluents. In normal practice, neither plant would be expected
to expose the public to these limits, primarily because the routine
effluents must be reduced below regulatory levels to meet a variety of
conditions, and would thus be expected to be substantially less (by a
factor of 10 or more) under average circumstances.
171
-------
In both cases the integrated accident risk (averaged over time and all
episodic events) is about 10"5 of the continuous exposure, for cither
the nuclear plant or the oil-fired plant. For the analyzed accident
with equal probability of occurrence, the oil-fired plant has a substan-
tially worse public health impact than the nuclear. For example, the
ono-in-a-million-ycars event for the oil-fired plant would lead to
approximately 700 respiratory deaths in a population center of 10 million
people; while the one-in-a-million-years event for the nuclear plant
would result in approximately one death in the same population.
Data from Los Angeles are not directly applicable to other regions of the
country. However, the analysis by Starr is useful in establishing the
relative significance of nuclear power and fossil fuel power emissions.
The factor of 60 which he derived is of the same order of magnitude as
the factor of 100 derived from health cost effect.
Derivation of Weighting Factor (W ) for Radioactivity. In order to
compare the emissions from nuclear power systems which are derived in units
of curies to the emissions from fossil fuel systems which are derived in
units of pounds, it was necessary to develop a conversion factor which
both converts the units to the same basis and rclaces comparable effects.
The previous discussion of health costs and lethality data gives an estimate
of the relative importance of exposure to fossil fuel emissions and to
radioactivity. It would appear that fossil fuel emissions are at least
100 times more important than nuclear emissions on an effect basis. In
light of the uncertainties in the analysis, and the limited consideration
of accidents in nuclear power systems, it has been assumed that emissions
fvr>™ fr>c-«-i1 fi,r>l cwc'-omc Jinr| pniicci'nn« frrvn niirlpar IVSfpnS have P.dUal
— "*••••—™ — — "-•-—•- —•"—/ — -—•••— * — *.__.. — _ ,, .
importance. For normal operations, this will tend to overstate the
importance of the environmental impact, of nuclear power.
Comparison of emissions from the two types of systems would require a
detailed analysis of each specific pollutant or radionuclide emitted.
For the purposes of this study, several approximations were made.
During reactor operations and fuel reprocessing it is assumed that the
air emissions are predominantly the noble gases. MFC values (10 CFR,
Part 20) for the noble gases are 3 x 10~7 yCi/ml and this value will be
taken as the standard for the air emissions calculations. Several
radionuclidcs can be present in the waste water, and MFC values (10 CFR,
Part 20) in water for some typical radionuclidcs are: 3H, 3 x 10~3 yCi/
ml; 137Cgj 2 x 10~5 yCi/ml; and 9°Sr, 3 x 10~7 uCi/ml. For purposes of
the water effluent calculations, a mid-range value of 3 x 10~^ uCi/ml
has been used for the "standard" MPC water value.
To reduce the-radioactivity to tha same units as the fossil fuel emis-
sions, the following relationships are applied.
172
-------
Air emissions.
/Radioactivity in
(Ambient \
standard]
NO /
,*».*.-j.v.1,., *"\ - n - X X '
equivalents / " ^r.air I /"Standard"\
\ MFC air /
where Qr = quantity of radioactivity in curies
x - Factors v/hich relates the importance of fossil
I fuel emissions to radioactivity in units of Ib/Ci.
For this analysis it is assumed to be 1.
Ambient - , -
standard, NO = 100//g/m = 0.23 x 10 Ib/m
"Standard" .
(UPC) air = 3 x 10 Ci/m
/Radioactivity in\ .. n _ ,.
lxTr> • i .. ) = Qr x 0.7. Ib.
\NO equivalents / '
Water effluents. To derive a similar factor for water, radioactivity has
been compared to trace metals. As noted earlier, the water quality
standard values, based primarily on drinking water standards, are in
the range of 0.1 to 0.3 ppm with the Hg-standard set at 0.5 ppb. For the
purpose of comparison, a water quality value of 0.1 ppm will be used.
/Radioactivity\ _ /Water quality
( in trace metal] trace I standard
e
\equivalents / ~ n x metals x \ trace metals
V I /"Standard"
-1 water r I w
\n
As in the case of air, trace metals/Ir is a factor which relates the
importance of trace metals to radioactivity. It is assumed to be 1 Ib
per curie for this analysis.
Water quality _, «
standard, = 0.1 ppm = 2.2 x 10~ Ibs/m
trace metals
= 3 x 105 Ci/m3
(MFC) water
Radioactivity in
trace metal = Qf x 7, Ib
equivalents
Since the water impacts are normalized in terms of dissolved oxygen, an
additional factor of 50 has been applied to the preceding expression.
Thus, to calculate the burden to the water from radioactivity, the
173
-------
radioactive effluents in curies is to bo multiplied by 3.5 x 10" 2 to
obtain a comparable unit.
Ecology. Weighting factors for ecological impacts to energy systems
have not been estimated for the current study. Concepts to be used,
however, could follow the general approach outlined in the study for
the Bureau of Reclamation. 0>-1) The ecological impacts are not in-
cluded in the current environmental index.
Human Factors. A combination of parameters is involved in the impact
of energy systems directly upon man's environment. Data to derive
quantitative weighting factor.', are often missing, and only a subjective
approach is possible at this time. For this report only the occupa-
tional health and safety sections have been considered. These have
been derived primarily of data from the Bureau of Labor Statistics.(B-13)
Weighting factors have not been -erived and the hunr-an factor impacts
are not included in the current environmental index.
Computer Program for Environrcental Index Calculation
The computer program for the calculation of the environmental index for
the energy systems evaluated encompasses seven steps.
1, Read in Data
The data read in consists of:
(a) Emission values for the components air. water, solid, and
land for each module
(b) The weighting factor for each emission value within the component
(c) Weighting factors for the relative importance of air, water,
solid, and land
(d) Weighting factors for module type, extraction, transportation,
processing, and utilization
(e) The modules comprising each system.
2. Calculate Weighted Component Totals for Each Module
This calculation is performed by multiplying the emission values within
each component by the appropriate weighting factor (read in 1-b). The
result is four numbers per module representing the sum of impacts for
each component—air, water, solid, and land.
3. Efficiency Correction
The weighted component totals for each module are divided by the product
of the efficiencies of all subsequent modules in the system. This
calculation is necessary since the module data are expressed on a basis
of a million Btu. The output, and thus the associated emissions, of, say,
an extraction module must be increased in proportion to the inefficiency
of the power plant.
174
-------
4. Calculate Normalizing Factors
The modules arc arranged into systems (according to data read in 1-e)
and the air, water, solid, and land totals are summed up. For the
number of systems chosen, this procedure results in a total of four sums
(air, water, solid, and land). The normalizing factor is then calculated
as the ratio of the air sum to each of these sums.
5. Calculate the Modulo Index
For each module in a system, the four normalized numbers (air, water,
solid, land) are weighted with respect to component weighting factors
(read in 1-c) and summed. Tlijs calculation results in a single impact
number for each module in a given system.
6. Calculate the System Index
For each system, consisting of several modules, the system index is
calculated by multiplying each module impact number by the module
weighting factor (read in 1-d). The sum of these results within a
given system gives the system index.
7. Rank the Systems
Finally, ranking of the systems is performed by ordering by system index.
Sensitivity Analyses
The procedures used in deriving an environmental index for various energy
systems incorporated a number of assumptions and in many cases estimates
have been made of the quantities of pollutants emitted in the modules. A
series of analyses were performed using the computer code previously
described to test the sensitivity of the ranking of the systems to
variations in the input and the assumptions that have been made. The
results of these sensitivity analyses give an indication of the validity
of the overall procedure and an appreciation of the reliability of the
final ranking.
The results of three sets of calculations are shown in Table B-l to
illustrate the changes in rank ordering of systems that occurs with
changes in weighting factors. The base case for comparison is the
ranking systems where all components and modules were equally weighted.
These rankings are compared to a case where the solid waste component
was weighted at 30 percent of the other component weighting factors,
i.e., burdens as a result of solid wastes are less important than
burdens in air, water, and land utilization components. In the third
case, all of the components were equally weighted, but the utilization
module was weighted 3 times as great as the other modules.
In general, the overall rankings remained similar, the systems that rank
high in the base case tend to rank high in the comparison case. Where
the importance of solid waste component is diminished, the system using
175
-------
Eastern coal and a limestone scrubber rank considerably higher than in the
base case. The large quantities of solid waste produced in this system
have relatively less influence on the ranking of this system. The
imported oil system moves high in the ranking when greater weight is
given to the utilization module. Its utilization module has a relatively
low burden compared with other systems. The changes in the order of the
systems are in the direction anticipated by the changes in weighting of
components or models.
The sensitivity analyses performed to date are not sufficient to determine
the significance of small differences in environmental indices. Until
additional analyses are performed and the results evaluated, care must
be taken in the interpretation of the ranking and the values assigned to
the environmental index.
176
-------
TABLE B-l. SENSITIVITY OF RAMCING TO VARIATIONS IN WEIGHTING FACTORS
All Components and Modules
Weighted Equally
VW1-00' ws
All Modules Weighted Equally
All Components Weighted Equally
Utilization Modules Weighted
3 Tines Greater than Others
LNG
Fluidized bed-oil
Gas
E coal-molten iron
W coal-conv boil
E coal-pres fluid bed
E coal-NgO scrubber
Import oil-topping-CB
E coal-PC-CB
E coal-PC-CB-HLSS
W coal-CB+LSS
On oil-pipc-ref-barge-CB
SRC-C3
CCC-C3
On oil-oil pipe-crude gas-gas pipe-gas CB
E coiil-Lurgi
E coal-C3+LSS
Off oil-oil pipe-ref-OT-CB
E coal-CB
On oil-oil pipe-ref-OT-CB
DI1CC-PC-CB
DNCC-PC-CB+LSS
DMEC-CB
LNC
Fluidizod bed-oil
E coal-molten iron
E coal-prcs fluid bed
N sas-GP-CB
W coal-:i»+LSS
E coal-C3+MgO
E coal-PC-CB+LSS
W coal-CU
E coal-:B+LSS
E coal-3KC-CB
E coal-?C-CS
Imp oil-topping-CB
E coal-;CC-CB
E coal-wurgi
On oil->ipe-ref-barge-CB
On oil-pipe-crude gas-pipe-CB
E coal-:B
DMEC-PC-CB+LSS
Off oit-pipe-ref-OT-CB
DMEC-PC-CB
On oil-oipc-ref-OT-CB
DMi-C-CB
LNG
Fluidized bed-oil
Inport oil-topping-CB
Gas
E coal-SRC-CB
E coal-noltcn iron
Off coi-pipe-ref-OT-CB
E coal-prcs fluid bed
E coal-PC-CB+LSS
On oil-pipc-ref-barge-CB
On oil-pipc-crude gas-pipe-gas CB
W coal-CB
E coal-PC-CB
E coal-MgO scrubber
CCC-CB
W coal-CB=LSS
E coal-CB+LSS
E coal-Lurgi
On oil-pipe-ref-OT-CB
DMEC-PC-CB
DMEC-PC-CB+LSS
E coal-CB
DMEC-CB
-------
References
B-l. "Environmental Evaluation System for Water Resources Planning",
report to Bureau of Reclamation, U.S. Department of the Interior,
by Battelle Columbus Laboratories (January, 1972).
B-2. Babcock, L. R. , Jr., "A Combined Pollution Index for Measurement
of Total Air Pollution", J Air Polln Cont Assn 20(10). 653 -
(October, 1970).
B-3. Brown, R. M., McClelland, N. I., and Deininger, R. A., and
Tozcr, R. G., "A Water Quality Index—Do We Dare?", Water and
Sewage Works JL7, 339-343 - (October, 1970).
B-4. Horton, Robert K. , "An Index-Number System for Rating Water Quality",
Water Pollution Control Federation Journal _3_7, 300-306 (March, 1965).
B-5. Wolman, M. G., "The Nation's Rivers", Science 174, 905-918 (November,
1971).
B-6. Environmental Quality. The Second Annual Report of the Council on
Environmental Quality. (August, 1971) p. 106.
B-7. Environmental Quality. The Third Annual Report of the Council on
Environmental Quality. (August, 1972) p. 6.
____ ........ . . T . •
n. ouiiuuai.y Licpuit. uj_ LUC IIGUJ.OII&J.
Council. Washington (December, 1972).
B-9. Sagan, L. A., "Human Costs of Nuclear Power", Science JT7, 587-93,
(August 11, 1972).
B-10. Air Quality Criteria for Nitrogen Oxides. AP-84.
B-ll. Background Material for the Development of Radiation Protection
Standards. Report No. 1, Federal Radiation Council (May 15, I960).
B-12. Starr, C. M., Greenfield, M. A., and Hausknecht, D. F. ,"A Comparison
of Public Health Risks: Nuclear vs Oil-fired Power Plants", Nuclear
News 15(10). 37-45 (October, 1972).
B-13. U.S. Department of Labor, Bureau of Labor Statistics, Handbook of
Labor Statistics 1971. Bulletin 1705.
178
-------
APPENDIX C
ENVIRONMENTAL EMISSIONS—OIL AND GAS EXPLORATION,
DRILLING, AND PRODUCTION
Table of Contents
Summary
Technology 180
EnvironmenLal Emissions -. . . 190
Pollution Controls 193
References 193
179
-------
APPENDIX C
ENVIRONMENTAL EMISSIONS—OIL AND GAS EXPLORATION.
DRILLING, AND PRODUCTION
Summary
The major sources of air pollution in the exploration, drilling, and
production of oil and gas arc blowouts and well-testing. The number
of blowouts during drilling on land from 1960 through 1970 has been re-
ported to be 100 out of 273,000 wells. Only three significant blowouts
have been reported during offshore operations since 1937. As a result
of these infrequent events, hydrocarbons are injected directly into the
atmosphere, and other combustion products of oil and gas can be emitted
if a fire occurs with a blowout. Blowout prevention appears to be the
most feasible means to reduce this type of environmental emission.
During well-testing, the gas or oil produced is burned, and the pro-
ducts of combustion are released to the environment. With adequate
pollution control devices on the burning equipment, the quantities of
these emissions can be small.
The emissions to the water environment occur through the discharge of
oil ?.nd s?!t"?tor b^in1??. Spills anH hlownnrs release oil. and some
additional oil is carried with the saltwater brines. Although the
quantity of saltwater produced is greater than the quantity of oil, pre-
sently all but about 4 percent of the saltwater is returned to under-
ground formations or otherwise disposed of in a satisfactory manner.
The total amount of oil discharged tc the air, water, and land environ-
ments from all sources during exploration, drilling, and production is
6 x 10~3 percent of the oil produced.
Environmental impacts to land are limited since the area required for
a drilling rig is small. The impact of oil and gas production on occu-
pational safety and health are: fatalities, 2.2 x 10"9 per 106 Btu's:
nonfatal injuries, 2.1 x 10'7 per 106 Btu's; and time lost, 3.5 x 10"5
man-days lost per 10^ Btu's.
Technology
General Description of Operation
A comprehensive description of the operations performed in the explora-
tion and production of oil and gas has recently been prepared by the
180
-------
National Petroleum Council.'^"*' This document and its supporting
references should be consulted for additional details on operations.
The scope of operations of interest in the determination of the environ-
mental emissions of oil and gas production include:
Offshore locations
Exploration
1. Geophysical surveying
2. Bottom sampling
Drilling
1. Drilling rigs
2. Blowouts
Completion
1. Formation evaluation and well-testing
2. Production casing setting
3. Perforation of the production casing
4. Suspension and abandonment
Production
1. Stimulation
2. Repair and recompletion
3. Sand -production
4. Accidents and disasters
Onshore Locations
Exploration
1. Survey
2. Core drilling
Drilling
1. Drilling operations
2. Waste handling and disposal
3. Blowouts
Completion
1. Formation evaluation and well-testing
2. Production casing setting
3. Setting the Christmas tree
4. Perforation of the production casing
5. Suspension and abandonment
Production
1. Stimulation
2. Repair and recompletion
3. Sand production
4. Accidents and disasters
There is a high degree of similarity between offshore and onshore
operations, and the two types are discussed together in the subsequent
sections of this appendix. Since there is expected to be a greater
increase in the amount of offshore operations between now and 19S5.
more emphasis is given in the discussion to offshore technology. Air
pollution considerations are basically the same for the two types of
operations, but water pollution problems from hydrocarbons are more
significant in offshore operations and land pollution problems are
181
-------
more important in onshore operations.
Exploration^0"1)
Gathering of geophysical and geological data for petroleum operations
in water-covered areas encompasses three categories of activities:
geophysical sampling to map various specific earth conditions, bottom
sampling to collect geological materials from the sea bottom, and core
drilling to sample bedrock below the sea bottom.
The specific earth conditions commonly surveyed by geophysical methods
to obtain data for the evaluation of the petroleum potential of an
offshore area are magnetic field, gravity field, seismic (acoustic)
sounding, and heat flow. Seawater chemistry measurements are also made
to determine the presence of hydrocarbons. Instrumentation to obtain
these types of data may be towed by a survey boat, lowered to the sea
floor from the boat, or utilized above the boat. Seismic measurements
are the only type of geophysical measurements that perturb the environ-
ment to any extent. The original acoustic source universally used was
dynamite, and fish kills occasionally resulted fro-n this technique.
But the trend is now toward the use of more sophisticated energy
sources such as encapsulated explosives (small charge), sparkers
(electric spark gap), exploding wire, compressed air guns, carbide
guns, gas (propane-oxygen) guns, and electro-mechanical and mechanical
transducers which should eliminate fish kills. In 1969. 35 percent of
all geophysical work was being done without explosives.'c"2)
Bottom samples are recovered from the sea floor by wire-line dredges,
grab samplers, or gravity corers. These are essentially surface sam-
ples of the sea bottom and do not penetrate bedrock. Benthic organisms
in the bottom sediments will be disturbed by these measurements, but
the resultant environmental impact should be negligible due to the
small areas that are sampled.
Core drilling operations are conducted by floating drill ships utiliz-
ing relatively small drilling equipment. Core drilling affords a possi-
ble source of pollution in the form of a blowout, and the danger in-
creases with depth of penetration. However, the probability of a blow-
out due to coring into an oil reservoir, which would be a pollution
source, is low. For example,
1. In the past 10 years, thousands of core holes have been drilled
by the petroleum industry (under USGS and Canadian government permits)
on the shelves and slopes of all of the U.S. and Canadian coasts, and
no pollution has been reported.(C-l)
2. JOIDES deep-water coring program drilled 236 core holes by December,
1970. Maximum depth of subocean penetration was 3,334 feet, and no
pollution was reported.
3. Improvements in core drilling techniques and blowout protection
can be expected.
182
-------
4. The number of blowouts during drilling (on land) from 1960 through
1970 has been reportcd(C-3) to be 106 out of 273,000 wells. Most blow-
outs are from high-pressure gas rather than oil.
Drilling
Offshore petroleum drilling operations are essentially the same as
those for onshore drilling except that the rig is supported by a struc-
ture that rests on the bottom of the sea or on a floating vessel rather
than on land. The type of offshore structure which supports the drill-
ing operation varies from platforms on piles, jack-up structure and
floating vessels to manmade islands. A self-contained platform con-
taining all of the necessary materials and equipment for drilling as
well as personnel housing is the accepted method for drilling in pro-
lific, proven areas.
Any spillage of fluids or waste disposal during drilling operations
provides a source of pollution. Pollution of offshore waters during
normal drilling operations is prevented by installation of drip pans
under the rig substructure for collection of mud and oil from the rig
floor area. These pans are drained at frequent intervals. The drill-
ing mud is water based and is not considered a pollutant.
On some offshore rigs the sump material is gathered and treated on the
platform to separate the oil products from water and noncontaminating
solids. These waste treatment units typically use chemical treatment
as a means of separating the hydrocarbons for further shore processing.
On drilling riot which do por havp thpsp facilities, the wastn oil pro-
ducts are hauled ashore to be disposed of or processed. Other trash
from the rig is put into metal containers and transported to shore for
disposal.
The greatest potential for pollution of offshore waters during drilling
operations is from a blowout. Once the hydrostatic head required to
control formation pressures is inadequate, feed-in from the formations
may commence. This loss of pressure may result from either drilling
into an unanticipated high-pressure formation or the loss of a hydro-
static balance because of a zone's accepting the drilling fluid.
Blowout-preventer assemblies and other protective equipment and tech-
niques are used to minimize the occurrence of the events. Blowout-
preventer assemblies are equipped with rams and closing mechanisms de-
signed to close around the drill pipe or around the casing or to plug
the open hole. Alarm devices are used to alert drilling crews to
potential blowout conditions. Hud system monitoring equipment is in-
stalled with derrick floor indicators while drilling operations are
taking place, and adjustments are made in the mud conditions to com-
pensate for the effects of pressure changes. The majority of blowouts
occur when pulling and running the- pipe. Use of recording pit-level
indicators has been helpful in determining that the hole is taking an
amount of mud equal to the pipe volume withdrawn. Industry experience
183
-------
has shown that this is an important item in blowout prevention.
Completion
Formation Evaluation and Well-Testing. The evaluation of offshore and
onshore wells to determine their commercial potential may he done in
several ways. The most accurate diagnostic method of evaluation is a
"drill stem test" which involves the transport of formation fluid to
the surface through pipe. This information, combined with an analysis
of bottomhole pressure, permits an estimate of the quantity of fluids
that the formation can produce as well as the type of fluid.
The fluids that are produced during a drill stem test are collected in
tanks at the surface. These fluids are recovered by flowing to the
surface, by being displaced from the well with drilling fluid, or by
collecting them in a chamber placed on the bottom of a drill pipe. The
oil, water, drilling mud, and gas are produced from the well and are
passed through a separator. The drilling mud is returned to the drill-
ing-fluid tank; the oil not used for laboratory analysis is placed in
a waste-oil tank; and the gas other than that collected for analysis is
burned by an appropriate flare arrangement.
The initial gas or oil produced from a well cannot be directed into
regular production facilities until the necessary tests are completed.
The testing time required, of course, varies with each well, but the
average for an oil well is two or three hours. For a gas well, the
average testing time ranges from two to four hours for a development
well and from one to seven days for an exploratory well, depending on
the area and the type of formation being tested. Also, the amount of
gas or oil initially produced and the rate of flow vary greatly for
different wells. Because of the short testing time required for de-
velopment wells, the initial production of gas or oil is relatively
small, but gas from an exploratory well can flow at a rate from a few
thousand cubic feet per day to millions of cubic feet per day.
Oil or gas produced during the well-testing programs is passed through
the required equipment, such as separators, tanks and vent lines, but
must be disposed of ultimately. Well-testing gas is usually burned,
emitting carbon dioxide and water vapor, and only small amounts of
other contaminants, into the atmosphere. The amount of oil produced
during well-testing is usually not a substantial quantity and may be
discharged into waste pits and burned, releasing products of the com-
bustion of hydrocarbons and some products of incomplete combustion.
This practice is becoming less prevalent and has been outlawed in
several states.
If formation evaluation and well-testing are done properly, there should
be no impact on the environment other than air emissions.
Setting the Production Casing. After testing is concluded and it has
been determined that the drilled well is to be completed as a producing
184
-------
or fluid-injection well, or that operations are to be suspended, the
final string of casing is placed in the well and sealed to the pene-
trated formation with cement. The environmental emissions of this
operation arc only those due to the preparation of the ccruont itself
and are not likely to be significant in the overall system.
After the production casing is set in place, the running tubing and
Christmas tree are installed. The Christmas tree or surface control
valve is normally installed at the surface, although underwater instal-
lations are being attempted. The casing is then perforated and the
flow from the well is established. If operations arc to be suspended
temporarily, or if the well is to be abandoned, the wellhead is capped
or plugged rather than being equipped with a Christmas tree. No en-
vironmental emissions are incurred during these oparations when properly
performed.
Production
The production phase of oil and gas operations covers a longer period
in the history of a producing field than the explorative, drilling,
and completion activities. Wastes or emissions to the environment can
result during routine production operations (waste water, saltwater
brines, sand), during stimulation efforts from acidizing, and from
accidents.
Waste Waters.(^-A) Waste water can be a source of oil pollution.
Waste water is that formation water which is produced from a reservoir
along with the oil and separated therefrom fay passing the production
through separation and treating facilities. Additional treating-facili-
ties remove the entrained oil from the separated water but arc not 100
percent efficient in removing the oil from the effluent water. The
efficiency in removing oil .depends on the physical characteristics of
a particular oil, the percentage of water in the crude stream, the
volumetric throughput and various other forces. After recognising
these characteristics, evaluating the state of the technology and
effects of content in produced waste water to an average of not more
than 50 parts per million or 0.005 percent (1/200 of 1 percent) prior
to disposal into the Gulf, Periodically, samples are taken and sub-
jected to laboratory analysis to insure that this average limit is not
exceeded.
There are about 1,893 structures in federal areas offshore Louisiana
producing approximately a total of 1 million barrels of oil per day,
but waste water is discharged from only about 214 of these structures.
Total waste water production is about 420,000 barrels per day; 240,000
barrels per day are transported to shore and 180,000 barrels per day
are discharged into the sea. The largest volume of waste water dis-
charged at a single location is about 20,000 barrels per day. The
decision to separate, treat, and discharge waste water on the platform
or pipe it to shore depends primarily on whether or not space exists
on the platform for separating facilities and if pipeline capacity is
185
-------
available. The oil content of waste water discharged in DCS operations
in the Gulf of Mexico, which averaged 40.8 ppm in March, 1972, will con-
tribute as much as 7.3 barrels of oil per day. During 1971, approxi-
mately 16 barrels of oil nitty have been introduced into the ocean daily,
cither from minor spills, or waste discharge.
Saltwater Rrines.' ' During production, large amounts of saltwater
are usually produced as oil fields age. Such water can create pollu-
tion problems from producing wells on land or freshwater-covered areas.
Its proper disposal has been and continues to be of major concern to
producing operators.
According to a study of the Interstate Oil Compact Commission (IOCC),
up to 25 million barrels of saltwater are produced daily from the
Nation's oil wells. This study shows further that 72 percent of the
water produced is being reinjected into the ground, either for secon-
dary recovery of oil or into nonproductive saltwater-bearing zones that
have no commercial value. Prior to returning saltwater obtained during
production to underground formations, geologic and engineering studies
are made to ensure that no damage is done to freshwater horizons.
Where proper natural conditions exist, this disposal method is desir-
able, both from commercial and ecological standpoints. Subsurface dis-
posal, whether for improved recovery or for disposal only, is strictly
regulated by state conservation agencies.
The IOCC study also indicates that 12 percent of the salt water ex-
tracted during production is put into nonpotable water bodies, approved
disposal sites, or is suitable for use in irrigation or for livestock.
Another 12 percent is poured into' nearby rivers. Disposal ot saltwater
into freshwater streams is not permitted, although it may be disposed of
in saline bays and estuaries and offshore.
Sand Production.(C-l) in some areas, the influx of formation sand into
the wellbore presents a major obstacle to production. All methods of
controlling sand influx require that all of the sand be cleaned from the
wellbore after the well "sands up" and goes off production. This sand
normally is oil saturated and must be cleaned or transported ashore to
avoid the danger of pollution of offshore waters.
Well Stimulation.( ' Acidizing, or pumping acid into a carbonate or
sand formation, and hydraulically fracturing a productive interval
account for more than 80 percent of all of the well-stimulation treat-
ments. Using the acidizing technique,"several hundred gallons of hydro-
chloric acid, organic acids or hydrofluoric acid ere pumped at a low
rate into the production formation. After treatment, the well is
placed back on production and the spent acid, which is neutralized by
salt water, is separated from the crude oil aid is disposed of in the
same manner as the saltwater produced from the well.
Blowouts.' ' Over 14,000 offshore wells have been drilled in the
period from 1937 to 1970 in the United States federal and state waters.
186
-------
Of these wells, approximately 9,000 have been drilled in the OCS with
more than one-half of them completed as productive for oil or gas.
During this period, 25 blowouts have been experienced. Th? three
serious blowouts are described here to indicate the scope of the en-
vironmental problems created by these events.
Santa Barabara Spill{c~5) On January 28, 1969, a blowout occurred be-
low Union Oil Company's fixed drilling Platform A in the Santa Barbara
Channel, about six miles southeast of Santa Barbara, California. This
blowout and spill occurred through a fissure in the ocean floor adja-
cent to the well after gas under high pressure from a deep reservoir was
accidentally injected into shallow reservoir sands. The resulting
buildup of pressure in the shallow reservoir sands soon exceeded the
strength of the overlying rock layer and caused a rupture to occur.
The rupture formed a fissure zone, thus opening an avenue of communica-
tion between the hydrocarbon reservoir and the seabottom. (C-6)
Total initial spillage was estimated by the Geological Survey to be
10,000 barrels, with subsequent leakage amounting to about 8500 barrels.
A number of factors relate to the final disposition of the spilled oil.
The report states that slow solubility and surface flotation of the
crude oil allowed rapid loss of volatile compounds which reduced poten-
tial toxicity of the oil. It should be pointed out that no chemical
analyses were included to support this statement. M. Blumer and associ-
ates (personal communication) had an opportunity to analyze oil that
arrived at Santa Barbara beaches and found that, in spite of exposure
at sea, gas chromatography showed the presence of benzenes, naphthalenes,
Letraliu&s , £uiu dip'uenyla. Tiius, Lin.- uil lidu Lu&ii LiLLLt u£ LLs> eieuuu,
and probably none of its long-term toxicity through exposure at sea.
Geological studies revealed that "much of the oil deposited at the
sediment-water interface was removed from the area of initial deposi-
tion and was retransported into deeper water". (C-5)
Elsewhere, the same author said that within four months after the acci-
•dent the entire Santa Barbara basin was covered with oil from the
spill. (C-7)
In summary, the study reiterates that damage to biota was not widespread
but limited to several species. The study hypothesizes that "the biota
of the area had a high tolerance to oil built up by almost continuous
exposure to small amounts of similar oil from natural seeps over long
periods. "(c~5) Further, "the presence of oil in the area may have re-
sulted in a normally high population of oil degrading bacteria". (c~5)
This hypothesis is supported by the work of marine microbiologist
»
The study was complicated by several factors. First, the area is noted
for natural oil seepage which made it difficult to obtain comparative
data in regard to "normal conditions in the area before or between
spills resulting from drilling activity. Second,- the largest recorded
flood in Southern California history occurred almost simultaneously with
187
-------
the spill resulting in a large runoff of freshwater and sediments into
the Santa Barbara Channel, creating reduced salinities, high sedimenta-
tion rales, and a probable increase in pesticide levels that washed in-
to the Channel from citrus groves. Third, there was an overall general
lack of knowledge of the ecology of the area. Fourth, in spite of
numerous statements concerning toxicity, solubility, aromatic content,
weathering, and oxidation of the spilled oils, results of chemical
analyses were not incorporated into the publication of the studies.
Chevron Fire and Oil Spill.(c~9) On February 10, 1970, Chevron Oil
Company's platform HP 41C, caught fire. Platform "C" is located in 40
feet of water about 75 miles southeast of New Orleans, Louisiana. On
March 10, 1970, the fire was extinguished, and oil that previously had
been consumed by the fire began escaping into the Gulf of Mexico.
Crude oil and gas continued to escape until the last of the wild wells
was brought under control on March 31, 1970. Reliable estimates placed
the total volume of oil spilled at about 30,000 barrels.
Oil from the spill was a light crude, containing a high proportion of
lower boiling constituents and a relatively low concentration (about
10 percent) of aromatic hydrocarbons. Through a fortunate set of cir-
cumstances, the oil was sprayed high into the air under great pressure
and frequently into considerable wind, so that far more evaporation
took place than is usually estimated to occur during a spill. Samples
collected 500 feet from the platform and analyzed by Federal Water
Quality Administration (FWQA) laboratories showed a loss in volume of
16 percent, all in the lighter ends. Also, about 5,000 barrels of oil
were removed by skimming. Some 1,500 barrels of chemical emulsificr
were used during the spill as well.
Almost no field observations or collections were made to determine eco-
logical damage that may have resulted from the spill. The FWQA, from
laboratory bioassays, reported that 72 hours with 13,300 parts per
million (ppm) of oil did not kill brackish water species of killifish.
The Louisiana State University, working with other Louisiana crudes and
white and brown shrimp, reported no mortality after 48 hours exposure
to 1,000 ppm oil, 50 percent mortality with 7,500 ppm, and 100 percent
with 15,000 ppm. However, emulsificr/oil combinations were roughly-
tenfold more toxic than oil alone when tested on shrimp.
The only other biological observations made were that samples from oil
slicks were found by Louisiana State University scientists to contain
large numbers of oil degrading yeasts, and that monitoring during the
spill by Louisiana Wildlife and Fisheries Commission showed no mor-
tality or oily taste in oysters east of the Mississippi River.
Thus, in concluding remarks, it was stated that there were no confirmed
reports to date of environmental damage that could have been directly
attributed to the Platform "C" oil spill. A number of fortunate circum-
stances serves to mitigate potential damage from this spill:
188
-------
1. Extreme rate of evaporation took place as mentioned above
2. Considerable dispersion and dilution took place because of the plat-
form distance offshore, wind and sea conditions, and use of emulsifiers
3. Direction of wind during the spill was predominately offshore, thus
blowing slick and emulsions further away from land, and
4. The saltwater/freshwater interface (riptide) caused by the overflow
of the Mississippi River, then at flood stage, appeared to provide a
very effective barrier and prevented oil from reaching the shores and
marshes of the lower delta.
The authors state that assessment of biological damage was complicated
in the area by the multitude of sources of oil and snail, but chronic
leakage. Numerous oil slicks from sources other than Platform "C" were
observed during the incident, and analysis of sediment samples revealed
widespread presence of oil. They hypothesize that, since the area has
been subject to chronic oil exposure for 20 years, it is possible that
the biota may already have been altered and the most oil-sensitive
species eliminated.
Shortcomings of this report are obvious: very little field sampling
was done; almost no chemical analysis of water, sediment, or biological
material was performed or reported; efforts to evaluate the environmen-
tal effects of the spill were generally limited to detecting the immedi-
ate impact on commercial fishery species. Ecologically significant
damage to biota could have occurred and remained undetected.
In public hearings held by the Department of the Interior in New Orleans
on September 8 and 9, 1971, concerning a proposed oil and gas lease
sale offshore Louisiana', Dr. John G. Mackin, marine biologist at Texas
A&M testified that his study revealed:
"One, the Chevron platforms 41-C fire liberated crude petroleum
in the shelf and Bretton Sounds areas to the northeast and
east of the Mississippi Delta. Two, so far as can be deter-
mined, none of this oil reached the shore or marsh. Three,
no effects of the spill can now be detected so far as the
biology communities are concerned. Four, no effect on the
fisheries was found. Five, the spill did not destroy birds
or wildlife as have some other widely publicised spills. As
a peculiar fact, destruction of birds has not been a feature
in any spill in Louisiana waters that I have any knowledge of."
Shell Oil Spill. On December 1, 1970, a blowout occurred on Shell Oil
Company's Platform B in Block 26, about seven miles offshore South
Timbalier Bay, Louisiana. About 53,000 barrels of crude oil were
spilled on waters near the 50-foot depth contour. With reservation, a
summary of the study^C~10^ on the fate and effects of this spill was
included in the Draft Statement. It was noted that sampling methods
189
-------
were questionable and that the results were somewhat inconclusive.
At the DCS Public Hearing of August 22 and 23, held in New Orleans,
Shell Oil Company presented written testimony including critiques of
the report'^-10) ^, t]iree scientists who are recognized authorities in
the areas covered.
These three critiques leave little doubt that the integrity of the fate
and effects study is questionable. Therefore, the summary of the study
which was presented in the Draft Statement has not been included in the
Final Statement. All material presented at the OCS Public Hearing is
available for inspection at the Bureau of Land Management, Washington,
D.C. office. Oppcnheimer^C-11) noted a "(s) light accumulation of oil
on beaches. No report on adverse environmental damage to biota have
been found", as a result of the Shell spill.
Environmental Emissions
Air
Sources of Emissions. The principal activities giving rise to air pol-
lution in the exploration, drilling, and production of oil and gas are
blowouts and well-testing. Blowouts will inject hydrocarbons directly
into the atmosphere and additional hydrocarbons are emitted by evapora-
tion of the oil that is dispersed on the water. The extent of the
c~.i33icr,3 wi] 1 Jcpcitd ^pcr. the chcniccl ccir.pcsitiop. of the crude oil
will increase as the fraction of light ends in the crude increases. If
a fire occurs in addition to the blowout, combustion products—CO, N0x>
S02, and particulatcs--will also be released to the air environment.
Over the ten-year period from 1962 to 1972, 1.9 billion barrels of oil
and condcnsate were produced from the OCS in the Gulf of Mexico.(c~^)
During this period, nine platform accidents involving drilling or pro-
ducing operations resulted in the spillage of 96,300 barrels of oil, or
5 x 10~3 percent of the amount produced. An additional amount of oil
is discharged to the environment in the waste water that is produced.
Current OCS regulations permit only an average discharge of 50 ppm of
oil in the waste water. In federal areas offshore Louisiana, approxi-
mately 1 million barrels of oil are produced per day along with 420,000
barrels of waste water. Only 180,000 barrels of treated water are dis-
charged to the sea. Oil discharged by this route is (50 x 10'6) (180,000)
- 9 barrels per day or about 1 x 10" ^ percent of the production.
During well-testing, the gas or oil produced is burned and the products
of combustion are released to the environment. With adequate pollution
control devices on the burning equipment, these emissions should be
very small.
An additional source of air pollution is the exhausts from the diesel-
190
-------
Fires(a)
1
19
0.1
0.01
2.5
Evaporation
.._
— -
38
—
—
Total
1
19
38.1
0.01
2.5
powered vessels used for seismic survey and drilling rig engines. These
emissions arc expected to be minor.
Estimate of Quantities of Emissions. For the purposes of this study, it
will be assumed that the sources oi' emissions during exploration, drill-
ing and production are the same for offshore and onshore operations.
It is further assumed that 25 percent of the oil that is discharged
through blowouts and spills is ignited and bums in a manner similar
to that in oil-fired burners. Of the remaining 75 percent, 20 percent
is assumed to be a volatile fraction that will evaporate into the air.
The total emissions from the oil discharges are:
Emissions, pounds per barrel of
oil discharged
FiresU;
Particulate
S02
HC
CO
NOX
(a) Burning assumed to be the same as residual oil
firing in industrial burners. Emission factors
from "Compilation of Air Pollutant Emission
Factors", (revised), U.S. Environmental Protection
Agency, Office of Air Programs. Research Triangle
Park, North Carolina, February, 1972.
Water
Sources of Effluents. In offshore operations, the major sources of
water pollution are the hydrocarbons released during blowouts and
spills, and hydrocarbons discharged with treated waste water. Human
waste treatment systems are now required, so that water pollutants
other than hydrocarbons are expected to be negligible.
There are several sources of water pollution in onshore operations.(c~12)
The construction of roads for access into prospective petroleum-produc-
ing areas could affect when drainage patterns are disturbed or when
erosion is possible. Canal dredging can avoid serious or permanent
water quality impacts, but can result in temporarily increased turbidity
and sediment suspension.
The major environmental emissions occur through the entry of oil, chemi-
cals, brine, and wnstc materials into the water cycle. Spills and leaks
allowing such substances to enter the surface or ground water systems
can result from human error and neglect, mechanical failures, burning
pits and open ditches, and from blowouts. During production, large
amounts of saltwater are produced daily from the nation's oil wells.
Subsurface disposal is strictly regulated by state water resource agen-
cies and disposal of saltwater is not permitted in freshwater streams.
191
-------
Estimates of Quantities of Effluents. Bnsed upon the discussion of air
pollution, it is estimated that 6 x 10~3 percent of the oil produced is
discharged to the environment. If the amount of discharged oil that is
released to Lhe air environment is subtracted from this total, about 4
x 10~3 percent of the oil produced appears as a water pollutant.
Saltwater brines were discussed in the Technology Section of this
appendix. From the data presented, it appears that up to 4 percent or
about 1 million barrels of the saltwater brines may be discharged
directly into the environment. Chloride concentrations range from 12
to 50 pounds per barrel and total dissolved solids are on the order of
100 pounds per barrel.
Land
Environmental impacts to the land from exploration, drilling, and pro-
duction arise through the use of land for the wells and rigs, and for
waste disposal pits for oil and brine. No estimate has been made in
this study of the amount of land that is being used for waste disposal.
About 1/4 acre is used for each oil well. If it is assumed that an oil
well produces about 6,200 barrels per year, then the land commitment
would be 0.05 acre-hour per 106 Btu. This average production value per
well is low for offshore operations and the land use per wall is higher
offshore, since the same offshore rig can service several wells. Hence,
the overall land cornitnenL for a unit energy output would be lower
for the offshore production.
Ocher Jmpacus — Occup-at-luiu:!
The work-injury rates for the exploration, drilling, and production of
oil and natural gas for 1969 (C-13) are 9.7 disabling injuries for each
million employee-hours worked and 983 clays of disability resulting
from the disabling work injuries for each million employee-hours
worked. There were 450,000 employees in tne petroleum and natural gas
industry in 1969 and a total of 939 million man-hours were worked. (C-14)
Within the industry there were 95 fatal injuries which represents a
fatality rate of 0.1 per million man-hours. There were 9,023 nonfatal
injuries in 1969 and a nonfatal injury rate of 9.61 per million man-
hours.
In 1969, the total production of crude oil was 3.3 billion barrels (C-14)
or a total of 20.8 x 10^ Btu's if it is assumed that each barrel of
crude oil is equivalent to 6.3 x 106 Btu's. The U.S. gas supply in 1970
amounted to 22.5 x 10^-5 Btu's. (C- 15) Combining the oil and gas esti-
mates, a total of about 43 x 1015 Btu's are produced annually by the
petroleum and gas industry. The impact of oil and gas production on
occupational safety and health are: fatalities, 95/43 x 109 = 2.2 x 10~9
per 106 Btu's; nonfatal injuries, 9,023/43 x 109 - 2.1 x 10"7 per 10°
Btu's; and time lost 1.49 x 106/43 x 10^ = 0.35 x 10~* man-days lost
per 10^ Btu's. (983 man-days lost per million man-hours x 939 million
man-hours + 95 fatalities x 6,000 days lost per fatality = 1.49 x 106
man- days lost.)
192
-------
Pollution Controls
Methods
Pollution control systerns(C-16) for gas ancj On exploration, drilling,
and production include the safety systems which control nonroutine re-
leases; water, soil, and gas treatment systems and operating practices
to control the routine pollutants; and sewage treatment systems to
control human wastes. The safety devices for offshore operations which
are required by DCS regulations include subsurface safety devices, high-
low pressure shut-in controls, high liquid level shut-in controls, pres-
sure relief valves, automatic fail-close valves at the wellhead, auto-
matic fire-fighting systems, automatic gas detector and alarm systems,
and other safety devices on production equipment; high-low pressure
sensing devices on pipelines; and blowout preventers, related well-con-
trol equipment, and tnud system monitoring equipment on drilling wells.
Since some of this equipment has been in use for a period of time less
than a year, it is not possible to assess quantitatively its effective-
ness in reducing pollution.
Burners are used to dispose of gas, oil, and emulsions and can be oper-
ated without smoke,(C-16) reducing particulate emissions. Waste water
treatment systems using filtration, skimmers, and centrifugal separa-
tors are available for the removal of brine, oil, and suspended solids.CC-17)
Drilling muds are neutralized before they are discharged into the ocean
from offshore operations. Drill cuttings and sand are processed to re-
move oil ^"^for0- r'isy sre <1iPnoscd of ^n |"t"a "'•^SJP, Fipctrnrafsivrir
units or sewage treatment plants are used on offshore platforms to con-
trol human wastes.
Costs
On an industry-wide basis, the offshore operators have estimated that
•pollution control and safety devices required to meet the OSC-8 guide-
lines will cost between $100,000,000 to $150,000,000.(C-18, C-19) Separ-
ation of environmental costs from safety costs cannot readily be made.
Brine disposal costs have been estimated to run about 2 percent of net
oil sales for onshore operations.(C-20)
References
C-l. Environmental Conservation.
C-2. Society of Exploration Geophysics, Geophysics 3^_ (6), December,
1969.
C-3. Oil and Gas Journal Annual Review, January 26, 1970.
193
-------
C-4. Final Environmental Statement. Proposed 1972. Outer Continental
She]f Oil and Gas General Lease Sale Offshore Louisiana, U.S.
Department of Interior, October 13, 1972.
C-5. Straughan, D., and Kolpack, R. L. (ed.), Biological and Oceano-
graphic Survey of the Santa Barbara Channel Oil Spill, 1969-1970.
Allan Hancock Foundation, University Southern California. Sea
Grant Pub. No. 2, 1971, 2 Vols.
C-6. Reinhart, p. U., Oil Seepage Potentialities of Dos Cuadras Oil
Field, Santa Barbara County, California. Santa Barbara Environ-
mental Quality Advisory Board, 1970, 31 pp.
C-7. Kolpack, R. L., FAO Meeting on Marine Pollution, Rome, December,
1970.
C-8. Zobell, C. E., Microbial Modification of Crude Oil in the Sea.
Proc. Joint Conference on Prevention and Control of Oil Spills,
1969, pp 317-326.
C-9. Department of Interior, Assistant Secretary for Fish, Wildlife,
and Parks, "Interim Evaluation of Environmental Impact from the
Chevron Company Fire and Oil Spill of Coastal Louisiana", Febru-
ary and March, 1970. Unpublished report, 1970, 38 pp.
C-10. Studies and Investigations of the Fate and Effects of the Shell
Oil Spill. Platform B, Block 26, South Timbalicr Bay, December,
1570. A rs~cvi. "reared by Resourc?? Tori'inin^y Corporation.
Houston, Texas, for the Environmental Protection Agency,
Washington, D. C, January, 1972.
C-ll. Testimony of Dr. Carl H. Oppenheimer at DCS Public Hearing,
August 23, 1972, New Orleans, Louisiana.
C-12. Draft Environmental Statement for the Proposed Prototype Oil
Shale Leasing Program. Volume II Energy Alternatives. U.S.
Department of the Incerior, September, 1972.
C-13. Handbook of Labor Statistics 1971. U.S. Department of Labor.
C-14. Statistical Abstract of the United States 1971. U.S. Department
of Commerce.
C-15. U.S. Energy Outlook. An Initial Appraisal 1971-1985. An Interim
Report of the National Petroleum Council, Volume 1, July, 1971.
C-16. Crosby, George, "Testing Procedures Available on Far East Wells",
Petroleum Engineer, pp 50-54, November, 1970.
C-17. "Liquids-Destroying Burner Successful in Offshore Tests",
Petroleum Engineer, pp 21-23, December, 1969.
194
-------
C-18. Bleakby, W. B., "Shell's SWD Meets Pollution Standards", Oil and
Gas Jounial, pp 144-146, September 21, 1972.
C-19. "Filtration Units Clean 500,000 b/d of Produced Water for Combina-
tion Disposal-Injection Supply", Petroleum Engineer, p 56, April,
1972.
C-20. Smith, Wesley W. , "Salt Water Disposal: Sense and Dollars",
PeLrolcum Engineer, pp 64-65, October, 1970.
195
-------
APPENDIX D
ENVIRONMENTAL AND ECONOMIC CONSIDERATIONS INVOLVED
IN OIL SHALE DEVELOPMENT
List of Tables
D-l. Land Requirements for Oil Shale Processing 205
D-2. Water Balance as a Function of Pumped Mine Water
Quality, Acre-Fcet/Ycar . 209
D-3. Water Consumed for Various Rates of Shale Oil
Production 213
D-4. Estimated Costs for Producing 100,000 bbl/CD Syncrude
From Oil Shale 215
D-5. Effect of Mining Method and Shale Quality on Syndrude
Value 217
D-6. Oil Shale Capital and Operating Costs 222
List of Figures
D-l. Oil Shale Utilization - Routes and State of Knowledge . . 199
D-2. Flow Diagram of 50,000 Barrel per Calem'.ar Day
Underground Oil Shale Mine and Processing Unit 200
D-3. Schematic Flow Diagram of Retorting System 201
n-6. 50.000 Barrel ocr Calr-.nd.ir Dav Refinerv ««.,
£.\J J
D-5. Flow Diagram of 50,000 Barrel per Calendar in Situ
Recovery System 204
D-6. Trial Water Balance for Two Hypothetical Mine
Developments in Colorado 208
D-7. Water Supply and Demand in Cu Ft/Sec for Underground
Mine, 50,000 bbl/Day of Shale Oil 210
D-8. Water Supply and Demand Cu Ft/Sec for Surface
Mine 100,000 bbl/day 211
D-9. Value of Syncrude from Oil Shale - Open Pit Mine 218
D-10. Value of Syncrude from Oil Shale - Strip Mine 219
D-ll. Value of Syncrude from Oil Shale - Adit Mine 220
D-12. Value of Syncrude from Oil Sh'ile - Shaft Mine 221
197
-------
APPENDIX D
ENVIRONMENTAL AND ECONOMIC CONSIDERATION'S INVOLVED
"IH OIL SHALE DEVELOPMENT
Oil shale deposits in the Green River Formation, underlying about
17,000 square miles within an area of 25,000 square miles, in Western
Colorado, Eastern Utah, and Southwestern Wyoming, comprises one of the
immense known potential resources of fossil fuels. Total known re-
sources have been estimated at upwards of 2 trillion barrels of oil
equivalent. Of this immense total, some 80 billion barrels are esti-
mated to be recoverable at cost levels estimated in the range of $4.00
to $6.50 per barrel. The growing need for new sources of liquid fuels
to meet the vast increases in U.S. demand foreseen over the next
several decades has intensified interest in the early commercial devel-
opments of these deposits.
The development of these resources will have a substantial and largely
irreversible impact on the environment of the region, as well as poten-
tial impacts on adjacent areas. The U.S. Department of Interior has
recently completed an environmental statement for a proposed prototype
oil shale leasing program which would involve two leases each in
Colorado, Utah, and l.'yoaiinr., including no more than 5,120 acres each.
Proposed methods of develop.:c-nt are to include:
1. Underground mining, with underground disposal
2. Underground mining, with surface disposal.
3. Strip mining with backfill
(D-l)
4. In-situ operations.
The technology involved in mining followed by surface processing of
oil shale and shale oil is reasonably well established, but the possi-
bilities of in-situ processing are still in the experimental and re-
search stages. Present status of knowledge on various routes to liquid
fuels from oil shale is shown in Figure D-l.
Much of the data used to provide estimates of the potential environ-
mental emission of the commercial development of a 1,000,000 barrel
per day liquid-fuel recovery from oil shale is based on information
and data taken from the U.S. Department of Interior study.
A flow diagram of a 50,000 barrel-per-day underground oil shale mine
and processing unit la shown in Figure D-2. A flow diagram of a re-
torting system is shown in Figure D-3 (six individual, 56-foot diameter
retorts would be required for a 50,000 barrcl-per-day plant), while
19S
-------
vD
(3A) NATURAL
(2C> HYDRAULIC
(2C) ELECT7W-
(EC) OS?.! EX?USSVE
(33)
I fRscm 8 filler (lA)
MINING Ir**5*™ £rl™S?
OIL SHALE DEPOSIT
(2 A) N. FrMi;< ^errvning from :
A
D fVnjlpjrn er c•^er rtjustry
Insrosc fw.r* tin OB)
I Rrir*^;!c*8 ^2A^
ltw.P (2A)
CTSTiLLATE FUO. OIL
RESIDUAL FUEL OIL
L.OUEFiED F2TROLEUM GAS
AK.'.'OMA (!C)
CC)
ATO.VATICS(2A)
S=CC!ALT!£S{3A)
COKE (1C)
PITCH (1C)
ASPHALT(IC)
WAX (2A)
August 1972
FIGURE D-l. OIL SHALE UTILIZATION - ROUTES AND STATE OF KNOWLEDGE
Source: Reference D-l.
-------
rGEU
O
O
Primary
crushers
Oil shate
73.700 tons/cd
1
Makeup natural
gas if needed
Retort product gas Refinery gas
Secondary crushing
and sizing plant
Dust from
crushers
and sizing
operations
1.000 tons/cd
Oil shale
72.700 tons/cd
Retort water
gal/ed
150,000 to 350.0CJ3- ---
\
I
Retorting
plant
Raw shale oil
53.500 bbl/cd
Oil
upgrading
olant
(refinery)
Upgraded oil
50.000 bbl/cd
Sulfur, 43 tons/cd
1»
Ammonia. 138 tons/cd
Coke. 855 tons/cd
>
I
I
1
Waste water
recovery system
Spent shale and dust
58.560 tons/cd
(dry weight)
| Refinery waste water
| 100.000 gal/cd
4 Makeup water from
t other Plant sources
Waste water
recovery system
plus fresh water
as needed
FIGURE D-2.
Source: Reference D-l.
Spent shale disposal
in-nine and/or surface
FLOW DIAGRAM OF 50,000 BARREL PER CALENDAR DAY (cd)
UNDERGROUND OIL SH/LE MINE AND PROCESSING UNIT
-------
from crusher
505 tons/hr
Basis: 1 retort
conveyor I I Feed
hopper
fl.M.0..,
5 Recy
. I ,1-35,:
cycled
x 10.6 scf/hr
x 1U" scf/hr
To plant fuel system
4.04 x 106 scf/hr
f-KP
Shale oil
storase
370 bbl/hr
Recycled gas 5.72 x 10& scf/hr
Spent shale 410 tons/hr
FIGURE D-3. SCHEMATIC FLOW DIAGRAM OF RCTORTINR SYSTEM
Source: Reference D-l.
201
-------
Figure D-4 shows a flow diagram for the upgrading plant, producing
scmircfincd oils suitable for pipeline transmission to a conventional
petroleum refinery.
A flow diagram of an envisioned 50,000 barrel-per-day in-situ recovery
system is shown in Figure D-5. It should be noted that substantial
quantities of water are produced in conjunction with the recovery of
oil and gas vapors, which would require treatment. The physical char-
acteristics of the shale-oil recovered by in-situ processing also
would be substantially different from that produced by presently known
retorting methods. Tests run on oil recovered in limited experiments
indicate that the oil would be appreciably lighter and with a much
lov/er pour point, making it potentially suitable for shipment to a con-
ventional petroleum refinery without further processing.
Land Requirements
Estimated land requirements for oil shale processing by different
methods are shown in Table D-l.
Surface mining would have the greatest initial disturbance. Assuming
a 30-year development period the cumulative land requirements might be
as much as 66,500 acres. With backfill of spent shale and restoration
of the land, this might be reduced to 26,750 acres.
Underground mining with surface disposal might be as much as 44,000
acres. By utilizing underground disposal for 60 to 80 percent of the
spent snaic, tnis could be reuuccu LU a'uuuc Z2,CGG aci"G3.
In-situ processing under full-scale operation would have from 15,500
acres to 35,800 acres in active development at any given time depend-
ing on the rate of recovery per well drilled. Restoration of depleted
areas would be a continuing process.
In addition to actual land used in mining, spent shale disposal, and/
or in-situ operations, land would be required for other processing
operations, storage facilities, and rights-of-way for pipelines, utili-
ties, and roads. This might require as much as 1,700 to 2,000 acres
per site, or from 34.00U to 40,000 acres total. Also, urban land re-
quirements to handle the increase in temporary and permanent employ-
ment in the region might require an additional 20,000 acres.
This would indicate a total land use requirement of upwards of 75,000
acres by 1985, and a continuing need for about 2,000 new acres annu-
ally. Thus, the land use would entail about 0.5 percent of the 25,000
square mile region, with a continuing requirement of 0.01 percent per
year. Land use per barrel of daily capacity would be about 0.075 acre.
Disposal of spent shale, as well as overburden in the case of a sur-
face mine, will create a major permanent impact on the land surface.
202
-------
Retort Cos. 9.220 LFEAJ
o
to
581 x 10s scf/d (Het). 100 Btu/sef Gross Heating Value
»-
T
Shot* Oil h Distil-
53.500 bbl/d I0"°n
1 Bottoms,
1 26.750 bbl/d
^ — (Furnace
Oistilloto.
/
_ Oeloy
>•* r.
26.750 bbl/d
Gas 1.890 LFE/d
»
cd Oiitillote,
^ r™^™™^ *
1.900
Hydro-
g 21.895 bbl/d
Coke
855 tph
1
Armon i a
> I.J3 t/
Sulfur
Gas 3. 75
'real ing
LFE/d
Hydrogen
63. 1 X I06 sc
'd
'd
10 LFE/d ,
1
Hydrogen
(/d Plant
Oil
P 50.
Fuel Gas
To Plant System
7 >w a Rrn i rr/rf
. Sen! -refined.
000 bbl/d
J/LFE is Liquid Fuel Equivalents liith Gross Heating Value 6.3 X 10s Btu
FIGURE D-4. 50,000 BARREL PER CALENDAR DAY REFINERY
Source: Reference D-l.
-------
N9
O
R
e
s O
t
Restored •-'
area o
O p
I
u
S
O
0
0
0
0
mf ••
•MMBa^
0
0
_ o
- R".
e"b
- t _
r ©
n-
<&-*• 8 ©
- z-
O
Makeup natural MaVeuo gas plus refinery
O
O
O
O
o
o
o
Low Btu gas to flare
1,485 x 106 scf/cd
gas if needed
Gas/oil mist
and water vapor
Legend
O Drilling well
O Producing well
® Injection well
0 Plugged well
O Surface monument removed
Gas/oil
separation
and
recovery
plant
In situ shale oil
49.100 bb!/cd
Retort water
560.000 gal/cd
_ tump
- Pi
'l
gas to plant fuel system
Oil
upgrading
plant
(refinery)
Upgraded oil
->
50.000 bbl/cd
Sulfur. 38 tons/cd
Ammonia. 130 tons/cd
Refinery waste water
100.000 gal/cd
Waste water
treatment plant
Treated water for refinery
or other plant uses
660.000 gal/ed
FIGURE D-5. FLOW DIAGRAM OF 50,000 B.:\RREL PER CALENDAR DAY IN SITU RECOVERY SYSTEM
Source: Reference D-l.
-------
TABLE D-l. LAND REQUIREMENTS FOR OIL S1IALE PROCESSING
Function Land Required, acres
Mining and Waste Disposal
Surface Mine(a'b) (100,000 bbl/day)
Mine Development 30 to 85 per year
Permanent Disposal, overburden 1,000 (total)
Temporary Storage, low-grade shale 100 to 200 (total)
Permanent Disposal, processed shale 140 to 150 per year
Surface Facilities^0' 200 (total)
Off-Site Requirements^6) 180 to 600 (total)
Underground Mine^ (50,000 bbl/day)
Mine Development (surface facilities) 10 (total)
Permanent Disposal
All processed shale on surface 70 to 75 per year
60 percent return of processed shale
underground 28 to 30 per year
Surface Facilities^) 140 (total)
Off-Site Requirements 180 to 225 (total)
Surface Facilities^0) ... 50 (total)
Active- Well Area and Restoration Area*1 ; 100 to 900
In-Situ Processing (50,000 bbl/day)
Surface Facilities^0)
Active Well Area and Restoration An
Off-Site Requirements 180 to 600 (total)
(a) Area required is dependent upon the thicknesses of the overburden
and oil shale at the site. Acres shown are for a Piceance Creek
Basin site, with 550 feet of overburden and 450 feet of 30 gallon/
ton shale (approximately 900,000 bhl/acre).
(b) Assumes 30 gallons per ton oil shale and a disposal height of 250
feet.
(c) Facilities include shale crushing, storage and retorting (excluded
for in-situ processing), oil upgrading, and storage, and related
parking, office, and shop facilities.
(d) See Vol. Ill, Figure (III-ll) for conceptual view of surface utili-
zation.
(e) Includes access roads, power and transmission facilities, water
lines, natural gas and oil pipelines; actual requirements depend
on site location. A 60-foot right of way for roads requires a
surface area of about 8 acres per mile. Utility and pipeline
corridors 20 feel in width require 2.4 acres per mile.
Source: Reference (D-l).
205
-------
During the early years of open-pit mining, all of the overburden and
spent shale from retort operations would have to be disposed off-site.
Because of the increase in volume of the spent shale over the original
oil shale in place, a substantial portion (20 to 40 portent) of the
spent shale would need to be disposed of above ground even with good
compaction of the spent shale. The immense volumes involved would need
to be disposed in carefully selected sites, probably dry canyons. The
filling of these canyons would affect the topographic and watershed
characteristics of the area involved. Considerable research and experi-
mental testing has been done on methods of compaction, stabilization
of the disposal piles, and revegetation. However, many years would be
required to fill canyons to the desired ultimate height and revegetatc
and otherwise restore the affected area. Interim actions would be re-
quired to prevent or minimize wind and water erosion as well as legc!j:
ing of the spent shale. Small-scale experiments by Nevens, et all " '
have indicated a natural surface cementation reaction that can mini-
mize erosion and leaching effects. The construction of upstream diver-
sion dams and canals or culverts to carry runoff water past disposal
sites has been suggested as a means of obtaining better erosion control
during the build-up of the waste disposal pile. Sediments eroding from
the pile would be i-rapped through construction of downstream ponds
capable of retaining the run-off waters for the necessary settling
time. Water from these downstreams ponds, if high in dissolved solids
from leaching of the pile, could be used for compaction of the pile;
or in other appropriate process operations. If water in excess of
operational needs is obtained, other disposal methods will be required
to prevont increased salinity in the Colorado River System.
Impact on Air Quality
The principal sources of air pollution would be solid particulates re-
sulting fi im mining and spent shale disposal operations, dust produced
during crushing and retorting operations, burning of gases from retort-
ing and refining operations and the generation of electric power, and
the dust and vehicle emissions from construction and mining operations.
Estimates by the U.S. Department of Interior for major air pollu-
tants based on a 1,000,000 barrel-per-day scale of operations are as
follows:
Dust -- 440 tons per day «0.88 Ib/bbl oil (assuming 98 percent primary
dust capture efficiency)
S02 — 460 to 680 tons per day«0.92 to 1.36 Ib/bbl oil
N02 -- 80 to 120 tons per day«0.16 to 0.?4 Ib/bbl oil.
The operation would, of course, be located in various areas having
differing weather conditions. Temperature inversions are typical of
the Colorado region, so air quality in certain instances may exceed
206
-------
ambient air standards. Weaver^ ' in a recent study has calculated
the possible impact on ambient air quality in the central Piceance
Creek Basin for a minimum sized plant. Peak ground level concentra-
tions under certain inversion conditions arc shown to exceed Colorado
air quality standards by appreciable amounts over substantial distances.
The U.S. Department of Interior in its recent report has stated:
"It is clear...that source emissions to the atmosphere must
be so controlled that pollutants would not accumulate under
inversion conditions. Wherever feasible, processing facili-
ties should be located on upland services rather than in
valleys and canyons."
For Utah locations they conclude that uncontrolled pollutants would
tend to affect the Rangely, Colorado, population center. Conversely,
inversion conditions in Wyoming are expected to present less of a
problem.
The residual concentrations of sulfur are estimated to be 230 to 340
tons per day for a 1 million barrel-per-day operation. This level is
calculated to meet minimum standards in tho region. Most of these
sulfur emissions would occur from burning of tha low Btu stack gases
from retort operations. Actual levels of sulfur present in these
gases would be between 0.9 and 1.1 pounds per million Btu for internal
combustion processes, about 5 pounds per million Btu for the indirectly
heated process, and 2.8 pounds per million Btu for in-situ combustion.
In comparison, the Environmental Protection Agency standards for sta-
tionary, sources is 0.6-.pound.ppr million Btu, while Colorado standards
arc still lower. It would, therefore, be necessary to establish sul-
fur removal facilities either through precombustion processes, or stack
gas removal of S02- Technology exists to accomplish the former, while
numerous methods for stack gas removal of SC>2 are in the developmental
stage.
The estimated NOX emissions are primarily a result of combustion tech-
niques, although some additional NOX also may be formed from chemically
bound nitrogen in liquid or solid fuels that may be used.
Impact on Hater Quality
The extent of the impact on water quality cannot be measured with any
degree of accuracy prior to actual development of a specific operation.
Aquifer characteristics and quality of the water produced would be
major determinants. Considerable data have been developed for the
Piceance Creek Basin in Colorado and estimates of the transmissivity
of the water-bearing zones have been made for most of the sites nomi-
nated in Colorado under the proposed leasing program.^
Water supply and demand balances have been developed for two hypothe-
tical mining operations in Colorado as shown in Figure D-6. Flow
207
-------
Keu Water. Acre Feet per Yf«r
Underground Hlnc M Surface Mine 21
Vater Required tor;
Crushing 150- 220 300- 440
Mtnlns 220- 290 . 440- 580
Processed shale disposal 2,480-4,230 4,960- 8,460
Retorting 580- 730 1,160- 1,460
Refining 1,460-1,820 2,920- 3,640
Other u»es 3/ 70- 440 80- 580
TOTAL 4,960-7.730 9,660-15.160
Vater Available from;
Retorting 170- 360 340- 730
• Refining 110 220
Mine development 4/ 7,680 12,410
Other 5/ ~ 100 200
TOTAL 6,260-8.450 13,170-13,560
Vater Balance
High quality Water
requirements 6./ 2.110-2,990 4,160- 5,680
High quality waiter fron nine ]J 3,960 6,205
EXCESS HIGH QUALITY 1,830- 950 2,045- 525
Poor quality vater
requirements 8/ 2,850-4,740 5,700- 9,480
Poor quality water froa mlue and
processing 9/ 4,320-4,510 6,965-7,365
EXCESS POOR QUALITY 1.660-(.-)420 l,665-(-)2,515
Trial Water Balance:
Excess Ugh quality ?•???" ??? 2>?*?". ,?2?.
txecss poor quality t,»jQ-(-y-'tG l.-jCS^i-J
SURPLUS JO/ or DIVERSION (-) U./ 3.490- 530
\f 50,030 barrels per day
2/ 100,000 barrels per day
3i/ Primarily net do-ncstic consumption [or associated population
4~/ Average produced water over 30->ear period (3)
J5/ Other sources, such as boiler blowdovn, bleed-off from cooling
"" tOatcr. etc.
(/ Requirement for retort inf.. refining, and other uses such as
*" drinking oor quality w.icvr would rrnutic dcsaltn>g|cvaporatlon
In Inpcrocablc ponds, or disposal by subsurface injection
II/ Diverted water would be from surface water in the Colorado
River system.
FIGURE D-6. TRIAL WATER BALANCE FOR TWO HYPOTHETICAL
MINE DEVELOPMENTS IN COLORADO
Source: Reference D-l.
208
-------
diagrams of these balances are shown in Figure D-7 for ar. underground
mine and in Figure D-8 for a surface mine. Table D-2 shows the water
balance as a function of pumped mine water quality.(D-l)
TABLE D-2. WATER BALANCE AS A FUNCTION OF PUMPED
MINE WATER QUALITY, ACRE-FEET/YEAR
-------
.2-.3
2.0 • 2.5
4—^— Diverted water
See (a) below f Processed^
water treatment / shale disposaj
or disposal
o
u)
CO
o
to
tf\Produced v/ater
Water available
for treatment
0' dispocal
Ranee (or water that could be
utilized in mining operation
O
ul
CO
Ul
UJ
10
"• 5
o
m
3
O
T
Diverted water needs (or
processed shale disposal
10
15 20
YEARS
(b)
25
30
35
FIGURE D-7. WATER SUPPLY AND DEMAND IN CU FT/SEC FOR
UNDERGROUND MINE, 50,000 BBL/DAY OF SHALE OIL
Source: Reference D-l.
210
-------
Mine Water
.4-.6
Crushing
.6-.8
Mining.
V
Water Treatment Or
Disposal
(Sec Below)
Other Uses
Construct ion.
Personnel.etc.
D
0.1-0.
Diverted
Koter
4.0-5.0
20
815
10
retort ing, refining, ond
\Votor that moybo'usod for
processed shalo disposal,
crushing,and mining.
I
I
5
10
15 20
YEARS
25
30
FIGURE D-8. WATER SUPPLY AND DEMAND CU .FT/SEC FOR SURFACE
MINE 100,000 BBL/DAY
Source: Reference D-l.
211
-------
pollution problem unless adequate controls arc established. Recent
experimental studies conducted at Colorado State Univcrsity(D-4) sug-
gest that the presence of snow may create a greater leaching problem
than rainfall because of the longer contact time. Channeling of water
flow away from canyons containing spent shale and collection of surface
runoff in downstream ponds is recommended. Other recommendations in-
clude wetting and compaction of the spent shale piles and avoiding
direct exposure of the top surface of the shale piles to the elements
to the extent possible.
Spent shale deposited in underground mines would also be subject to
leaching if the mine workings were flooded while active or after mining
operations ceased. The possible effect of this is unknown at this
time.
« Domestic Wastes. The U.S. Department of Interior has estimated
that a 400,000 barrel-per-day operation would require a population in-
crease of about 47,000 people in the region. Extrapolation of this
requirement to a 1,000,000 barrel-per-day operation would indicate a
population increase of about 117,500. Population of the region in 1970
was about 119,000, so domestic demands for water would essentially
double present requirements. Some degradation of water quality would
probably occur, the extent of which would be determined by the type and
extent of municipal water treatment systems that might be installed.
e Writer Consumption. The net water consumed for v.'irious rates of
shale oil production is shown in Table D-3. If all of this water ob-
(•ainorl <»it-hr>r Hirorrly or indirppr.1v from snrfarp and pronnri wafers t-h;^
would otherwise contribute to the flow of the Colorado River, the
salinity at Hoover Dan would be expected to increase between 6 and 10
mg/1, or an increase in salinity of about 1.4 percent. This might be
considered the worst normal case if supply of water is less than demand.
On the other hand, if supply of water is greater than demand, an aver-
ago salinity of the effluent above about 740 mg/1 would add to the
salinity content at Hoover Dam. This indicates the desirability of the
construction of different holding basins, maximum utilization of high
saline-content water where possible, and the' prevention of inadvertent
discharge of high-saline content v;ater.
o Operational Spills. The possibility always exists for accidental
spills of oils and chemicals in process operations. The establishment
of controls similar to best technology used in petroleum refining
should minimize potential water contamination from these sources.
Little information is available regarding impact on water quality that
might result from in-situ operations. Dcwatering of the in-situ site
would be required involving some means of disposing of this water.
Methods used would depend on its salinity. There also would be poten-
tial contamination of ground water supplies, subsequent to the under-
ground fracturing, retorting, and recovery of tiie shale oil. Further
experimentation will be needed to determine the severity of the problem
212
-------
TABLE D-3. WATER CONSUMED FCR VARIOUS RATES OF SHALE OIL PRODUCTION
Shale Oil Production - barrels per day
Net W.itcr Corisured, acre feet per year
(a).
Function 50,000 100,000 250,000 1,000,000
Mining 220 - 290 440 - 580 1,100 - 2,900 3,500 - 6,100
Crushing (dust control) 150 - 220 300 - 440 800 - 1,100 2,400 - 3,500
Retorting 580 - 730 1,160 - 1,460 2,900 - 3,700 9,300 - 11,700
Processed Shale Disposal 2,480 - 4,230 4,960 - 8,460 12,400 - 21,200 39,700 - 67,700
Shale Oil Upgrading 1,460 - 1,820 2,920 - 3,640 7,300 - 9,100 23,400 - 29,100
Other(b) 70 - 440 80 - 580 400 - 2.300 1.000 - 6.300
TOTAL 4,960 - 7,730 9.860 -15,160 24,900 - 40,300 79,300 - 124,400
(a) This million barrel per day production- is assumed to be derived from 5 underground, 1
surface, and 1 in-situ operation.
(b) Primarily net domestic consumption £OT associated population.
Source: Reference D-4.
-------
Involved in any specific location. Underground migration of the shale
oil and gases produced by the combustion process also might be a major
source of water pollution in the area. Treatment methods also would
have to be established for the water produced in conjunction with the
shale oil and gases to maintain desired water quality.
Impact on Fish and Wildlife
Noise levels would be substantially increased because of blasting,
earth moving equipment, crushing and grinding operations, compressors,
pumps, processing operations, etc., involved in this massive indus-
trial operation. This and other factors associated with industrial
development would change the character of the region and would have a
significant impact on the wildlife presently inhabiting the area.
Some species, such as mountain lions, elk, and peregrine and prairie
falcon would be intolerant. Others would be affected to a lesser de-
gree.
The impact on fish and other aquatic life would depend on the extent
and frequency of water pollution that may occur—over time.
Impact on Aesthetics.. Recreation, and Cultural Values
Presently, the area is remote and sparrcly settled. Average population
density is about three persons per square mile. Recreation activities
involve hunting, fishing, and bo«"ting, by both residents and tourists.
Within the 25,000-mile region there are a wide variety of unique fea-
tures and scenic wondprs. Hislririr ,ir/»;»<: pro nrimarilw acer^i -*+oA
with Indian culture. The development of a largo-scale oil-shale
industry would cre.te many irreversible chcngos. With proper location
of mining and processing operations, the rvjor aesthetic values and
historical sites can be maintained, but the substantial increases in
residents and in visitors (both business and vacationers) would expand
recreational utilization of the region while at the same time fish and
wildlife population might be expected to decline.
Economic Considerations
Costs that may be involved in the development of a major shale oil in-
dustry arc subject to a wide variation, depending on the type and loca-
tion of operations that may be established.
An appraisal made by the Oil Shale Task Group of the National Petroleum
Council in 1971 provided estimates of capital and operating costs that
might be involved in 12 cases involving four mining methods and three
grades of oil shale. These estimates are shown in Table D-4.(D~5)
This table shows capital costs ranging from $522.6 million to $746.6
million including the required construction perioc for each mining
method evaluated and a 20-year operating period, including a three-
214
-------
TABLE D-4. ESTIMATED COST5 FOR PRODUCING 100,000 BBL/CD SWCRUDE FROM OIL SHALE
(AT ,<1D-YEAR 1970)
\JI
25 CAl/TON
SHALE
30 CAL/TOS SKAL2
OIL SKALE XISED & RETORTE3. TOS'S/CS 176,800
CRU3E S'.iALE OIL PRODUCED. 8BL/C2 1C '.,000
VV!vC vr— j(}5 SL'?.?AC2 UKaSRCKOViO
CAPITA'.. S MILLION
MINING. CJU'S'IINC. ASH DISPOSAL
INITIAL
RE701T::.3
t?CRA3::-c
TOTAL INVESTMENT
VCtKING CAPITAL
TOTAL CAPITAL (SOT 1NCL. UUO)
cpriur.c COSTS, $ M'-LION/YEAR
KIM'.C. C".i:S!IINC. ASH DISPOSAL
Ri'lMTP.C
VATZP. SYSTfM
TOTAL Ol'LRATINC COSTS
FUST IS V.A1S
AfTtl 15 YEARS
UNIT fiSTS
PIT
176.8
94.2
192!&
7.0
719.0
27.6
74».6
STRIP
95.4
79.4
248.2
192.8
7.0
622.3
27.6
650.4
AD;T
103.0
71.4
243.2"
192. S
7.0
624.4
27.6
652.0
S'-vrr
,1'IO.S
'4.0
2-.B.2
112.3
• 7.0
6t2.8
)3.8
611. 6
165. 6CO
104.030
SUPrACE UNDERGROUND
1 PIT
147.2
78.4
2C6.8
192.8
7.0
632.2
21.6'
655.8
STRIP
79.6
65.0
206.8
192.8
7.0
352.0
73.6
575.6
AUIT
87.6
39.4
2C5.8
192.3
7.0
333.6
23.6
ITO
StiArT
109.0
61.6
206.8
172.8
7.0
377.2
74.8
602.0
35 CAL/TON SHALS
124,830
104,000
SURFACE VSOEICROt.'VD
PIT
126.2
67.2
177.2
•192.5
7.0
•370.4
20.0
591.2
STRIP ADIT
68.2 75.0
56.6 51.0
177.2 177.2
192.8 192..8
7.0 7.0
301.8 303.0
70.8 20. S
522.6 523. 8
ShAFT
93.4
32. S
177.2
19:. s
7.0
323.2
545.6
(SOT INCLUDING DrPRECIATIOS)
39.6
20.4/25.6
16.8/19.4
77.2
85.0
39.6
77.2
85.0
39.6
77.2
85.0
'.2.8
BO. 4
83.2
33.0
17.0/21.2
16.8/19.4
0 4
67.2
74.0
33.0
67.2
74.0
™ ' " MINING. CKUMIINUi AMI AMI UlSIUN.ll,
CAPITAL (S PER TOM/CD)— INITIAL
Qrp£B«r|
OfiWTISC COST (e PER TON)
FIKsT 15 VE,\RS
AHJ.H 15 YEARS
PIT
1011
> 539
62
62
STM-
5'.6
4$i
62
62
bOl
409
62
62
71.3
424
67
o7
1
13.0
67.2
74.0
14^0
•™
32
40
33.6
69.8
76.6
23.2
14.6/18.2
16.3/19.4
0.4
60.0
65.2
28.2- 28.2
60.0 60.0
66.2 6S.2
UPCRABINS MUSE
(5 PL* LBL/tD)
(C PUl BOl.)
NPC LNEXCr
30.6
62.4
68.6
S'lALC OIL
44
OUTLOOK
Source: Reference D-5.
-------
month start-up period during the first year of operation. Deferred
costs for replacement of equipment and working capital requirements
are included.
The effect of differences in mining method and shale quality on dis-
counted cash flow rates of return for various syncrude value is shown
in Table D-5. The same type information for the four mining methods is
shown in Figures D-9 to D-12. These figures illustrate the sensitivity
of mining method and shale quality on the value of syncrude needed to
secure the same rate of return. For example, to secure a 15 percent
rate of return on shale assaying 25 gallons per ton in open pit mining
would require a syncrude value of $6.65 per barrel compared with about
$6.08 for strip mining, $6.12 for adit mining, and $6.40 for shaft
mining. On the other hand, utilizing a shale assaying 35 gallons per
ton would reduce the necessary syncrude value to $5.30 per barrel for
open pit mining, $4.90 for strip mining, $4.92 for adit mining, and
$5.10 for shaft mining. All of these estimates include a 25 percent
contingency in the retorting and upgrading investments. In comparison,
the U.S. Department of Interior estimates of capital and operating
costs, as presented in their recent study, " ' are shoxm in Table D-6
for underground, open pit, and in-situ operations. It should be noted
that both capital and operating cost estimates are appreciably lower
than those prepared by the National Petroleum Council.
In addition to the direct costs involved in developing a million barrel
per day oil shale industry, substantial investments would be required
in the infrasl .-ucture needed to support the operation. As mentioned
earlier, a population increase of more than 100,000 would be required.
Assuming an average capital cost oi- aoout $J2,UUU per individual for
the required housing, commercial and community facilities would indi-
cate a requirement of about $1.2 billions of dollars.
Economic Costs for Environmental Protection
The cost estimates prepared by the National Petroleum Council and the
U.S. Department of Interior both include estimated costs of providing
environmental safeguards and facilities designed to meet present en-
vironmental standards. However, prior to the actual selection of speci-
fic locations and methods of operation, it is impossible to determine
the costs that might be involved in providing the necessary environmen-
tal safeguards. Furthermore, actual operating conditions encountered
might require substantial changes in presently envisioned means of pro-
viding the needed environmental protection.
The vast bulk of economic costs required for environmental protection
will be concerned with mining operations and disposal of the spent
shale and overburden. More than a third of the capital costs and
about half of the operating costs will be involved in these operations.
Costs involved in disposal methods may account for up to 50 percent of
these requirements, and substantial portion of this total would be for
prevention of leaching and erosion from spent shale and overburden
216
-------
TABLE D-5. EFFECT OF MINING METHOD AND SHALE QUALITY ON SYNCRUDE VALUE
M
l—•
•xj
Mining Method
SURFACE
Open pit
Strip
UNDERGROUND
Adit
Shaft
Shale Assay
gal/ ton
25
30
35
25
30
35
25
30
35
25
30
35
Discounted Cash Flow Rate
% for Indicated Svncrude Val
4.00
5.6
8.1
10.0
7.0
9.4
11.2
6.9
9.3
11.1
6.1
8.6
10.4
4.50
7.8
10.2
12.0
9.2
11.6
13.4
9.1
11.5
13.2
8.3
10.7
12.6
5.00
9.7
12.0
13.9
11.2
13.6
15.4
11.1
13.4
15.3
10.3
12.7
14.6
5.50
11.4
13.8
15.7
13.0
15.4
17.4
12.9
15.3
17.2
12.1
14.5
16.4
of Return,
.ue in $/bbl
6.00
13.0
15.4
17.4
14.7
17.2
19.2
14.6
17.0
19.1
13.8
16.2
18.2
6.50
14.5
17.0
19.0
16.4
18.9
21.0
16.2
18.7
20.8
15.3
17.9
19.9
Source: Reference D-5 .
-------
c»
03
CD
LU
Q
ZJ
cc
o
to
u.
o
LJ
5
VA'.UE OF SYNCRUDE FROM OfL SHALE
OPEN-PIT MINE
7.00
6.00
5.00
4.00
:±q.!: NO LAND COST J
-1-1- . L_*—4 . I , > I I I- I I I 1-t-t—1' j
i i T ti 'i i 111 in i rn !!
'r:rn:T.rJ:
j_Li±.i 44
i i t i I !
0 12 14 16
FIGURE D-9. DISCOUNTED CASH FLOW RATE OF RETURN, %
-------
VALUE OF SYNCRUDE FROM OIL SHALE
vO
STRIP MINE
7.00
GQ
CD
•5- 6.00
bJ
Q
ID
o:
o
•z.
CO
LU
O
LU
5.00
4.00
j ! I I j 1 ! ;_^).i.i-U-4-H-f-i-U-f-}- I I I I I I I i-U-
I I I I I i • I ' I I I \ l : ' I ' ' ' I ' 1 ' _l ' _ i ! .1-
' ---
;;±±SHALE ASSAY
FT GAL/TON
0 12 14 16
FIGURE D-IO. DISCOUNTED CASH FLOW RATE OF RETURN, %
-------
700
VALUE OF SYNCRUDE FROM OIL SHALE
ADIT MINE
03
03
UJ
O
CO
u.
O
LU
n
5
6.00
5.00
4.00
HNO LAND
±±|±r+tSHALE ASSAY i+^^p-H
•- ri-r-t-:--- O AI /TDM >VJ-1-
m^$m
rri-4- i- LLtixTx
i i I i i i i i • i
FIGURE D-ll. DISCOUNTED CASH FLOW RATE OF RETURN, %
Source: Reference D-5.
-------
VALUE OF SYNCRUDE FROM-OIL SHALE
7.00
NJ
K>
_J
CD
CD
UJ
tr
CO
tL
O
u
5
6.00
5.0O
4.00
-tSHALE ASSAYS
i ! ; ?'! M i ; i ; i | i i. J_JJJJ.i
1. !-!-! ! ' L III i iL. ,.l. ivj.
--. ------_
l tflii J:in;Li
10 12 14 16
FIGURE D-12. DISCOUNTED CASH FLOW RATE OF RETURN, %
-------
TABLE D-6. OIL SHALE CAPITAL AND OPERATING COSTS
(Millions of Dollars)
(a)
Plant Capacity, Thousand bbl/day
Mining Option 50 100
Underground with Mine Disposal
Capital costs:
Labor • 35.2
Equipment 187.2
TOTAL 222.A
Annual operating costs:
Labor 11.2
Supplies 14.9
TOTAL 26.1
Open Pit v?ith Backfill
Capital costs:
Labor 51.2
Equipment 267.8
TOTAL 319.0
Annual operating costs:
Labor 15.8
Supplies 17.9
TOTAL 33.7
In Situ (non-nuclear fracturing)
Capital costs:
Labor 19.8
Equipment 213.9
TOTAL 233.7
Annual operating costs:
Labor 13.1
Supplies 2.1
TOTAL 15.8
(a) Except for in situ, capacity is based on Bureau of Mines gas
combustion retort and is in terms of semirefined shale oil
and 1970 dollars.
222
-------
and for restoration of the land surface to minimize degradation of
aesthetic values. Thus, costs may be in the range of $0.50 to $1.00
per ton of material, or upwards of $0.70 per barrel of shale oil pro-
duced.
Economic costs involved in retorting and upgrading operations would be
similar to those encountered in petroleum refining.
References
D-l. Draft Environmental Statement for the Proposed Prototype Oil
Shale Leasing Program (3 volumes), U.S. Department of the
Interior, September, 1972.
D-2. Kcvcns, T. D. , W. J. Culbertson, Jr., and R. Hollingsliead,
Disposal and Uses of Oil Shale Ash, Final Report, U.S. Bureau of
Mines, Project No. SWD-8, submitted by Denver Research Institute,
April, 1970.
D-3. Weaver, Glen D., "Environmental Hazards of Oil-Shale Development",
The Conservation Foundation, September 15, 1972.
D-4. Water Pollution Potential of Spent Oil Shale Residues, Colorado
State University for the Environmental Protection Agency, Grant
No. 14030 EDB, December, 1971.
r\ c 11 r> K>_........ r> ... 1 _ _l. j> _ T __••..».. i A __.'..! 1 .. L. - /•>„•! PU..I.. T..1.
&'-'.'. w . *s . 4^11*. Lj^jr tsu i. A. wksrw , tin .1.11 4. «. .1. u j. A i |/|Si. t* j. uti j. \j j i.iiw W.A. wrnui.4= A. M o n
Group, National Petroleum Council, November, 1971.
223
-------
APPENDIX E
COAL MINING AND UNDERGROUND GASIFICATION OF COAL
Table of Contents
Page
Coal Mining 226
Underground Gasification .'!!.'!!.'!! 232
References !!!!!! 237
List of Tables
E-l. Underground Gasification, Estimated Operating Costs. . 227
List of Figures^
E-l. Representation of Coal Mining Module 227
E-2. Input-Output Designation for an Underground
Gasification Module 234
225«
-------
APPENDIX E
COAL MINING AMD UNDERGROUND
GASIFICATION OF CUAL
.Coal Mining
To benefit the economy through the use of coal for steam raising, elec-
tric power generation, carbonization, and gasification (the important
applications), coal must be recovered from beneath the surface of the
earth, by either underground or stripping systems involving the removal
of varying thicknesses of overburden to reveal the seam. The only
alternative to such mining systems is underground gasification, which
is treated in the second section of this appendix.
A number of different physical systems are used underground to nine
coal, depending on geological conditions. In any event, to mine coal
underground requires inputs of electric power, diesel fuel, water, con-
pressed air, explosives, ventiJating air, rock dust, and other physical
components, in addition to men (labor) and machines (capital). The
product is coal, and the by-products are (1) mineral materials (usually
partially removed in associated coal-cleaning plants), (2) some coal
dust (which results from handling at the surface, but is a local, minor
factor), and (3) acid mine drainage, which represents the principal en-
vironmental problem of the underground coal mining operation. ' An
additional problem of underground coal mining is the aesthetic factor,
which, however, is of greater significance in the refuse piles of
cleaning plants and the unreclaimed surface mining operations.
In surface mining operations there is the input of labor (less inten-
sive than underground mining), machines, power, ancillary materials and
supplies, and the environmental factors, attendant on the production of
coal, principally due to aesthetic values and acid mine drainage.
The Underground Coal Mining Module
Figure E-l represents a module for the input-output factors for the
recovery of a basic unit of one ton of coal by underground mining. As
mentioned previously, the chief inputs are labor, supplies, power, and
machines, while the output in addition to the product coal, are acid
mine drainage and local dust.
An Attempt to Quantify the Acid Mine Drainage for the Appalachian
Bituminous Coal Mining Region, Active Mines. Recently, Tybout^l) has
estimated costs of alleviating acid mine drainage on the basis of stu-
dies made in Pennsylvania by the Pennsylvania Department of Mines and
Mineral Industries and the Pennsylvania Department of Health with
226
-------
Labor
Machines (Capital)-
Powcr
Diesel Fuel —
Atr (Ventilation and
Compressed)
Other
Coal in
place, active
underground nines
One ton raw coal mined
Dust (Unquantifiable)
Aesthetic factor (Unquanti
fiable)
Acid mine water drainage
One ton-ot" coal brought to the surface represents about 50 percent
of the coal in place in the scam, on the average. Sone mining
situations are better, some slightly worse. A refinement would
translate the unit ton into a basic one million Btu (or multiple).
Some dust is produced from handling the mined coal brought to the
surface whether it is loaded for transport or delivered to a
cleaning plant. The amount is of local significance and not
quantifiable.
The aesthetic factor is not quantifiable.
The acid mine water produced by a given mining situation may be
approximately determined and measures taken co minimize the pro-
blem. The pyrite in the coal remaining in the mine, in the roof,
floor, pillars, partings, etc. represents the raw material con-
tributing to the production of acid mine waters through the pro-
cesses of oxidation of the pyrite, leaching of the acidic product
and removal from the area by ground water in natural flow or by
pumping.
FIGURE E-l. REPRESENTATION OF COAL MINING HDDULE
227
-------
respect to the volume of drainage. On the basis of that report, the
average volume of acid mine drainage from active bituminous coal mines
in Pennsylvania is assumed to be 7.15 gallons per square foot of mine
roof exposed per year. A further assumption is made that this average
figure lor mine drainage volumes in Pennsylvania can be extended to
represent the whole of the Appalachian region. In the absence of simi-
lar data for the same type of coal mining in these other states — no
averaged data could be found — this assumption must be used as a first
approximation.
It should be noted that the quantity of acid mine waters produced by an
active bituminous mining operation depends, anong other factors, on the
number of years the mine has been operated. This results from the fact
that the amount of oxidation of the pyrite (and the amount of the oxi-
dized products that can be removed by leaching and solution in the water
present) is controlled by the area of surface exposed. Thus, the quan-
tity of acid mine water released by a given mine is a factor of the age
of the mine. Presumably, in the collection of data on volume of acid
mine water produced, the average value represents the mine age factor.
To translate the average volume of acid mine drainage per year per
square foot of roof area to a more descriptive unit basis, average
values for the density of the coal in place, and the thickness of the
seam arc required. This entails the assumption that the area of roof
exposed is proportional to the amount of coal produced and to the re-
sulting volume of mine drainage.
The average density of the bituminous coal in place in the Appalachian
area is assumed to be 82.6 pounds per cubic foot.(E~2)
The average thickness of the coal scams of active mines in the states
of the Appalachian region is assumed to be 4.9 feet. This was derived
from Bureau of Minos collected data for the year 1965, (E- 3) together
with production data for the year 1970. (E~4) From these data a weighted
average value for bituminous coal seara thickness as of 1970 was ob-
tained. Use of 1965 coal seara thickness data with 1970 coal production
figures is justified by the fact that the Average seam thickness (all
bituminous and lignite underground mines) in the United States was 5.3
feet in 1945, 5.4 feet in 1950, 5.3 feet in 1955, 5.4 feet in 1960, and
5.3 feet in 1965. In the Appalachian coal mining region the average
seam thickness in 1965 for bituminous coal production varied from ex-
tremes of 3.6 feet in Maryland to 5.3 feet in Pennsylvania.
The calculated averaged output of acid mine water per ton of coal pro-
duced in 1970 in the Appalachian bituminous coal mining region is cal-
culated to be:
gallons/sq ft pounds/ton
-•-' = 353 gallons per ton of coal mined
oi. . o x «4 . y
pounds /ft-*"9* ^feet (thickness)
228
-------
Since the number of tons of bituminous coal mined in the Appalachian
stntes in 1970 totaled 294.2 million tons, the total volume of acid
mine water produced, under the assumptions stated, was 103.8 billion
gallons during 1970. The average acidity of the produced mine water
is not known. In evaluating acid mine drainage abatement costs,(E~2)
the quality of the drainage water was assumed to be weakly acidic
(i.e., * 500 mg per liter as CaO^) with 1600 ppn TDS.
Acid Mine Drainnge in Other Bituminous Coal Mining Areas (Underground).
Mining conditions (underground) in the flatter terrain of the central
bituminous coal mining states are somewhat different than in the
Appalachian area. Accordingly, the assumed value for the average volume
of acid mine water produced per unit roof area exposed may not be the
same. During the short period of time allowed for search for pertinent
values, none representing average values was found. Further study would
be required to determine a reasonably satisfactory value.
The Siime is true for the western bituminous coal mining states with
appreciable underground operations, such as Colorado and Utah.
Surface Coal Mining
In 1970, almost 600 million tons of bituminous coal and lignite were
mined in the United States. Approximately 46 percent of the coal was
produced from mines located in Ohio, Pennsylvar. a, and West Virginia.
Of the total production, about 56 percent was from underground coal
mines. Approximately 41 percent of the total was produced in strip
mines, and the balance—slightly core than 3 percent—by auger mining
techniques.(E~5)
The 1960 decade saw the total production of bitunijnous coal and lignite
by strip mining techniques about double, from about 120 million tons to
about 240 million tons or from about 30 percent to 41 percent of the
total annual production. These data indicate the increasing importance
tof surface mining techniques in the production of coal and the impor-
'tance of minimizing the environmental effects of surface mining.
Although surface mining techniques are''complex operations, they consist
basically of removing the topsoil, rock, and other materials above the
coal seam so that, the coal can be recovered. Surface mining of coal
embraces three general techniques:(E-6)
1. Area strip mining
2. Contour stripping
3. Auger mining
Area strip mining is used where the terrain is relatively flat. It con-
sists of cutting a trench through the overburden to expose a portion of
the coal seam. After the exposed coal has been removed, a parallel cut
229
-------
is made with the overburden from the new cut being deposited in the
void left by the previous cut. The final cut leaves an open void
bounded on one side by the highwall and on the other by the last spoil
bank. The overall surface effect on the unreclalned land has been de-
scribed as the creation of a gigantic "washboard". This effect can be
eliminated by proper grading and leveling.
Contour stripping is used in rolling or mountainous terrain. This tech-
nique consists of removing the overburden — starting at the outcropping
of the coal seam— and proceeding along the hillside. After the first
cut is made and the coal is removed, additional cuts are made until the
ratio of recovered coal to overburden becomes so small that the opera-
tion no longer is economically feasible. Contour strip mining of coal
creates a "bench" on the hillside bordered on one side by the highwall
and on the other by a sharp grade covered by spoil. This can result in
landslide and severe erosion unless it is controlled.
The quantities of coal produced by these two techniques — area strip
mining and contour stripping — were about equal in 1970. The latter
technique is practiced extensively in the Appalachian area.
Auger mining usually is associated with contour stripping. The tech-
nique is used to recover the coal which can no longer be mined econo-
mically by contour stripping. It also is used to recover coal from
outcroppings which can't be mined safely by underground techniques.
Among the adverse environmental effects of surface mining of coal are^E"
1. Destruction of the vegetative covering
2. Creation of massive piles of spoils
3. Drastic reshaping of the terrain
4. Sliding of spoils and blockage of streams
5. Pollution of streams with sulfuric acid and silt
6. Destruction of economic and esthetic value of the land.
By 1965, more than 1.3 million acres of land had been disturbed by the
surface mining of coal. The annual rate of increase in the area of
land disturbed by these activities amounted to over 46,000 acres in 1964.
The increasing demand for coal coupled with the increased use of surface
mining techniques makes the development of improved techniques for con-
trolling the pollution of all environmental media by these activities
i ative.
Surface mining of coal is not a major contribution to the overall pro-
blem of air pollution. However, the burning of fuels in mining and
hauling equipment, the dust and other materials emitted during blasting
230
-------
operations, and airborne dust from active and abandoned nines as well
as from spoils piles do contribute to air polluLion.
Surface mining of coal contributes to the pollution of stroans and
underground water supplies. Significant pollutants include sul'furic
acid, and iron; trace metals such as arsenic, copper, load, manganese,
.and zinc; and silt. In the Appalachian region it has been estimated
that the siltation from surface mined areas may be 1,000 times that
from undisturbed terrain.
Both the air and water pollution problems created by the surface mining
of coal are increased significantly by improper reclamation of the land
area which has been disturbed by the mining operations. Often restora-
tion of the land to its original vegetation is difficult because of the
physical and chemical nature of the solid waste produced during the
stripping operations. The quantity of such waste produced per ton of
coal recovered vary greatly from deposit to deposit as well as amount
within a given deposit. In the Appalachian area an average of about 33
tons of solid wastes are produced per ton of coal mined.(E-7) The
solid wastes produced in Western surface mines average about 17 tons
per ton of coal produced.(E~7)
Methods of land restoration arc described in the following sections of
the Appendix. Current costs for such restoration have been estimated
at $500 to §2,000 per acre, with $1,000 per acre being a reasonable
average.
Land Restoration. There are currently no Federal regulations regarding
land restoratiou following strip mining. The more stringent state
regulations are designed to assure the environmental acceptability of
the operation. Such regulations include the following practices.(E~8)
1. Removal of top soil for redistribution after the operation
2. Backfilling so as to bury pyritic material or other material which
.will not support life.
3. For "area" stripping, grading to the original contour over which
farm machines can travel
4. For "contour" stripping, reduction of the high wall is required
5. Replanting a ground cover. Generally, 70 to 80 percent ground cover
with no more than 1/4 acre bare, to include 600 living stems (shrubs
and trees) per acre, is required. Survival checks are usually made dur-
ing two growing seasons.
Assuming this type of land restoration the environmental emissions will
become negligible after the restoration is complete. It is assumed
that the miming operation will require 1 year and that 2 years are re-
quired to stabilize the land.(E-8)
231
-------
Treatment of Mi'ne_ Drainage. Treatment of mine drainage refers pre-
domin.intly to treatment of waters containing varying amounts of ferrous
eulfate, ferric sulfaLe, aluminum sulfate, n-agnesium sulfate, manganese
sulfate, and very small amounts of free sulfuric acid. Often a partial
neutralization has taken place via the natural calciferous materials
present and thus calcium sulfate is often present. In some cases, the
iron is originally present as the bicarbonate salt and thus the waters
are neutral, but still highly mineralized. Little sulfate is normally
present in this latter instance.
Methods of removing these netal salts, or neutralizing the acidic salts
• are known. Neutralization is the best known and the one which has the
most actual practice. Other physical separations methods such as re-
verse osmosis, ion exchange, freezing, and electrodialysis have been
studied. Freezing has been found to be expensive and relatively in-
effcctiver Electrodialysis is poisoned by the iron present in the
feed waters and thus is technically not feasible. Reverse osmosis lias
been extensively studied and appears a good candidate for further de-
velopment and demonstration. Electrolytic oxidation of ferrous iron
with recovery of hydrogen has been studied by EPA for treatment of acid
nine waters.
The treatment of acid mine water results in a water impact in the form
of dissolved solids and a solid impact in the form of a sludge. For
example, in the limestone treatment of acid water, CaSO^ is produced.
This material is slightly soluble thus creating the dissolved solids
impact, while the undissolved portion remains in the sludge.
Cost of Control
The cost of strip-r.iined land reclamation varies widely depending on the
specific conditions. An average value of $1000 an acre(E-S) together
with an assumed coal seam thickness of 2 feet give a cost of 1.1 cents
per million Btu.
The cost of neutralization has been evaluated by OR and M'for some re-
presentative cases. For a 106 ton/year plant producing 10& gallons per
day water flow with 1000 mg/1 acidity, the cost of neutralization was
estimated to be 30 cents per 1000 gnllons or 0.46 cents per 106 Btu.
The estimated costs for control are thus low enough that they should
not seriously impact the cost of electric power from coal.
Underground Gasification
There is a.possible alternative to the mining of coal underground with
its attendant problems of worker health and safety. , This involves the
process of in-situ underground gasification.
232
-------
In practice, the process of underground gasification would consist of
1. An arrangement, in accordance with the actual technique to be em-
ployed, of bored holes on a grid system from the surface to the coal
seam, for (a) the introduction of the gasifying medium and (b) for
conduction of the resulting fuel gas back to the surface.
2. Use of some procedure for rendering the coal bed porous between the
intake and offtake ends of the grid system. Such fracturing along the
coal seam has been investigated by several means. One method is termed
electrolinking process results in gradual carbonization in a cross-
section of the seam between the two points, thus resulting in fractures
and pores for the passage of gases and allowing the necessary consecu-
tive combustion and reduction reactions to occur. Hydraulic fracturing
also has been investigated. Directional drilling and mining of passage-
ways have been studied. Such fracturing is necessary co permit the
necessary solid-gas reactions to occur, without (it must be stressed)
permitting the bypassing of unreacted or only partially reacted gases
to the offtake.
3. After preparation and fracturing, the coal is ignited at the air (or
oxygen or air-oxygen mixtures) intake by burning some fuel until a path
at proper temperature reached the offtake, with discard of the offtake
gases. The gasifying air is admitted and, hopefully, the collection of
the offtake fuel gas begins.
In work on underground gasification in the past, the gas produced, even
with partial]y enriched air, had heating values in the range of about
80 to 100 or slightly more 3tu/cu ft.(E-9) Even with oxygen, this value
did not reach more thau about. 125 Btu/cu ft in the Bureau of Mines-
Alabama Power Corpany tests. The cost of oxygen was deemed prohibitive,
and in the Bureau's study of underground gasification costs the assump-
tion for a commercial venture assumed the use of air and a fuel gas
heating value of 100 Btu/cu ft.(E-lO) Underground gasification appears
to be thermally inefficient. The Bureau lists thermal efficiencies to
'be about 15 percent with hydraulic fracturing and up to 38 percent with
an electrolinking fracturing system.(E~10)
Figure E-2 represents an attempt to depict a module representing the
underground gasification process. The choice of base units is affected
by the grid distance between intake and offtake in two directions, the
thickness of the coal seam, and the density and/or heating value of the
coal. We have chosen in this instance to use a unit based on the mil-
lions of Btu per foot of path (between intake and offtake).
Status of Underground Gasification
At one time, principally in the late 1940's and 1950's, there was in-
terest in underground gasification in the United States, England, Japan,
Russia, and several other countries in Europe. In the United States,
pilot-plant experiments were carried on through 1959 under a joint
233
-------
Input
Kvhr for electroUnking
(or for compressed
Alr at perhaps 40 psig_
for gasification
1,000,000 Btu,
in situ coal
—•J380.000 Btu in offtake gas
—£airyovcr dust (variable^no
data)
—jS02 in product eas (about 907, ^->.
of sulfur in the coal (3)
—jDeconposition tarry materials;
no daca (H
This amount of gas produced is based on U.S. Bureau of Mines information,
1C 8020, 1961. If hydraulic fracturing wore employed, the same source
specifics a thermal efficiency of 15.8 percent and a consequent output
of 150,000 Btu per one million Btu in the in situ coal.
Amount of carryover dust from underground is not given in the Bureau of
Mines work. Should be small and readily removable.
The SO, In the p,as depends on the sulfur content of the coal. Most
of the sulfur in the coal gasified would appear in the offtake gas. The
S02 would have to be largely removed if the underground operation were in
areas of high sulfur coal. But the large part of the western coals, with-
low sulfur contents, could be gasified underground without removal of S02
from the product gas.
Some tar-forming naterial probably will be in the offtake gas. American
work has not gone far enough to permit reasonable determination of the
amount present. The amount could vary with the method and grid scheme.
Russia has reported the use of washers and de-tarring equipment.
r •) INPUT-OUTPUT DESIGNATION FOR AN UNDERGROUND GASIFICATION MODULE
™t»
234
-------
effort by the U.S. Bureau of Mines and the Alabama Power Company. The
results of the work., overall, were not very promising and the project
was ended in 1959. Many problems were encountered, including chat of
producing a porous passageway through the con] bed for continuous oper-
ation, melting of the associated rock and'blocking of passageways, by-
passing of the reaction gases, c:tc.
By the early 1960's, the experimental work in the United States and
England had been concluded, but some activity was still being reported
in Russia, Czechoslovakia, and Japan. So far as is known, experimental
work in Japan and'Czechoslovakia.is not now being carried on. A recent
report by Arthur D. Little, Inc., to the Bureau of Mines (1972, pub-
lished) on underground gasification concluded that the process is tech-
nically feasible but unproven economically after many countries had
devoted many years of research, chiefly during the period 1945 to 1960.
Since that time few underground tests have been reported and no sig-
nificant research is believed to be under way anywhere through the first
half of 1972.
However, it was reported in the fall of 1972 that the Bureau of Mines
had decided to take another look at underground gasification.(£-11)
By late this year, the Bureau will have drilled into a seam of coal in
Wyoming, at a depth of 400 feet, with the purpose of investigating the
production of a "low-sulfur, high-energy gas" from coal in place. Most
certainly seam fracturing and new techniques will be studied, since
almost all workers in the field of in-situ underground gasification
have stated such to be a requirement justifying further work in this
field.
As far a<; the large deposits of low=-rank coals are concerned, the en-
vironmental problem from sulfur dioxide release from the underground
produced gas upon burning would be minimal, since such1 coals are lev; in
sulfur (much in the 0.5 to 0.8 percent range). Dust loadings would
probably be low, but dust-removal equipment is available. Thus, the
ienvironmental emission on the surrounding area might be relatively
low. However, gas produced in Russia has been with normal gas cleaning
equipment—scrubbers, water-coolers, electrostatic de-tarrers, and some-
times sulfur removal, and, if a commercial underground gasification
process becomes commercial in this country, the same cleaning proce-
dures probably would have to be used.
It is impossible to judge the eventual technical and economic success
with respect to the planned investigative effort in the current Bureau
of Mines program. In any event, even initial success within ensuing
years probably would not lead to any commercial ventures for at least
the next 10 years.
During the underground gasification tests in the United States, the
Bureau of Mines is believed to have spent about $2.5 million.(E-12)
The amount spent' by the Alabama Power Company might have totaled up to
235
-------
a million dollars, but this is only an estimate. In addition, one
company, Elcctrofrou Corp., spent a considerable sum to develop and
apply an elcctrolinking system, not only for use in underground gasi-
fication, however.
Up through 1959, the British had spent some $4.5 mi.Uion on underground
gasification tests.(E~i2) Work was stopped shortly thereafter, Amounts
spent in investigative effort in Russia, Japan, Czechoslovakia, and
elsewhere are not known.
To develop underground gasification for use in the United States would
represent a large investment in tine and money. Judging from past ex-
penditures and the lack of good results, to reach commercial status with
a feasible and economic system would require many years of intensive
effort and the expenditure of large sums of money, many tens of millions.
£ostoj[ Producing Gas by Underground Gasification
In 1961, the Bureau of Mines published estimates of the cost of gas pro-
duced by underground gasification.(E~9) The resulting estimated costs
were for two seam fracturing systems: (1) elcctrolinking, and (2) hy-
draulic fracturing. The assumptions rcade included: (1) coal seam thick-
ness, 3 feet; (2) distance between boreholes, 155 feet; (3) distance
between paths, 50 feet; and (4) 100 paths operating simultaneously dur-
ing gasification. For the conditions stated, a 60,000 kw plant oper-
ated at a base load for 20 years would require a tota.1 of 4 square miles
of coal acreage.
Katell and Fabor(E-lO) developed equations for gasification costs in
which the main variables were (1) thickness of overburden, (2) gasifica-
tion air dnlet pressure, (3) electric power cost, and (4) thermal effi-
ciency. Table E-l summarizes the Bureau's estimated cost (1960 dollars)
per million Btu in the produced gas with assumed power costs of $0.01
per kwhr, a gasification air pressure of 40, a production rate of 18.7
billion Btu per day, and 200 feet of overburden.
The total operating costs shown in Table E-l, 62.1 cents per million
Btu for gasification employing electrolinking, and 77.1 cents per million
Btu for hydraulic fracturing. These costs would increase by about 10
cents per million Btu (hydraulic fracturing) or 15 cents per million Btu
(electrolinking) if power costs per kwhr were doubled.
The costs listed do not include anything for processing the gas after
recovery for removal of sulfur, tarry material, or dust, nor is the
cost of the acreage in terms of mineral rights, outright purchase, or
royalties included. Thus, based on the results of the Bureau estimates,
the estimated cost of the gas produced could well reach $1.00 per mil-
lion Btu when acreage costs, increased power, labor, and material costs,
and some gas cleaning costs were added under today's economic conditions.
On the other hand, improved techniques which could result from further
research and development might tend to offset some of the factors in the
236
-------
overall cost pattern.
TABLE E-l. UNDERGROUND GASIFICATION, ESTIMATED OPERATING
COSTS
Item
Site preparation and development
Power required for' linking
Labor required for linking
Electrode and pipe cost
Hydraulic fracture
Borehole drilling cost
Borehole pipe cost
Piping header cost
Transmission pipe cost
Linking air cost
Gasification air cost
Operating labor cost
Total Cost
Cents Per
Electrolinking
1.1
10.8
5.4
12.9
4.8
0.8
1.6
22.0
2.7
62TT"
Million Btu
Hydraulic
Fracturing
3.8
7.7
15.4
12.3
0.8
1.6
10.8
22.0
2.7
77.1
Note: Assumptions:
Power cost, $0.01 per kwhr
Gasification air pressure, 40 psig
Gas production rate 18.7 billion Btu per day.
References
E-l. Tybout, Richard A., "A Cost-Benefit Analysis of Mine Drainage",
Second Symposium of Coal Mine Drainage Research, May 14-15, 1968,
Pittsburgh, Pa., pp 334-371.
E-2. Dee, N., Stacey, G. S., Bowman, J. H., and Qasira, "Methods of
Financing the Cost of Preventing Controlling and Abating Water
Pollution—Modified Nonpoint Source Pollution", Battelle Report
to Water Quality Office, Environmental Protection Agency, April,
1971. Contract No. 14-12-957.
E-3. Young, W. H., "Thickness of Bituminous Coal and Lignite Seams
Mined in 1965", U.S. Bureau of Mines 1C 8345, 1967.
E-4. Westerstrom, L. W., "Coal—Bituminous and Lignite", Preprint,"
1970, Bureau of Mines Minerals Yearbook, 1972.
-237
-------
E-5. U.S. Environnental Protection Agency, "Legal Problems of Coal
Mine Reclamation", March, 1972.
E-6. U.S. Department of the Interior, "Surface Mining and Our Environ-
ment, 1967.
E-7. Private communication with EPA staff.
E-8. Private communication, R. Hill and L. Grimm, Environmental
Protection Agency, Cincinnati.
E-9. Fies, Milton 11., and Schroeder, U. C., "Underground Gasification
at GorGas, Alabama", Preprint M1219-'47, paper presented at joint
ASME-AIME meeting, Cincinnati, Ohio, October 20-22, 1947.
E-10. Katell, S., and Faber, J. H., "Estimated Costs of Gasifying Coal
In Place: A Study Based on Electrolinking and Hydraulic Fracturing
ExpeririGnts of the Bureau of Mines", U.S. Bureau of Mines, 1C
8020, 1961.
E-ll. National Coal Association Coal News. September 29, 1972, p 3.
E-12. Anon, "Needed: New Gasification Technology", Chemical Engineering
February 23, 1959, pp 60.
238
-------
APPENDIX F
GAS PIPELINE AND UNDERGROUND GAS STORAGE
Table of Contents
Gas Pipelines 240
Underground Gas Storage 240
References 242
239
-------
APPENDIX F
GAS PIPELINE AND UNDERGROUND GAS STORAGE
Gas Pipelines
The gathering of natural gas from gas wells, and their transmission to
processing centers and to regions of distribution for consumption is
done by means of pipelines. An integral component of the transmission
circuit are pumping stations and wherever possible natural underground
gas storage facilities used primarily by gas distributors during low
consumption periods.
Environmental Emissions
Other than the need to clear and maintain an overland easement, the
pipelines in the continental United States present a minimal impact on
the surroundings they traverse (after the initial installation). The
operation of such pipelines, however, does present some environmental
emission parameters. If only the major transmission lines leading
from the processing centers to remote distribution centers near centers
of population are considered, movement of the gas at 750 psia through
the pipelines requires strategically located compressor stations to
maintain such pressures. The compressors are operated by gas engines
which use as fuel the natural gas they are compressing. The amount
of fuel consumed in 1970 to transmit 17.809 x IQl2 ft* of natural gns
to various distribution centers was 0.743 x 10* ft3 or about 4.1 per-
cent. (*'*•) fhe emission from such an operation is primarily NOX as a
result of the internal combustion of natural gas in the engines and is
reported to be about 7300 Ib NOX per 106 ft3 of natural gas consumed.(F~
At this rate about 0.304 pound of NOX per 1000 ft3 of natural gas pumped
is emitted.
As the need (anci cost) of natural gas continues to increase, more ..
"naphtha" is being used for fuel to operate compressor stations.
With the combustion of a higher molecular weight hydrocarbon larger
quantities of pollutants other than NOX will be emitted from engines
designed for using natural gas. As this trend expands, techniques
presently being developed for the gasoline automobile engine will have
to be employed to meet the upcoming stringent Federal emission require-
ments for such engines.
Underground Gas Storage
In various parts of the country, natural gas companies operate under-
240
-------
ground gas storage fields. These fields are composed of various types
of porous rock formations which are suitable to act as storage
reservoirs.
The major use of these reservoirs is to smooth out seasonal fluctuations
in gas usage. Thus, during the summer, when gas requirements are
relatively low, gas will be pumped down into the reservoir. In the
winter, this gas is then available to augment the normal gas flow.
In addition to this major use, the gas reservoirs contain quantities
of valuable hydrocarbon liquids which arc often brought up with the gas.
After separation, these liquids can be sold for additional revenue.
The two major environmental emissions of the gas storage are (1) gas
pressurizing and (2) leaks.
Environmental Emissions
Gas Pressurising. The gas to be stored in the reservoir is pressurized
to a higher pressure than the final use pressure. The reason for this
is that there is considerable pressure drop as the gas flows through
the reservoir into the delivery system. Typically, 1800 psi is used
to fill the reservoir, the delivery pressure upon withdrawal is about
650 psi, and the gas is further throttled to about 550 psi pipeline
pressure.
Emissions associated with the compression of gas from 550 to 1800 psi
during the summer (about 6 months) can be considered an environmental
emission. As natural gas is readily available to the storage site,
gas engines are used to power the compressors. It can be calculated
that about 0.014 ft-' of gas must be burned to compress 1 scf of natural
gas from 550 to 1800 psi (overall efficiency of 25 percent). The
combustion of this gas would result in 0.0006 Ib of NOX released to
the atmosphere per scf of natural gas stored. Calculations arc based
'on an emission factor of 4300 Ib of NOX per 106 ft3 of gas.^'1' For
a typical flow of 200 x 10& cubic feet per day injected into storage,
a total of 600 tons of NOX would be released into the atmosphere daily.
Gas Leakage. Several gas storage reservoirs in the country are confronted
wirh gas leakage vertically. This gas can accumulate in the upper for-
mations of the reservoir, and even escape into the atmosphere resulting
in a pollution problem, as well as a safety hazard. Bernard and Holm TF-3)
have studied the use of foaming agents and found that one application
of about 0.3 pound of these agents per barrel of pore space would result
in a 99 percent decrease in the leakage problem.
Assuming a 10 percent by volume pore space, and a cost of $1.00 per pound
of foam, control of gas leakage would cost $0.04/1000 scf of gas.
241
-------
References
F-l. Private Communications, R. Bruce Foster, Manager, Industrial
Planning Institute of Gas Technology, Chicago, Illinois.
F-2. A Compilation of Air Pollutant Emission Factors (Revised), EPA
Report No. AP-42 (February, 1972).
F-3. Bernard, G. G. and Holm, L. W., "Model Study of Foam as a Sealant
for Leaks in Gas Storage Reservoirs", Soc. of Pet. Eng. J., p 9
(March, 1970).
242
-------
APPENDIX G
LNG TRANSPORTATION, HANDLING, AND STORAGE
Table of Contents
Summary 244
LNG Tankers 245
LNG Port Facilities 245
LNG Storage 245
XNG Gasification . . 246
References ' 246
243
-------
APPENDIX G
LNG TRANSPORTATION. HANDLING. AND STORAGE
Summary
Liquefaction of natural gas in overseas locations having a substantial
surplus such as Algeria, Libya, Venezuela, and Alaska and shipment to
gas-short areas such as Japan, U.S. East Coast, Spain, and Italy is
increasing in popularity. For the United States, LNG is being used
mainly for peak shaving, that is, augmenting pipelined gas during
times of peal; demand. Thus, the high cost has only a small effect on
the overall average price.
Pollution due to the transportation, storing, and gasification of LNG
is negligible and energy requirements are small. Pollution and energy
costs of liquefaction, storage, and transportation on foreign soil and
the high seas are beyond the scope of this study.
Environmental Impact of Spills
The environmental impact of spills of LNG needs to be considered,
realizing that spills are more of a safety hazard than pollution hazard.
The hazard is threefold—freezing, asphyxiation, and fire. Spills on
ground would result in rapid evaporation initially that would cool the
ground and slow the boiling. Plants and animals frozen in the process
probably would be killed or injured. Spills into water result in very
rapid boiling. Under certain conditions, a spill on water can produce
an .explosion-like eruption, but recent studies indicate that these
eruptions are not likely to cause any damage. The gas released in a
LNG spill, principally methane, does not support life and thus can be
suffocating. Large spills can give a cloud of gas that can spread to
an ignition source and then burn. As a matter of fact, this happened
in one of the first LNG installations in the 1940's, killing more than
100 people. A mixture of vaporized LNG and air that is within the
flammable limits will burn if ignited. Therefore, air is rigorously
excluded from storage tanks. Obviously the spill of a tanker load of
LNG resulting in a fire could result in a catastrophe. Since the safety
hazard is high, elaborate precautions are always taken so that environ-
mental impact multiplied by the probability of an incident is quite
low. To date there is not enough experience with LNG to quantify this
further.
244
-------
ING Tankers
Modern LNG tankers carry 0.5 to 1.5 billion scf of gas in liquid form
at near-atmospheric pressure, utilizing well-insulated tanks to main-
tain the cargo at its boiling point (near minus 260 F) with a small
boil-off rate. Future tankers will be larger with a 2.76 billion scf
tanker already on order. If the natural gas is available r.t 5-10 cents
per million Btu, the value of LNG is 30-40 cents.loaded aboard ship
and 60-70 cents delivered to the U.S. port. ^ " ' The field cost of
gas is expected to rise and the cost of shipping is expected to decrease
as economics of scale are realized. The value of LNG delivered but not
unloaded in 1990 is estimated by Battelle to be 70-90 cents per million
Btu. On the loaded voyage, the fuel is primarily boil-off (0.3 percent
of the cargo per day), supplemented by fuel oil. On the return trip a
small amount of LNG is carried so that evaporation will keep the tanks
chilled. This boil-off supplements the fuel oil used on the return
trip. The pollutants consist primarily of SCh from sulfur compounds
in the fuel oil. Pollution in the United States will occur only in
the last few hours of the voyage, 2 days in port, and the first few
hours on departure. The value's will be on the order of 10"^ pounds
of pollutants per million Btu of LNG delivered and hence have been
judged .negligible.
LNG Port Facilities
The port facilities consist of docks, storage, gasification, and
general administrative and maintenance facilities. Storage and gasi-
fication are treated as separate modules elsewhere.
The docks, administrative, and maintenance facilities are negligible
energy users and pollution sources. Spillage and release to the
atmosphere is kept to a minimum for safety's sake. The land use is
small compared to storage tanks and gasification facilities-and
difficult to relate to throughput of LN'G.
LNG Storage
The simplest situation is in a base-load LNG plant where gasification
is more or less continuous. Here storage is related to expected rate
and size of shipments, and the boil-off of 0.1-0.3 percent per day is
merely compressed and added to the mains. On the other hand, a peak
shnving unit may receive only a few shipments over the period December
to May and must keep it on hand until needed. The tanks will hold on
the order of 10 days' supply. Here it is essential to keep losses to
a minimum and to rcliquofy the boil-off. The terminal storage for a
base load plant will add about 40 cents per million Btu to the cost of
LNG. Peak shavinq storage will add an additional 60 to 90 cents per
million Btu. (G-i'
245
-------
LNG storage does not produce pollution or use significant amounts of
energy. Compressors and pumps required will use electricity or fuel
but will not have much impact on the
LNG Gasification
Gasification plants can supply heat for vaporization in three ways: by
warning with ambient air (through appropriate heat exchangers), hy
warming with ambient wster, or by burning fuel. Current U. S. practice
is to burn natural gas, achieving about 90 percent efficiency (that is
11 percent extra heat). If flame temperatures are kept below 2000 F
so that NOX is not formed, there is essentially zero pollution. This
ignores power used for pumps and the pollution produced by them. The
gas is produced at low gauge pressure and is compressed for use in
city gas mains.
The value of vaporized gas is $1.05-$1.15 per million Btu for a base
load operation (none in the United States at present) and $1.70-$2.20
for a peak shaving operation (assuming 5-10 cent gas in Algeria) /G" D
By 1990 the field cost of gas will have risen, transport will be cheaper,
and liquefaction facilities will be cheaper per unit gasified due to
economies of scale and accumulated experiences. Approximately the
same price can be expected for gas from each type of operation in 1990
as today.
Currently no attempt is made in the United States to utilize the cooling
power due to latent heat of vaporization available in the gasification.
When large base-lo.nd LNG facilities are built, this probably will be
done, lowering the heat input, pollution, and cost. However, this puts
the gas utility into a nonregulated business, requires additional
capital, etc. Thus, the data developed here represent a "worst case"
for 1990.
Reference
G-l. Paul C. Johnson, Technology and Economics of Transporting and
Storing LNG, American Institute of Chemical Engineers, Dallas,
Texas, February, 1972.
246
-------
APPENDIX II
OIL TRANSPORTATION ON INLAND WATERWAYS
Table of Contents
Summary 248
Technical and Economic Characteristics 248
Environmental Emissions 248
Oil Spills . . 251
References 252
List of Tables
H-l. Petroleum and Petroleum Products 250
247
-------
APPENDIX H
OIL TRANSPORTATION ON INLAND WATERWAYS
Summary
Inland waterways provide a major economic means of transporting petro-
leum and petroleum products. In 1971, 211.5 million tons, or almost 40
percent of the total freight traffic on inland waterways was these
products. The average towboat handling petroleum and petroleum products
has from 3200 to 4500 horsepower (hp) and can push barge tows of from
15,000 to 25,000 net tons, although larger towboats up to 9000 hp capable
of'handling tows up to 50,000 net tons are in use.
Most of the towboats are powered by diesel engines, so air emissions are
low per unit cf product handled. Other air emissions are from release
of hydrocarbons during the loading and unloading of barges. The major
pollution threat is the possibility of major oil spills that could occur
from a disaster to one or more barges in a tow. There is a continuing
improvement in the development and maintenance of river channels, the
handling of river traffic, and the design of barges and towing methods.
The safety record of handling petroleum and petroleum products has been
good. Frequency and severity of injuries are in the same range as pipe-
line transportation of oil and gas. Land requirements are primarily
those lequired for product storage at the various terminals.
Technical and Economic Characteristics
In 1971, transportation on inland waterways of the United States (exclu-
sive of the Great Lakes) amounted to 560.5 million tons. Crude oil and
various petroleum products accounted for about 211.5 million tons, or
37.7 percent of the total net movement broken down as follows:
1Q6 Tons
Crude petroleum
Gasoline, including natural gasoline
Jet fuel
Kerosene /a)
Other petroleum and coal products
(a) Residual fuel oil is believed to be the primary component.
248
-------
In comparison, net movement of bituminous coal and lignite amounted to
109.5 million tons, and sand, gravel, and crushed rock amounted to 75.4
million tons.
Breakdowns in movement of crude petroleum and petroleum products by major
inland waterways are shown in Table H-l.
Barge units navigate about 25,000 miles of inland waterways. The
towboat handling petroleum products has from 3,200 to 4,500 horsepower
and can push bargetows of from 15,000 to 25,000 tons. Larger towboats
with about 9000 hp can handle bargetows up to 50,000 tons. Upstream
speeds on the Mississippi/Ohio Rivers of from 5 to 8 miles per hour can
now be attained with maximum loads. (H~2' This would indicate a horse-
power requirement of .18 to .21 hp per ton of cargo.
As of January L, 1971, there were 3.185 tank barges, having a cargo
capacity of 6,330,298 net tons.(H'1) Of these, 2,581 with a cargo
capacity of 4,753,480 net tons operated on the Mississippi River System
and Gulf Coast Intracoastal Waterway; 581 with a capacity of 1,521,222
net tons operated on the Atlantic, Gulf, and Pacific Coasts; while 23
with a capacity of 55,596 tons operated on the Great Lakes.
The average size of tank barges is about 2,000 tons. Assuming an average
tow of 20,000 tons, the transportation of 211.5 million tons of petroleum
and petroleum products would require 10,575 tows. Based on total tank
barge capacity and assuming a 90 percent operating efficiency, the number
of tows that could be operated on inland waterways at any given time
would be about 283 (6,275,000 x .90 i 20,000). On the same basis, the
movement of 211.5 million tons of petroleum products with barge capacity
of 6,275,000 tons operating at 90 percent efficiency would require about
37.5 round trips per barge, or a total elapsed time of slightly less than
10 days per round trip.
No figures have been obtained for average distance per trip for petro-
•leum and petroleum product shipments. However, average distance per
trip for all inland waterways cargo is 325 miles. This would indicate
a round trip distance of 650 miles for petroleum and petroleum product
barges.
Environmental Emissions
Using the average fuel consumption rate for motor ships of 0.34 pound/
hp-hr,(H'3> and a horsepower requirement of 0.18 to 0.21, the fuel con-
sumption would be 0.0612 to 0.0714 pound per hour per ton of cargo.
Assuming an average speed of 6 mph, the fuel consumption per mile per
ton would be 0.0102 pound to 0.0119 pound. Crude oil has an average
volume of 6.77 barrels per ton making a fuel consumption per barrel
mile of from 0.00151 pound to 0.00175 pound.
249
-------
TABLE H-l. PETROLEUM AI!D PETROLEUM
PRODUCTS (Millions of Tons)
Inland Waterways
River Crude
Upper Mississippi
Mississippi 17.8
Ohio 8.0
Illinois Waterway
Calumet- Sa.; Channel
Allc&hony/Monongahela
Kanawha
Cumberland
Tennessee
Gulf Intcrcoastal
Waterway 34.5
Subtotal (60.3)
Houston Ship Channel 4.3
Black Warrior, etc. 1.0
Appalachula, etc.
James River
Gasoline
Kerosene
Jet Fuel
5.8
21.0
13.6
2.5
0.3
1.2
0.7
1.4
2.0
14.1
(62.6)
1.5
0.1
0.3
Other
Petroleum
and Coal
Products Crude
6.1
21.3 21.3
6.8
5.2
0.7
1.2
0.3
0.5
1.4
18.6
(62.1)
6.1 2.3
0.5
0.2
3.1
Ocean Cointr
Gasoline
Kerosene
Jet Fuel
3.9
0.1
0.1
10.9
Other
Petroleum
and Coal
Produces
8.7
1.4
0.3
0.1
9.9
Atlantic Intcrcoastal
Waterway (Norfolk
to St. Johns River) 0.3 1.0
Atlantic Intcrcoastal
Waterway (St. Johns
Rtvcr to Miami) 0.7
Delaware 2.0 4.5 11.2
Potomac 0.6 3.4
Chesapeake Bay 0.3 10.6 5.8
Hudson River 3.5 g.7
Mew York State
Barge Canal 0.7 1.6
Columbia 0.3 0.6
Sacramento 0.2 0.1
San Joaquin ___ 0.4
Total 67.9 85.2 105.5
NOTE: Duplication of movement exists.
47.6
0.3
71.5
7.9
0.3
1.3
1.4
25.9
0.1
20.4
2.6
4.2
2.6
0.4
50.7
Source: Inland Waterborne Commerce Statistics, 1971, The American Water-
ways Operators, Inc., Washington, D. C.
250
-------
Diesel fuel has a heating value of about 19,800 Btu per Ib so Btu require-
ments would be 29.9 Btu to 34.7 Btu per barrel mile. Assuming an average
Btu content of 5.8 million Btu per barrel of petroleum shipped, the Btu
requirements per million Btu would be 5 to 6 Btu per mile, or an average
round trip of 650 miles would require 3250 Btu to 3900 Btu per million
Btu of product transported, or an average of about 3575 Btu. The fuel
consumption while in port, assuming an average of two days in port per
trip and a consumption of 660 gallons per day of diescl fuel, would be
= 233 Btu per million Btu of Product. This would
*.w ^ *
indicate a total Btu requirement of about 3800 Btu per million Btu's of
product transported.
Oil Spills
Contamination of inland waters from oil is a major environmental problem.
Spills from barge accidents and losses occurring in loading and unloading
operations contribute only a small fraction of the Lotal pollution
occurring on inland waterways. During the short time period for this
study, quantitative data have not been found for the amount of oil con-
tamination caused by barge movement of petroleum and petroleum products.
If one assumed that the average loss per year per barge amounted to 1/10
of 1 percent of barge capacity, spillage would be about 6330 ton;;, or
0.03 percent of tonnage shipped annually. Assuming an average weight of
300 pounds per barrel, the spillage per barrel shipped would amount to
0.09 pound. For comparison, oil spills from pipeline shipments is esti-
mated to be 0.023 pound per barrel.
It should be recognized, however, that the potential threat of a major
spill from barge operations would be much more severe than the threat of
a pipeline incident. Individual batch movements of oil on inland water-
ways of up to 50,000 tons (350,000+ barrels) are comparable to tankers
used in U.S. trade. While the contents of individual barges are much less
and multicompartation with void spaces fore and aft are used, spills of
large quantities of oil are a constant threat requiring prompt action to
prevent major disasters from occurring.
The safety record in handling barge movement of oil has been quite good.
Frequency and severity of accidents in marine and inland waterways
operations are similar to those in pipeline operations.
Continuing improvement in the development and maintenance of river channels,
the handling of river traffic, and in the design of barges and towing
methods may be expected, which will tend to offset the dangers from
increased traffic on inland waterways.
Land use requirements for barge movements of oil are primarily for storage
at the various terminals.
251
-------
References
H-l. Inland Waterborne Commerce Statistics, 1971, The American Waterways
Operators, Inc., Washington, D.C.
H-2. Environmental Conservation, The Oil and Gas Industries, Vol. 2,
National Petroleum Council, February, 1972.
H-3. Environmental Protection Agency, Office of Air Programs, Compilation
of Air Pollutant Emission Factors (Revised), February, 1972.
252
-------
APPENDIX I
TRANSPORTATION MODULE FOR COAL AND OIL
TRANSPORT BY MIL, TRUCK, AND PIPELINE
Table of Contents
Page
Summary 254
Emissions 255
References 272
257
List of Tables
1-1. Data on Coal Transport From Various Production Districts. 257
1-2. Locomotive Load-Speed Cycle 258
1-3. Railraod Locomotive and Truck Emissions from Coal
Transport from Mine to Electric Utility 260
1-4. Environr.iental Impact Comparisons of Highway and
Railroad Transportation Modes 262
1-5. Projected Emissions from Transport of Coal for
Electrical Production % 266
1-6. Crude Oil Transported to Refineries by Stale and
District, 1970 267
1-7. Emissions from Diesel Driven Pimping Stations in Crude
Oil Pipe Lines 268
1-8. Projected Emissions from Transport of Oil for
Electrical Production 271
List of Figures
1-1. Fuel Supply Districts—Coal 256
1-2. Total Accident Predictions 263
1-3. Consumption of Bituminous Coal and Lignite, by
Consumer Class, with Retail Deliveries in the
United States 265
1-4. Designation of Petroleum Districts 264
1-5. Relation of Transport Modes in Crude Oil Transport. ... 270
253
-------
APPENDIX I
TRANSPORTATION MODULE FOR COAL AND OIL
TRANSPORT BY KAIL. TRUCK. AND PIPELINE
Summary
Assessment of the emissions from the transport of coal and oil by rail,
truck, and pipeline has been accomplished through an evaluation of the
fuel quantities and distances transported by the various transportation
modes, a determination of the power per quantity-mile of the transport-
ing device, and a correlation of these collected data to establish
actual air pollution emissions. Subjective data on transportation
accidents, construction and maintenance, land use, noise pollution, and
aesthetics are considered with reference to the transportation modes.
Of the 695.A million tons of coal shipped from the production districts,
495.8 millions tons or 71.3 percent is shipped by rail and the remainder
is shipped by truck, barge, and other transportation modes. Consequent-
ly, the rail transport of coal dominates the other transport modes.
Exhaust emissions into the air, particle tailings from the top of rail-
road cars, and land right-of-way appear to be the significant factors
associated with coal transport. Air emissions were calculated based on
the prime mover required to transport the coal. Basically, rail and
truck transport of coal is primarily dependent on petroleum products,
and no immediate alternates to the use of petroleum appear technically
or economically feasible. Emissions to the air of NOX, HC, CO, and S0£
were calculated for rail transport of coal resulting in 116.7, 9.07,
89.9, and 8.31 thousand tons/year of these pollutants exhausted to the
atmosphere, respectively.
Land use is perhaps the largest environmental factor associated with
coal transport. Land right-of-ways of 3760 square miles are currently
held by the railroads. Since 16 percent of the total material shipped
by rail is coal, 616 square miles of right-of-way may be attributable to
coal transport.
Crude oil is transported primarily by pipeline (77.4 percent) and the
remainder by water (21.5 percent), tank cars', and tank trucks. Of the
1.888 million horsepower required to operate the oil pumping stations,
1.43 million horsepower is developed from electrical power and the re-
mainder from gas and dicsel engines. Since the electrically powered
units contribute to the emissions more from a land-use and central power
station standpoint, the gas and diesel driven stations were analyzed on
the basis of emissions to the air.
254
-------
Future reduction in fuel consumption is likely provided engine efficien-
cies are improved. Conservatively, it is assumed that engine efficien-
cies will remain at the currant level and environmental changes occur as
a result of the greater demand for coal and oil transport. As a result,
the future projections of the emissions from the transport of coal and
oil are based solely on die demands projected for the electrical re-
quirements.
Emissions
Evaluation of the quantity of coal and oil and distance shipped by
various transportation means is required to determine the overall
emissions from the transport systems.
Coal
Distribution of coal is primarily accomplished by mil, barge, and truck.
Of the total production in 1970, 81.3 percent of the coal was shipped by
rail and barge, 12.2 percent by truck, 0.7 percent by all other means of
transportation; 5.8 percent of the 1970 coal production was used at the
mine in generating plants.U~iJ' The 0.7 percent transported by other
means .includes the transport of coal using slurries in pipeline sys-
tems. ^ The total production for 5601 active mines for 1970 yas
695,400,000 tons.^1"10) The locations of these mines are shovm in
Figure 1-1. The objective of the quantity-transport evaluations is to
combine the data to establish the ton-mile of coal transported by each
transportation means.
Battelle's Columbus Laboratories performed a study that related the
1975 transport of coal from the mines to specific areas of the United
States.C1"10) Table 1-1 shows the compiled data on the quantity and
distance shipped for each of the production districts. The percentages
'cited above were used to establish the ton-miles of coal shipped by
rail and truck. Quantities shipped by other means and by barge are also
included in the data given in Table 1-1. Note that the quantity of coal
shipped by rail and barge is 81.6 percent of the total with an assumed
split of 71.6 percent by rail and 10 percent by barge.
Unit Emissions Evaluations. Having established the quantity and distance
transported of the coal used in electrical production, establishment of
conversion factors is required to determine the physical emissions ex-
hausted into the atmosphere as a result of coal transport for electrical
power generation.
Data presented in the previous section established the quantity of coal
and the distance transported from each of the 23 production areas of the
United States. A conversion is needed to relate ton-miles of coal to
emissions of N0x, CO, HC, and S02. This is to be accomplished by assuming
255
-------
-.-- - • /.. - :,r--*C
FIGURE 1-1. FUEL SUPPLY DISTRICTS—COAL
-------
TABLE 1-1. DATA ON COAL TRANSPORT FROM
VARIOUS I'RODUCTION DISTRICTS
Production^'
District
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
•Total
»a' Reference
Reference
* Reference
Shipments Average
in Millions Mileage
of Tons
51.7
26.6
47.9
71.0
(No
13.4
25.6
198.9
62.4
73.4
27.1
0.8
27.6
0.2
11.7
0.9
7.7
11.8
12.8
5.1
8.9
.8.3
1.6
695.4
1-13.
1-10.
1-13 111 list rat
Shipped
175
200
116
208
Data A v
200
305
293
395
237
200
250
80
250
206
200
200
390
365
200
180
847
270
•i>« thi» tof.nl fi
Millions of Ton-Miles Shipped
Rail(c)
e
io6
6,450
3,793
3,961
10,530
a i 1 a b
1,911
5,567
41,552
17,574
12,402
3,864
143
1,574
36
1,718
128
1,098
3,281
3,331
727
1,142
5,024
303
126,117
,hinmf»nf fr
*arEe(c)
£
io6
904.7
532.0
555.6
1,476.8
1 e )
268.0
760.8
5,827.8
2,464.8
1,739.5
542.0
20.0
220.8
5.0
241.0
18.0
154.0
460.2
467.2
102.0
160.2
704.6
43.2
17,688.2
•nm mil an*1
Truck
1
io6
1,131
665
695
1,846
335
976
7,224
3,031
2,174
677
25
276
6
301
22
192
575
584
127
200
881
54
22,110
KnvrtA f- *i
Other
x
IO6
561.3
332.2
344.4
915.2
166.0
484.2
3,613.2
1,528.2
1,078.5
336.0
12.0
137.2
3.0
149.0
11.0
95.0
285.0
289.4
63.0
98.8
436.4
26.8
10,967.0
l*n ftl "> v*n*>.
81.3 percent,
the percentage of each was assumed to be 71.3 percent and 10 percent, respectively.
257
-------
a 3,000 horsepower requirement for each 2,000 tons of gross load in a
locomotive-train system.(I~8) At an average speed of 44 mph, a conver-
sion to train horsepower-hour from gross ton-miles may be established as
follows:
3.000 hn
15,000 g tons] |_44 mi/hr3
0.0341
hp-hr
ton-mi
for maximum power conditions. Derating this figure to account for the
percent of time at the various throttle positions is required and Table
I~2 illustrates the proposed load-speed cycle for locomotive-emissions
testing that can be used for this purpose.
TABLE 1-2. LOCOMOTIVE LOAD-SPEED CYCLE
(1-16)
Throttle
Position
8
7
6
5
4
3
2
1
Idle
Dynamic Brake
Engine,
rpm
900
815
730
645
560
480
395
315
315
"
Percentage of Rated
Horsepower, approx.
100
86
86
51
35
23
12
5
0.75
3
Percentage
of Time
30
3
3
3
3
3
3
3
41
8
Excluding the idle and brake periods, the load factor or the average
horsepower divided by the maximum horsepower is 0.749. In addition
to this load factor, a relationship between the gross-to-net-weight
ratio is required. Data from the American Railroad Association reveal
that the ratio of average gross tonnage to average net tonnage is
2.3481.(*~8) AS a consequence, the 0.0341 hp-hr/gross ton mile can be
converted to a usable factor to be directly applied to the accumulated
ton-mile data by applying the load factor and gross-to-net weight ratio
as follows:
10.0341
hp-hr
n ton-mi
H2.3481
n ton
][0.74 9] = 0.0599
hp-hr
ton-mi
Emission estimates on railroad locomotives of 15.43-tons of NO per
hp-hr, 1.213 tons of HC per 106 hp-hr, 11.9 tons of CO per lO^p-hr and
1.1 tons of S02 per 10° hp-hr have been recently reported.Cl-16) Using
these data and the conversion factor 0.0599 hp-hr/ton-mi as presented
258
-------
above, together with the data presented on Table 1-1, provides the
quantity information required to formulate the actual emissions result-
ing from the transport of coal; these calculated data are presented
under the railroad emission section of Table 1-3.
Unit emissions as a result of coal transport by truck to the electric
utilities requires an evaluation of the horsepower-hour necessary to
ship a quantity of coal a given number of miles. For a truck with a
gross vehicle weight of 60,000 pounds, the level-road horsepower to
maintain a 50 mile per hour speed is 270. Applying these'data to
establish the truck horsepower from gross ton-miles results in the
following:
hp Required hp-hr
(Vehicle Weight) (Velocity) ~ g ton-mile
Using the values stated above, the conversion factor is 0.15 hp-hr/g ton
mi at 60 mph and 0.107 hp-hr/g ton mi at 50 mph. The average speed of
trucks on main and rural highways in 1968 is 54 mph, and on this basis it
is assumed that 40 percent of the travel time is at 60 mph and 60 percent
of the travel time is at 50 raph. Taking a weighted average, the conver-
sion factor of ton-miles to horsepower-hour for trucks becomes
(0.107) (60) + (0.15) (40) _ hp-hr
100 ~ u-x^ g ton-mile
This figure is based on gross tonnage of the vehicle weight as opposed
to net tonnage. As a result, an estimated gross-to-net weight ratio
must be determined. Calculations in Reference 1-8 indicate that the
gross-to-net weight ratio for trucks is 2.1531. Therefore, the conver-
sion to be used in the emission calculations is
[0.1242 hP"hr .H2.1531 £-£S£ ] = 0.267 hhp"hr,
g ton-mi n ton „ n ton-mile
Applying this conversion factor to the truck data shown in Table 1-1, the
resulting horsepower-hour required to transport the coal quantity a given
distance as designated is calculated .and shown in the truck section of
Table 1-3.
Reported truck emissions of the various emissions are 11.6 tons of
HC + NOX per million horsepower-hour, 6.6 tons of CO per million horse-
power-hour, and 1.1 tons of S02 per million horsepower-hour.(*~°' Using
these data and the horsepower-hour data determined above, actual truck
emissions resulting from the transport of coal may be calculated. The
results of these calculations are shown under the truck emissions data
in Table 1-3.
259
-------
TABLE 1-3. RAILROAD LOCOMOTIVE AND TRUCK EMISSIONS FROM
' COAL TRANSPORT PROM MINE TO ELECTRIC UTILITY
«SJ
s
Hp-Hr. Required to Move
the Ton-Kile of Coal of
Production
District
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Table 1
Rail
386.3
227.2
237.3
630.7
114.5
333.5
2,489.0
1,052.7
742.9
231.5
12.0
94.3
2.2
102.9
7.7
65.8
196.5
199.5
43.5
68.4
300.9
18.4
Truck
302
178
186
493
( N o
89
261
1945
823
580
181
7
74
2
80
6
51
154
156
34
53
235
14
Emissions
(103 Tons/Year)
Rail
NO
X
6.00
3.50
3.65
9.71
Data
1.76
5.14
38.30
16.20
11.40
3.56
0.18
1.45
.03
1.58
0.12
1.01
3.02
3.07
0.67
1.05
4.63
0.28
HC
0.46
0.27
0.28
0.76
Aval
0.14
0.40
2.99
1.26
0.89
0.28
0.01
0.11
-
0.12
0.01
0.08
0.24
0.24
0.05
0.08
0.36
0.02
CO
4.60
2.70
2.82
7.51
1 a b 1 e )
1.36
3.97
29.60
12.50
8.84
2.75
0.14
1.12
0.03
1.22
0.09
0.78
2.34
2.37
0.52
0.81
3.58
0.22
so2
0.42
0.25
0.26
0.69
0.13
0.37
2.74
1.16
0.82
0.25
0.01
0.10
-
0.11
0.01
0.07
0.22
0.22
0.05
0.08
0.33
0.02
Truck
NO + HC
3.5
2.1
2.2
5.7
1.0
3.0
22.6
9.5
6.7
2.1
0.1
0.9
-
0.9
0.1
0.6
1.8
1.8
0.4
0.6
2.7
0.2
CO
2.0
1.2
1.2
3.3
0.6
1.7
12.8
5.4
3.8
1.2
-
0.5
-
0.5
-
0.3
1.0
1.0
0.2
0.3
1.6
0.1
so2
0.3
0.2
0.2
0.5
0.1
0.3
2.1
0.9
0.6
0.2
-
0.1
-
0.1
-
0.1
0.2
0.2
-
0.1
0.3
Total
7.554.4
5903
116.30
9.07
89.90
8.31
68.5
39.0
6.5
(a)
Based on emission factors from Reference 1-8.
-------
Related Factors. Physical emissions shown in Table 1-3 directly reflect
the environmental changes that occur with respect to the air pollution
due to the transport of coal and oil. Additional factors should also be
considcred--for example, spillage, transportation accident potential,
road and railway construction, right-of-way factors, noise pollution,
effective land use, ecological factors, aesthetics, and the social well
being. Most of these factors arc not subject to quantitative analysis
and as a consequence only a relative comparison between railroad and
highway environmental factors is attempted.
Major environmental factors caused by railroad and highway transportation
listed above have been compared on a relative basis with respect to con-
struction, right-of-way, and land use. The primary areas of comparison
include ecological factors, water pollution, air pollution, land pollu-
tion, noise pollution, aesthetics, and social well being. Reference 1-8
has completed this type of evaluation, and the results are shewn in
Table 1-4. The general environmental indicators are listed at the top
of the table while environmental factors are listed on the left side of
the table. If a comparison is established for the various factors, it is
an indication that a major impact on the environment exists from both
modes of transportation, and that the impact of one mode of transporta-
tion is greater than the other. In the event that a blank occurs on the
table, no differences exist with respect to the major environmental
factors.
The spillage of coal from either the railroad car or from the truck in
the form of dust blown from the top of the load has also been considered.
The coal companies are conscious of this factor since it results in a
direct financial loss. As a consequence, several methods are employed
by the transporting companies to minimize dust loss. Chemicals applied
to the top of the load and load topping with an appropriate type of coal
are examples of the current methods employed to prevent dust loss.
Environmental effects resulting from accidents can be compared based on
•the number of accidents per year by the railroads and by highway trucks.
Figure 1-2 shows the total number of accidents predicted for the rail-
roads and motor carriers or trucks from 1956 and projected until 1980.
In brief, accidents involving trucks are more frequent than those in-
volving trains but the quantity of material involved in a single accident
is significantly larger in the latter case.
With respect to spillage, transportation accident potential, road and
railroad construction, right-of-way factors, noise pollution, effective
land use, ecological factors, aesthetics, and social well-being, it is
expected that increased energy needs existing in the United States will
result in a proportional increase in the environmental factors. As a
consequence, only the effects of increased transportation due to the
electrical generation demands will be considered for future projections
of environmental factors associated with the transportation of coal.
261
-------
TABLE 1-4.' ENVIRONMENTAL IMPACT COMPARISONS OF
HIGHWAY AND RAILROAD TRANSPORTATION MODES
10
O*
to
Ecological
Causes cf Impacts Factors
A. Construction. Operation. 6 Disposal
1. Materials used In manufacture H > R
2. Operation
a. Exhaust
b. leaks end spills R > H
c. Llr.hts
6. Stop and stare
3. Roods transported
a. Hjzardous R > K
b. Other bulk cargo
4i Disposal
B. Right of Ujy (Adjacent/Operations!)
1. Materials used In construction H > it
2. Construction operation
3. Locatlonal consideration!
a. lllj.'way/rall
b. Dr.iln.ijji:
C. Liphtlnn
4. Maintenance and repair H » R
C. Land Use
1. Direct (temlnals. repair.
refill'! ing)
2. Indirect
(Adjacent land uses) H > R
Pollution
Social
Hunan
Air Uater Land Noise Aesthetic Interest
11 > R II > R
H » R H
R > H R > H R
H
H > R H > R H
R > H R » H
H > R R > R H
H » B H »> R H
K>R H>R H > R H > R H
H
H > R H
H » R H > R
R > R R > H R
H
> R H > R
» V
> R
> R
>» R
» R
> R
» R
> R
> K
» R H > R
Veil Ee'.nt
HuTian
Betteraent
H » R
H » R
H > R
H >'R
H » R
R > R
X > R
Key
H Highway Freight Transport
X Rail Freight Transport
Blank No difference or najor inpscts.
-------
100.000
00.000
60,000
40.000
20,000
cc
ui
£10,000
o.
w 8,000
ul 6,000
Q
O
$J 4,000
u.
O
1C
I 2.000
1.000
I 1
I I
J 1 I
MOTOR CARRIERS
RAILROADS
(STRAIGHT
EXTRAPOLATION)
RAILROADS
-------
Protections of Environmental Factors. Figure 1-3, depicting the quantity
of coal transported to the various industries, illustrates that the per-
centage of coal shipped directly to electrical power utilities, has been
approximately constant over the past few years. As a consequence, it is
assumed that the environmental emission due to emissions from transporta-
tion systems will be increased on the same percentage basis as the electri-
cal generation established in Appendix R of this report. On this basis,
a projection of emissions was calculated and the results are shown on
Table 1-5.
Oil
A transportation network consisting of pipelines, tankers, barges, tank
cars, and tank trucks carry the crude petroleum to refineries for pro-
cessing. Of the crude oil received at the refineries in 1970, 77.4 per-
cent was received by pipeline, 21.5 percent by water, and the remaining
1.1 percent by tank cars and tank trucks. Since this section of the
report deals only with the pipeline, truck, and rail aspects of moving
oil, the major factor of concern is with regard to the crude oil trans-
port by pipeline.
Petroleum Administration for Defense (PAD) districts have been estab-
lished as shown in Figure 1-4 and quantity shipments between and within
each PAD District are shown in Table 1-6.
FIGURE 1-4. DESIGNATION OF PETROLEUM DISTRICTS
These data illustrate that 66 percent, or 1,036,629,000 barrels, of the
crude transported is received by refineries in the northeastern section
of the United States. C1"^) Maps distributed by the Oil and Gas Industry
also illustrate the predominance of the pipelines in the east to north-
eastern sector of the United States. As a result, the largest percent-
age of pumping stations that possess the potential for environmental
impact with respect to emissions into the air are found in the eastern
sector of the United States.
264
-------
(OO.ooo --' :- —!-
., Ceil tO Cthcr r.ir.j f j
rlnlng plant*, r
veurl jt-tt forelrn
~
.:.. _L1J_U. .LULL
. _L . Co* 1 to icttl tnd rolling
'cillU, Beehive Uke plants
I loven coV.e ?Un.s . I :
|-:T-;-l-rl TT: "I
i ? ; r~j
rr^ i--q-.r: i
FIGURE 1-3. CONSUMPTION OF BITUMINOUS COAL AN'D LIGNITE, BY CONSUMER
CLASS, WITH RETAIL DELIVERIES IN THE UNITED STATES
265
-------
TABLE 1-5. PROJECTED EMISSIONS FROM TRANSPORT OF
COAL FOR ELECTRICAL PRODUCTION
to
Emissions
Method of
Transport
Railroad
Truck
(10-* Tons/Year)
Pollutant
NO
HCX
CO
so2
NO + HC
cox,
SO,
1972
75.0
6.25
58.0
5.36
44.2
25.2
4.2
1975
116.3
9.07
89.9
8.31
68.5
39.0
6.5
1980
141.4
11.0
109.3
10.1
83.3
47.0
7.9
1985
163.0
12.7
126.0
11.64
96.0
54.2
9.1
1990
183.9
14.3
142.1
13.1
108.3
61.1
10.3
1995
203.0
15.8
157.0
14.5
119.7
67.6
11.3
2000
224.0
17.4
173.3
16.0
132.1
74.5
12.5
-------
TABLE 1-6. CRUDE OIL TRANSPORTED TO REFINERIES
3Y STATS AND DISTRICT, 1970
,Th.-^. u.,,-.l :
Lontion efrt^aeriM
rrc*ino( crude eil
felnti t
\\n\
Dvinri U.
!.r"--*"1
K* :•. i»/T«Vw»"""I"I
N'.irfff. A V. jk-oMiA
MM JM. NitftJk*. ...........
ou.!1^"":::::::::::::::
Dwtn-i U!
Vji» -.MI*
TuJ
Dllnil »
Minui
»'>"w."!!iiiir.iiiiiiiiii
T,U
TclJ
Tulal Imtcd StatM
TV" A.
JoE"
cuii.'!
Oli
11.111
1.111
t«. 102
i9.:ii
2.117
1V> CI9
r.i '.:»
IJU US
ll'f-1
i ;:»
is. in
11 171
111 7i»
t m
i: j'v
in •. .;
C* l.i)
11,751
I.OII 141
13.111
20,373
<0 111
I1C lit
1 .1 1:1
471 IM
B=£._ £f-=
1.4M.III
9. Ml
hicm>unc.|.!>hcm-
lolifiU TAUiIiilnct !I
An. 1. M. hy. N.ST.
W>1 lf«! . KJII. O'.io N Uik . Oll«.
M.tb Tfni B tt.l.
1.NI
..... ... .. ... ......
4U
4.705 3.i:i lii i.3'.i iji
9373 S'.'.S 351 4.717 «71
If |I>1 101 1 3'J !.?»* 13 IH
• <•» 1.171 11.130 t >.'•' 11 -'J
1 3'JI 11 II I'.l Ill
11.119 l.fl
III!"!" '. '.".'.'.'. I!III! "i.oij III"! 'in "j.:ii
17 u;
4 l» 1 t«S 131 Ml
ii' i'« "I"! ..'..,. "i'Jir I". II !.!.
1.311
^l.«'.l ;-
II 7M
1. IH. IIS 1 1 UI
2011
n.i'9
4i.i79 IIIIII III!'.! "III! I. .1.1 " «
Ci lit *
1 tli ;•'! '9710 31417 M I'l I.UI 12.CJ2 34.179
' 3|:i9 II 97 SI 11 U 232
:«
FAOilL-nellil
Toul ft!'.
Mae
."1
«!3(i iiimr
9 'XS 11.9^1
31. IS' 7.VU
• • ill
1" 5" ... .
i «n
MI» :.:.:i
» ro
!• V? "5.'775
i •::
3.S7J
29 11. Ml
io7 Jo
ait :% 319
i
t
113. (Cl J2.J11
U. X. MIL
ill
tl.UI 104
SI
72.CK 440
12' 119 ill
ei :n i- ?:i
14.011 it :u
'Ji.'o^ ...l.i.
Ja'.iii "ili2i
«:.« :::::::
IU.OI4 tl.Cil
2l).C!3 11.55)
41
42
l.SIO
2.SIU
115,3:0 112.3:0
1.411 3C1
Ttuj
i!i»
37. ill
it. i:i
t) III
III SO
91 211
11 1-7
1 Oil
11 t'.I
"il.TIO
39 <»
13 7(1
JJ.7C8
17 112
f- J— •-••
419.71]
To-*!
1.4IJ
1 lit
tl MO
143
179.413
217. 1M
%» r,r
II «71
i: 741
11 KC7
" 20.BI4
4l|ll3
3 C17
1', ill
Tl 177
S3. 749
24:. 7:7
3"3 C39
41
IS
l.MO
2. 1'O
1.ICO.PI5
J.I97
.nut. rt«.nu hon>-
PAD(!»-ticlIV
Coto. Meet. L'uTt V/o.
. . . .......
11
::•:::: ..?:"! ::::::: :::::::
3.111
i i;i I.JM) 10 »"i
1 131 H.7.-1 It 111
i on in i< v:i
II! Ill "III" "III" *.OI9
1
19 3.IS7
17 3.127
1.205 21 1 t::
1} nil
ll.H-7 13) 11.931
11.139 J.'ilU 11 1^.^-1
10 Old
10.9IJ
2l.lt! !7.liM I4.i>: 118.701
CI 49 40 Uli
Toul loul '
....... .......
312
21
..?:*! ::::.-:
i in u:
it i-i
1«7~7 """.I
111
1.019
1 fll
J J-l
I.V'.J "III"
1
9.111
1 III
it :>i
n on
2-..7-0 17
i nl
i: r-i »7
10 910 «1. 911
lO.oio ti :H
lil.B.t '(5.711
4T9 191
Toll)
tarrvfttt
rvcr w
11. HI
1 lit
U IS1
1.211
i2f.ua
11.411
ill 9M
17:, !'•
i. •>}
i VH
li. :u
Wi
17 Ml
111 ^SO
1 MI
II ill
Tl (01
1
111 (.17
3Vj 119
II 231
13 VI)
2< 'v5
l.lll
Tl HI
•J Oil
'1.1:1
• Honli.lKI.St. Ywk. I 4JI. Vuini. » Wol \.u.oli 1.319. .
I AUti*. C2 (19. Amiu. 2.411; Ci!i!.ra^ 4.473. .Ne»*:», 111.
-------
The Interstate Commerce Commission has reported a total of 171,782 miles
of interstate pipelines transporting crude oil and petroleum products
as of December 31, 1970, It is estimated that the older pipeline pump-
ing stations are located on the average of every 40 to 60 miles apart,
whereas the newer pipelines have pumping stations on the average of 100
to 150 wiles apart.
Of the 1.888 million horsepower used in pumping oil across the United
States, electric powered pumping stations develop 1.43 million horse-
power or 76 percent of the total, diesel powered pumping stations devel-
op 0.31 million horsepower or 16.3 percent of the total, and gas powered
pumping stations develop 0.15 million horsepower or 7.7 percent of the
total.Tl*25) Assuming a specific fuel consumption of the stationary
diesel engine at 0.39 pound fuel per brake horsepower-hour(I"26) pro-
vides the basic quantization information for establishing the diesel
emissions. Conversion data on the gas engine were accomplished assuming
an equivalent thermal efficiency with respect to the diesel and comparing
the fuel heating values.
Unit Emissions Evaluation. As indicated in the quantity evaluation
section, 77.4 percent of the crude oil received by refineries in 1970
was transported by pipeline, and almost all of the remainder by water.
As a consequence, only the oil shipped by pipeline is considered in this
section. Of the 1.888 million horsepower depicted as the total horse-
power developed in pumping stations, 1.43 million horsepower is developed
from electrical power resulting in no environmental effects other than
land use. The emissions due to the 0.31 million horsepower developed
using diesel power can be determined by considering a specific fuel con-
sumption of 0.38 pound fuel per brake horsepower-hour and assuming year-
around operation which results in the conclusion that 144.9 x 10° gallons
of fuel per year is used. If a 10 percent down-time is anticipated,
130.4 x 10 gallons of fuel per year is used.
Emission factors of 16 pounds of particulates per 103 gallons of fuel,
142 pounds of S02 per 103 gallons of fuel, 0.2 pound of CO per 103
gallons of fuel, 3 pounds of hydrocarbons per 103 gallons of fuel, and
80 pounds of NOX per 103 gallons of fuel has been reported as appropriate
for stationary units of the kind found in pumping stations. C^"*3) Based
on these data, Table 1-7 shows the resulting emissions that have been cal-
culated for the diesel operated pumping stations in crude oil pipelines.
TABLE 1-7. EMISSIONS FROM DIESEL DRIVEN PUMPING
STATIONS IN CRUDE OIL PIPE LINES
Emission,
Pollutant 10' tons/year
Particulate 1.09
S02 10.30
HC 0.22
NOX 5.80
CO 0.14
26S
-------
Emissions from gas engines can be calculated in the sam.. manner by
assuming the gas engine to be as thermally efficient as the diescl engine
and converting the specific fuel consumption into cubic feet of natural
gas per brake horsepower hour. Accomplishing this requires a knowledge
of the fuel heating value — natural gas 1028 Btu/f t3^1"27) and 18,300
Btu/lb of dicsel fuel. The gas engine specific fuel consumption estab-
lished in this basis is 6.76 cubic feet of fuel per horsepower hour.
Emission data available from gas engines in pipelines are only available
on. the N'0X pollutant and are reported to be 73001b NO per 106 cubic
feet. (I" 15) The emissions of NOX as a result of 90 percent operation of
a gas engine using 0.15 million horsepower in a crude oil pipeline is
(0.15 x 106 hp][24 hr/day][365 days/year] [0.90] [6.76 ] [
] = 29'179 X 1() t0ns °f N0x/year<
The transportation accident potential of transporting oil is signifi-
cantly reduced as compared with coal since the primary mode of carrying
oil is a pipeline. As a consequence, oil spillage and the pumping
station represent the major emissions.
Spillage of oil usually occurs in rather concentrated areas around the
loading and unloading area resulting in heavy saturation at the ground in
specific areas. Heavy rainfall or perhaps a rise in the water table can
result in significant water pollution from these saturated areas.
Materials are currently available which can be utilized to decompose the
oils in the area. Obtaining good results with this method requires a
knowledge of the soils present and the type and density of the materials
spilled. If at all possible, water-oil separators should be used in
conjunction with a retention pond to prevent water pollution in the
loading and unloading areas.
Projections of Emission. Figure 1-5 illustrates the percentage of total
crude oil transported by the various means has remained relatively con-
stant over the past few years, and it is assumed that this relationship
between the transport modes will be maintained. As a consequence, the
pollution from oil transport over the future years is assumed to be in
direct proportion to the percent increase of the crude oil demand re-
quired for electrical power generation. Table 1-8 summarizes the esti-
mates of the physical emission calculations from the transport of both
coal and oil based on the assumptions as outliiied above.
Pollution Controls
Coal and oil is basically transported by heavy duty diesel engines.
Reference 1-28 includes regulatory data on heavy duty engines but is
restricted only to regulations through 1974. Smoke emissions and limited
data on exhaust gaseous emission standards are presented. Smoke standards
269
-------
to
«J
o
'• •;• Rail - 0.257. average
56
FIGURE 1-5. RELATION OF TRANSPORT MODES IN CRUDE OIL TRANSPORT
-------
s>
TABLE 1-8. PROJECTED EMISSIONS FROM TRANSPORT OF
OIL FOR ELECTRICAL PRODUCTION
Emissions
Method of
Transport
Pipeline
Diesel Engine
Gas Engine
(103 Tons/Year)
Pollutant
Particles
NOX
CO
S02
HC
NO,.
1972
1.09
5.8
0.14
10.30
0.22
29.2
1975
1.29
6.8
0.17
12.2
0.26
34.6
1980
1.52
8.04
0.201
14.4
0.31
40.9
1985
1.62
8.6
0.214
15.3
0.33
43.9
1990
1.67
S.9
0.22
16.0
0.35
46.0
1995
1.74
9.2
0.23
16.7
0.36
48.0
2000
1.805
9.5
0.24
17.3
0.37
49.8
-------
are established at opacity levels of 20 percent during the engine
acceleration mode, 15 percent during the engine lugging mode, and 50
percent during the peaks in either mode. Exhaust emissions of 16 grams/
brake horsepower of the hydrocarbons plus oxides of nitrogen and 40 grams/
brake horsepower for carbon monoxide. In addition, regulatory action is
being considered which would impose (1) a requirement of recording equip-
ment on stacks exceeding a certain CFM threshold, (2) limitations regard-
ing odor regulations, and (3) limitations of idle duration. Since the
regulations currently imposed are only in effect until 1975 and the ex-
tent of regulatory measures to be imposed after 1975 is not evident, the
projection of controls after 1975 and the corresponding costs•of imposing
these rules were not calculated.
References
1-1. Szego, "The U. S. Energy Problem - Volume 2: Appendices, Part B",
IntcrTechnology, November, 1971, pp N-l to N-34.
1-2. Morrison, W. E., and Readling, C. L., "An Energy Model for the
United States, Featuring Energy Balances for the Years 1947 to
1965 and Projects and Forecasts to the Years 1980 and 2000", U.S.
Department of the Interior, Bureau of Mines, Washington, D.C.,
July 1968.
1-3. "Estimated Motor Vehicle Travel in the United States and Related
Data", Bureau of Public Roads, American Petroleum Institute.
1-4. Interstate Commerce Commission Annual Report, Statement No. 6103,
"Intercity Ton-Miles 1939-1959", April, 1961.
1-5. "Shipments of Fuel Oil and Kerosene", U.S. Department of Interior,
Bureau of Mines, Mineral and Industrial Surveys, Washington, D.C.
1-6. "Automotive Fuels and Pollution", U.S. Department of Commerce,
March, 1971.
1-7. "Nationwide Inventory - Air Pollution Emissions, 1968, Publication
No. AP-73", National Air Pollution Control Administration, U.S.
Department of HEW, August, 1970.
1-8. "A Study of the Environmental Impact of Projected Increases in
Intercity Freight Traffic" to Association of American Railroads,
Battelle Memorial Institute Research Report, August 1971.
1-9. "Petroleum Facts and Figures", American Petroleum Institute,
Washington, D.C., 1971 edition.
I-10. "Task Report on EPA Energy Quality Model Exercise for 1975, Series
B, Supplement V, Output from Control 3 Takes, Research Report from
Battelle Memorial Institute, Environmental Protection Agency Office
of Air Programs, 1972.
272
-------
1-11. "Sales of Fuel Oil and Kerosene in 1970", Materials and Industry
Surveys, U.S. Department of the Interior, Bureau of Mines,' 1971.
1-12. "Coke and Coal Chemicals", Bureau of Mines Yearbook, U.S. Dept.
of the Interior, 1970.
1-13. "Coal-Bituminous and Lignite", Bureau of Mines Minerals Yearbook,
U.S., Dept. of the Interior, 1970.
1-14. "Crude Petroleum and Petroleum Products", Bureau of Mines
Materials Yearbook, U.S. Dept. of the Interior, 1970.
1-15. "Compilation of Air Pollution Emission Factors", U.S. Environ-
mental Protection Agency, Office of Air Programs, 1972.
1-16. Ephraim, M., "Status Report on Locomotives as Sources of Air
Pollution", International Conference on Transportation and Envir-
onment, Washington, D.C., May 1972, p 9.
1-17. Sherbinsky, M., "Characteristic Emission of Heavy Class Intercity
Trucks", International Conference on Transportation and the
Environment, Washington, D.C., May 1972, p 14.
1-18. "Specifications of 1971 On-Highuay Trucks", Automotive Industries,
114, 87-98, March 15, 1971.
1-19. Wright, J. M. and Tignor, S. C., "Relationship Between Growth
Weights and Horsepowers of Commercial Vehicles Operating on
Public Higlways", SAE Paper No. 937B, SAE Transactions, 73,
469-477, 1965.
1-20. Turenun, W. A., and Collman, J. S., "General Motors Research
GP-309, Gas Turbine Engine", SAE Paper No. 650714, SAE Trans-
actions, 74, 1966.
1-21. "Statistical Abstract of the United States: 1970", 91st edition,
U. S. Department of Commerce, Bureau of Census, U.S. Government
Printing Office, Washington, D.C., Table 849, 1970.
1-22. Beck, N. J., "Forecast of Truck Pilot Plant Developments", Diesel
and Gas Turbine Progress, 33, 36, October 1967.
1-23. Hanley, G. P., "Railroad Exhaust Emission Control and Regulation",
presented at the Emission Control Symposium, Association of Ameri-
can Railroads, Washington, D.C., February 10, 1971.
1-24. "Over 1.5 Million Tons of Coal Slurry Moved Through Big Sluggy
Line", Oil and Gas Journal. Tulsa, Oklahoma, April 17, 1972, p 42.
273
-------
1-25. "Crude Oil Pipelines", Pipe Line News. Oildom Publishing Company,
1971-72 Edition, p 65.
1-26. Mechanical Engineers' Handbook. L. S. Marks, Ed., 5th ed., McGraw-
Hill Book Company, Mew York, N.Y., 1951, p 1198.
1-27. Gas Engineers' Handbook, Fuel Gas Engineering Practices, The
Industrial Press, New York, N.Y., 1965, p 2/10.
1-28. "Control of Air Pollution from Motor Vehicles and Engines—Heavy
Duty Engines", Environmental Protection Agency, Federal Register,
September, 1972.
274
-------
APPENDIX J
ELECTRICAL TRANSMISSION
Table of Contents
Introduction 276
Environmental Factors 277
Nonesthctic Factors 279
Future Considerations • 280
References '. 281
List of fables
J-l. Mileage and Load Capacity for Various Transmission
Voltage Levels 276
J-2. Costs to Improve Esthetics 278
List of Figures
J-l. Capabilities of Underground Transmission 282
275
-------
APPENDIX J
ELECTRICAL TRANSMISSION
Introduction
There are at present close to 4000 electric utility companies in the
United States which operate over 400,000 miles of overhead transmission
lines and about 2000 miles of underground transmission cables. The
transmission .lines utilize approximately 4 million acres of land for
right of way. This section discusses the impact of the transmission
lines on the environment, and points out methods of reducing these
impacts.
Early transmission lines consisted simply of wood poles, wood cross arms,
and solid copper conductors. Voltage levels were as low as 6900 V-. As
the requirements for electrical power increased, transmission voltages
increased. For some years, 230 kV was the highest voltage in general
use. At the present time, voltages of 345, 500, and 765 kV are in use,
with future planning on the next highest voltage levels of 1000 kV and
1500 kV. Some data on mileage and load capabilities for different
voltage levels compiled by McCaw'*1"1' are shown in Table J-l.
TABLE J-l. MILEAGE AND LOAD CAPACITY FOR VARIOUS
TRANSMISSION VOLTAGE LEVELS
Voltage kV
up to 1969
69
115
138
161
230
287
345
500
765
1,300
TOTAL
Mileage
136.000
82,000
77,000
47,000
17,000
37,000
1,000
9,000
4,000
410,000
Loading, MW
100
120
240
580
1,280
2,700
6,500
As the voltages get higher, insulators and conductors become bigger and
heavier, and towers evolved into large steel or aluminum structures with
276
-------
two-pole designs. In the future we are likely to see development in the
areas of tower designs and material of construction, underground trans-
mission, and cryogenic cooling.
The transmission of electrical energy from the generating station to the
load centers must be considered as an integral part of the electrical
power system. Thus, in any study of environmental emission of energy
systems, due consideration must be given to the electrical transmission.
Environmental Factors
There are essentially two effects on the environment from transmission
lines. One is a visual or esthetic; that is, transmission towers, along
with their associated cables, are not a pretty sight to most people. The
other is the actual destruction of the environment in a physical manner
due to the transmission lines.
Esthetic Aspects of Power Transmission
Although there are surely some poeple who would consider a transmission
line with its long sweeping curves of wires and graceful towers as a
pleasant sight and a triumph to man's technology, most would consider the
line as an intrusion into the natural beauty of a particular scene or
view.
In general, the esthetic aspect of a line can be minimized by proper
placement of the transmission corridor and by thoughtful design of the
towers and lines.
The following points are considered to have a deleterious effect on the
esthetics of the environment.(J~2)
1. Transmission lines in heavily timbered areas, over steep slopes,
proximity to main highways, through shelter belts, and scenic
areas.
2. Crossings of roads at intersections or interchanges.
3. Crossings over open expanses of water and marshland especially
near flight lanes utilized by birds and waterfowl.
4. Long views of lines perpendicular to highway, canyons, and belts
5. Crossing hills and other high points at their crests
6. Long right-of-way "tunnels" through forests and wooded areas.
Tower design and placement also has an esthetic impact from the follow-
ing standpoint:
277
-------
1. Color of towers
2. Use of guyed towers especially where visible
3. Use of two structures for two circuits rather than consolidation.
Controls. The most obvious control technique for eliminating the ad-
verse visual effects of transmission lines is to utilize underground
systems in lieu of overhead transmission.
From an economic standpoint, in order for underground transmission to
assume a major role in electrical transmission, much is still required
to be learned. At the present time, cables are being operated at up to
345 kV and in general an oil-paper insulation is used. The cost of
running an underground line is approximately ten times that of an over-
head line.
Another control technique would involve the avoidance of the situations
which tends to be undesirable by using additional lengths of line. For
example, instead of crossing a hill over the crest (which may be the most
economic way), additional lines could possibly be installed to circum-
vent the hill. Wooded and scenic areas could be bypassed.
A third technique would involve the planting of trees to shield long
stretches of transmission lines from view. A cost comparison to these
three major control techniques is given in Table J-2. The following was
assumed in developing the cost data:
Line length 100 miles
Load capacity 1000 MW
Annual charges 13% of capital ('*"•*)
Cost of overhead transmission $150,000/mile(J~4)
Tree cost $25/tree, 35 ft apart
TABLE J-2. COSTS TO IMPROVE ESTHETICS
Capital Costs, Operations,
1.
2.
3.
Option
Underground transmission
(entire length)
Plant trees along 20 percent of
route (both sides)
Add 20 percent length to avoid
undesirable areas
$/kw
135
0.2
3.0
mils/kwhr
2.0
0.003
0.04
278
-------
From this table, it is seen that underground transmission for the entire
route at the present, time is very expensive. The cost of the generating
station itself is about $l35/kw. Even if only 20 percent of the line were
underground, the cost would be high.
In contrast, rerouLing or the planting of trees is a reasonable control
technique, and would certainly be much less costly.
Means of improving the esthetics of the towers themselves are mainly
limited to design and material modifications. Some of the more recent
trends in this area are:
1. Horizontal po.-.t insulators
2. Single pole construction without arms. However, single-pole lines
exclusive of right-of-way costs about $2500 per mile more than the
same line supported on the wider H-frames.
3. Painting the towers to blend in with the surroundings.
4. Use of insulators with a sky-blue glaze color instead of the common
brown ones.
5. See-through poles
6. Use of concrete poles.
Nonesthetic Factors
Apart from the esthetic factors described above, transmission lines can
have a direct, often physically destructive impact on the environment.
The following considerations can be mentioned in this regard.
Clearing and Construction. In order for a transmission line to be con-
structed, the riyht-oJI-way must be prepared adequately. High trees are
cut down to prevent arcing from the lines, brush and bushes are usually
cleared, the ground must be suitably prepared, and access roads to the
line are built. Each of these activities results in some physical
destruction of the environment.
Other aspects of this problem are:
1. Open burning of construction wastes, trees, branches, and brush
2. Soil erosion of right-of-way due to removal of natural vegetation
cover
279
-------
3. Oil spills from construction equipment
4. Damage to trees, stream channels, etc., from blasting operations.
Control of Nonesthetic Factors. In general, control of the above factors
requires planning construction activities with environmental conservation
in mind. Such factors include;
1. Minimize clearing, and restore those cleared areas back to their
original state insofar as possible.
2. Use of helicopters for conductor stringing and bringing in materials
3. Construction during seasons of low wildlife occurrence
4. Replacement of topsoil
5. Transportation of material to be burned to an area of small fire risk
and heat damage to natural vegetation.
Future Considerations
Transmission design and technology is at present undergoing much change.
In the past, right-of-way was easily obtained, but now it is much more
difficult and expensive. An environmentally conscious public is demand-
ing preservation of the environment. Also, people are objecting to the
proximity of power plants, which necessitates increasing distances of
electric transmission lines.
Major effort is being put into (1) ultra-high voltage lines (>745 kV) and
(2) underground transmission.
The use of higher voltages will enable a given line to carry a higher load,
and avoid the necessity of multiple circuits or lines.
•*•
With regard to underground transmission, research is proceeding in several
areas.
Compressed Gas Insulation.
In this method, the wire carrying the power is suspended concentrically in
a pipe. Compressed gas ( SFg is the most likely candidate) fills the annular
space between the wire and the pipe. The advantages of this system include
good heat transfer, and very low dielectric loss.
Cryogenics
It is well known that as certain materials are cooled down, the electrical
resistance decreases. For example, pure aluminum or copper will be from
50 to 2000 times more conductive at liquid hydrogen temperatures than at
280
-------
room temperatures. At temperatures from 4 to 10 K, certain materials
lose their resistance entirely, a state known as superconductivity.
The development of cryogenic technology will enable power to be carried by
relatively small wires and should result in a reconsideration of the
feasibility of underground transmission systems. Figure J-l shows a pro-
jection of various types of underground systems.U-6)
Another new concept which has been proposed for underground transmission
is the use of wave guides utilizing microwave transmission. The big
advantage of this system is the elimination of conductors and insulation.
The major problems with this system are large losses in wave guides of
conventional size, and the need for efficient terminal conversion equip-
ment.
In summary, it appears that, at present, the major effort toward control
of the impact of electrical transmission should be careful design of the
corridors, lines, and towers within the environmental constraints. Re-
planting, additional line sections to avoid adverse visual impacts, and
care during construction can be used very effectively.
In the future, it appears that underground technology will be developed
sufficiently to enable either replacement of some sections of the trans-
mission line or of the entire line.
References
J-l. McCaw, B., "The Development of Electric Transmission Systems",
Power Engineering, 72 (11), SI (1968).
J-2. Environmental Criteria for Electric Transmission Systems, Report
prepared for U. S. Departments of the Interior and Agriculture (1970)
J-3. Anon, "A New Era of Power Supply Economics", Power Engineering,
U, .(3), 30 (March, 1970).
J-4. Underground Power Transmission, Federal Power Commission,
Washington, D.C., April, 1966.
J-5. West, J. R., "In Support of CGI Cable", Power Engineering, Tb_ (3),
42 (March, 1970).
J-6. Papamarcos, J., "New Incentives for Underground Transmission", Power
Engineering, ^ (12), 27 (December, 1971).
281
-------
1971
1980
Year
1990
2000
Superconduc-
ting
Resistive
Cryogenics
Gas Dielectric
Pipe Cable
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
xxxxxxxxxxxxxx
xxxxxxxxxxxxxx
xxxxxxxxxxx
XXXXXXXXXXH
xxxxxxxxxx
xxxxxxxxxx
456
MVA (103)
8
10
FIGURE J-l. CAPABILITIES OF UNDERGROUND TRANSMISSION
282
-------
APPENDIX K
REMOVAL OF SULFUR FROM NATURAL GAS
Table of Contents
Page
Nature of Problem 284
Sulfur Removal Technology 284
Sulfur Recovery Technology 287
Sulfur Emission . 287
Other Pollutants 288
References 290
List of Tables
K-l. Composition of Various Natural Gases 285
K-2. Natural Gas Processed 289
List of Figures
K-l. Preparation of Sulfur from Hydrogen Sulfide (Generalized
Flowsheet) 286
K-2. Flow Diagram of Processes to Eliminate Air Pollutants
from Tail Gases of Sulfur Plants 286
283
-------
APPENDIX K
REMOVAL OF SULFUR FROM NATURAL GAS
Nature of the Problem
The sulfur content of natural gas is a function of the field from which
the gas originates. Most of the sulfur present in natural gas is in the
form of hydrogen sulfide. The hydrogen sulfide content may vary from
near 0 to as high as 76 percent (as in Hinds County, Mississippi). The
wide range of sulfur from typical natural gas is illustrated in Table
K-l.
Hydrogen sulfide is a corrosive material, and therefore it is removed
from natural gas before the gas is transported. Gas with a high sulfide
content is called sour gas. Sweet gas is low in sulfur. Natural gas
which is transported and sold in the United States has a hydrogen sulfide
content of less than 0.25 grain per 100 standard cubic feet of meth-
ane. (K-l)
Sulfur Removal Technology
Sulfur is generally removed from natural gas by absorption in an alkaline
solution. Ethanolamines are most commonly used, but other absorbents are
also used in commercial practice. Carbon dioxide is also removed from the
natural gas during this absorption step. The hydrogen sulfide is then
desorbed and, when the sulfur content is high enough to warrant economic
recovery of sulfur, is converted to elemental sulfur in a Claus sulfur
plant. A generalized flowsheet of this sulfur extraction and recovery is
shown in Figure K-l. The elemental sulfur is recovered from the converters
in this process and is usually stored.
The oxidation of hydrogen sulfide to sulfur is exothermic, and it is be-
lieved that no fuel need be consumed in the process. In conventional
operations, about 90 to 95 percent of the sulfur present in natural gas is
recovered as elemental sulfur. The remainder is discharged to the air,
primarily as sulfur dioxide, but also as other sulfur compounds.
When the sulfur content of natural gas is low, it is frequently uneconomic
to recover sulfur. Under such conditions, hydrogen sulfide is frequently
flared, and the resulting sulfur dioxide discharged directly to the
atmosphere. For the purpose of this investigation, it has been assumed
that this practice of direct discharge will not be permitted in future
gas production. Therefore, this direct discharge of acid gases to the
284
-------
TABLE K-l. COMPOSITION OF VARIOUS NATURAL CASES'
Composition, mole %, of gas from
Rio
Airiba Terrell
County, County,
Component N.M. Texas
methane
ethane
propane
butane*
Dcntancdand
heavier
carbon
dioxide
hydrogen
sulfidc
nitrogen
helium
total
total sulfur,
grains/ 100 ft'
classification
wet
dry
sweet
sour
gross heating
value.
Btu/ft« 1
specific
Brevity
96.91 45.64
1.33 0.21
0.19
0.05
0.02
O.S2 53.03
0.01
0.68 0.21
100.00 100.00
0 6.3
•
•
X X
X
x^
,010 466
0.574 1.077
Stnnton
County,
Kansas
67.56
C.23
3.18
1.42
0.40
0.07
21.14
100.00
0
X
x.
938
0.733
Sun Juan
County,
N.M.
77. 2S
11.18
5.83
2.34
1.18
O.SO
1.39
100.00
0
X
X
•
•
1,258
0.741
Olds
Field,
Alberta,
Canada
52.34
0.41
0.14
0.16
0.41
8.22
85.79
2.53
100.00
22,525
X
x ,-
807
0.8S2
i
ClifWde
Lacq Field,
Field, .Amarillo,
France Texas
70.0 65.8
3.0 3.8
1-.4 1.7
0.6 0.8
,
0.5
10.0
15.0
25.6
l.S
100.00 100.00
X X
X
X
921 S25
0.7S4 0.711
285
-------
^Cteii»n
tour fit
<
«___
>
—<
f
Cooler
>— »•
"«
—
Hcil
Hdunger
Absorber RiKWitor
|
. \
**\
Ofiier
1
1
|- II.S. CO, ,
>T
| 1
/•!,$. SO,. CO,.
W !
I
j
|
j Baler Converter
Nj. H,0
«
J.
1
I
Scnibbef Conwrttr
SUel
**
i
i —
Soubb
FIGURE K-l. PREPARATION OF SULFUR FROM
HYDROGEN SULFIDE (GENERALIZED
FLOWSHEET).
Buijvon Sulfur Reinov/al Process
fui CAS •••••" »n
>^SUL/UHi'L/l«rMlLGAS ^ JL COOLI
HYOnocFNArEO COOLED MIL CAS TO M,S RECOVERY
, t j
^X
AIR
SULFUR SC
f*V-
"~\2/
Strctford Process
JL IM&
EO **" BOOSTER
\ / BLOWER
_A „ .*
4n V
ffl
LIQUOR RETURN
1
UW.. >riticn J SULri"*
SULFUR
FIGURE K-2. FLOW DIAGRAM OF PROCESSES TO
ELIMINATE AIR POLLUTANTS FROM
TAIL GASES OF SULFUR PLANTS.
286
-------
atmosphere has been ignored.
Sulfur Recovery Technology
As mentioned above, sulfur is currently removed from natural gas by
absorption in an alkaline solution, followed by oxidation of the hydro-
gen sulfide to sulfur in a Glaus plant. As currently practiced, this
technology will result in removal of about 90 to 95 percent of the sulfur
present in the natural gas.(K~2) In this investigation we have assumed
that a new Claus plant would recover 95 percent of the sulfur present in
natural gas. If the tail gas from the Claus sulfur plant is not treated,
the remaining" 5 percent of the sulfur will be vented to the atmosphere
in the form of sulfur dioxide.
There are a number of new processes for the further removal of sulfur
from the tail gas of a Claus sulfur plant. These include the Beavon,^"^'
the Shell,(K-3) and the Clcanair(K-4) processes. It has been claimed
that 99.9 percent of the sulfur present in the gas can be recovered when
these processes are used. This recovery is costly, however. The exact
cost will depend upon the size of the plant, the quantity of sulfur in the
tail gas, and the level to which the sulfur must be removed. In general,
the investment for the Beavon process to remove additional sulfur will
about equal the investment required for the Claus plant to achieve 90-95
percent sulfur recovery. For a sulfur plant with a capacity of about 100
long tons per day, the additional investment for the Beavon process would
be between $700,000 and $1,000,000. In addition, the direct operating
cost of the Beavon process (excluding depreciation and return on invest-
ment) will be about $25 per ton of sulfur recovered by the process.^K~^'
This will add about $1.00-$1.30 per ton to the average cost of all sulfur
recovered.(K-6)
For the purpose of this investigation,, it has been assumed that the Beavon
process or a similar process would be installed on new natural gas wells
after 1975 and that these processes would recover 99.8 percent of the
sulfur contained in natural gas.
Sulfur Emissions
It is difficult to estimate the emissions of sulfur dioxide from a
natural gas processing facility because these emissions will be directly
proportional to the sulfur content of the natural gas. It is assumed
that before 1975 the emissions will be equivalent to 5 percent of the
sulfur contained in natural gas, and that after 1975, technology will
exist which will limit emissions to 0.2 percent of the sulfur present in
natural gas.
287
-------
Unfortunately, there is little data upon which to estimate the overall
sulfur content of natural gas. The only data that were found during this
Investigation are summarized in Table K.-2. These data were collected by
Processes Research Inc.(K~7) These data represent about 9 percent of the
natural gas produced in 1970. In addition, these data are biased toward
high sulfur emissions because they were collected primarily in areas
where sour gas is a significant factor. The Louisiana offshore gas has
a relatively low sulfur content and the gas from the Alaskan North Slope
has about an average sulfur content. Therefore, use of these data may
tend to overstate the sulfur emissions.
As can be seen from Table K-2, the sulfur dioxide emitted as purged gas
(i.e., from gas processing where there was no sulfur plant) greatly
exceeds the sulfur oxide emissions as tail gas from the Claus sulfur
plant. These emissions were ignored in making calculations. Furthermore,
Processes Research assumed a 90 percent recovery of sulfur in the Claus
plant, whereas we have assumed a 95 percent recovery. Assuming a 95
percent recovery of sulfur in the sulfur plant, and assuming the natural
gas described in Table K-2 is representative, the emissions of sulfur
dioxide would be 0.0183 pound per 1,000 cubic feet natural gas (Mcf). If
one further assumes that the recovery technology after 1975 is the
equivalent of 99.8 percent recovery of sulfur, the emission factor would
be 0.00073 pound per Mcf.
Other Pollutants
Other than the emissions of sulfur oxides, emissions of other pollutants
from natural gas sulfur recovery plants should be negligible. Small
quantities of nitrogen oxide, carbon monoxide and hydrocarbons will be
emitted by incineration of tail gas. Process pumps are driven by steam
generated in the process.
There will no doubt be a small quantity of water pollutants resulting from
condensate blowdown and possibly from treatment of process water. There
may also be minor leaks of the alkaline absorbent. The emission of these
pollutants is believed to be negligible. No data were found of these
emissions.
Since the oxidation of hydrogen sulfide to sulfur is exothermic, there will
be a certain amount of heat removed from the system. The quantity dis-
charged to local waters would be highly dependent upon location and the
individual processing characteristics. No estimate has been made of heat
discharge to local streams.
No significant solid wastes are expected from the sulfur plant.
288
-------
TABLE K-2. NATURAL GAS PROCESSED
Gas Production
State
I960
Arkansas
Mississippi
New Mexico
North Dakota
Texas
Wyoming
•
1970
Arkansas
Mississippi
New Mexico
North Dakota
Texas
Wyoming
•
State
Total
MM cf/d
177.1
244.5
2,183.5
41.0
13,638.9
369.0
16,654.0
128.1
133.7
3,016.5
106.9
22,531.8
847.9
26,764.9
Soiir
Gas
MM cf/d
177.1
—
1,176.5
41.0
2,158.3
111.0
3,663.9
122.6
30.0
1,712.7
96.9
3,177.9
149.7
5,289.8
Sulfur
Sulfur
Prodn.
LT/D
99.0
—
41 .-6
45.4
428.6
• 385.5
1,000.1
104.0
6.0
105.9
137.0
1,534.8
115.6
2,003.3
Tail Gas
S0x
T/D
70.4
—
12.0
7.6
102.5
102.8
295.3
103.2
1.5
28.8
24.7
250.6
32.3
441.1
Purged
Gas SOx
T/D
255.8
--
862.9
— —
566.5
212.4
1,897.6
254.6
29.9
384.8
— -
410.6
1,255.0
2.33V.9
Total SOX
T/D
326.2
—
874.9
7.6
669.0
315.2
2,192.9
357.8
31.4
413.6
24.7
661.2
1,287.3
2,776.0
289
-------
References
K-l. Kirk-Othraer, Encyclopedia of Chemical Technology, Vol. 10,
p449.
K-2. Beavon, D. K., Pollution Eng., p 34 (Jan/Feb, 1972).
K-3. Oil & Gas J., 2P_ <*3), October 2, 1972.
K-4. J. F. Pritchard & Co., Cleanair Process Bulletin.
K-5. Beavon, D. K., private communication, October, 1972.
K-6. Beavon, D. K., and R. P. Vaell, paper presented to 37th Midyear
Meeting of the Refining Division, American Petroleum Institute
(May 9, 1972).
K-7. Processes Research Inc., Sulfide Dioxide from Natural Gas Fields,
Task Order No. 20, Contract No. CPA 70-1, prepared for Office of
Air Programs, EPA (July 21, 1972).
290
-------
APPENDIX L
PETROLEUM REFINING
Table of Contents
Conventional U.S. Petroleum Refining 292
Fuel Oil Refinery 307
Allocation of Pollutants to Products • 309
By-Products 311
Cost of Pollution Control • 312
References. .' .313
List of Tables
L-l. Air Emissions from California Refineries 294
1-2. Potential Sources of Specific Emissions from Oil
Refineries 295
L-3. Estimated Refinery Sulfur Dioxide Emissions 298
L-4. Summary of Effluent Data 302
L-5. Estimated Aqueous Effluents from New Refineries 304
L-6. Fuels Consumed at U.S. Refineries, 1925-1969. . 306
L-7. Estimated Aqueous Effluents from New Topping Refineries . 309
List of Figures
L-l. Processing Plan for Typical Complete Refinery 293
L-2. Example of a Plan for the Collection and Treatment of
Refinery Liquid Wastes 301
291
-------
APPENDIX L
PETROLEUM REFINING
Petroleum refineries, like people, are individualistic; no two are ex-
actly alike. For the purposes of estimating emissions two vastly dif-
ferent types of refineries were considered. These are the conventional
U.S. petroleum refinery, which is designed to maximize gasoline, and a
topping refinery which is designed to maximize fuel oil.
Conventional U.S. Petroleum Refining
A modern petroleum refinery is a highly complex operation. Furthermore,
each refinery has its own individual characteristics, its own blend of
feedstocks, and its own special emissions problems. One may grasp the
complexity of a typical petroleum refinery from the simplified flow
diagram presented in Figure L-l. Because of the complexities and pecu-
liar characteristics of each individual refinery, generalizations re-
garding refinery emissions will not be applicable to any given refinery.
Nevertheless, such generalizations are useful for comparing the overall
emissions of alternative energy sources on the environment.
Air Emissions
Although a 1966 publication by the National Academy of Sciences indi-
cated that carbon monoxide was the principal atmospheric pollutant
emitted from petroleum refineries,^- *•) most recent data indicate that
sulfur dioxide and hydrocarbons are emitted in greatest quantity. Other
major air pollutants from refinery operations are particulate matter and
nitrogen oxides. There are also lesser emissions of aldehydes, organic
acids, ammonia, and various other compounds which, although generally
emitted in very low concentrations, contribute significantly to the odor
near refineries. Emission data for the major air pollutants from some
typical refineries in California are summarized in Table L-l. Because
California refineries manufacture larger quantities of fuel oil than do
their Eastern counterparts, these emission data may not be representa-
tive of the emissions from Gulf Coast refineries. Nevertheless, these
data are believed to be sufficiently representative for the current in-
vestigation. The major sources of these pollutants are summarized in
Table L-2.
Sulfur Oxides. Catalytic Crackers. A major source of sulfur oxides from
refineries is the regeneration of cracking catalysts. With fluid catalytic
292
-------
D-y O.M
Fuel e,n
Wetqw
crude
Residuum
-LfCcy
•-LPG
.Hvy hycto-
C/OCtcd
gasoline
(yd'ogon
.— CoXer gaioime
Lu3C
prOC»SSin;
VII |
_
^
^
Motor gotellna
•*— Aviation gosoKne
to
Chtmical
Ke-osre
(uil oil
Oie:«! fuel
*- Sulfur
Lubes
Woxes
Greoset
HeOvy fu
Asphalt
oH
Cofe
FIGURE L-l. PROCESSING PLAN FOR TYPICAL COMPLETE REFINERY
-------
TABLE L-l. AIR EMISSIONS FROM CALIFORNIA REFINERIES
to
Refinery
Standard Oil Co. of California
Richmond Refinery
Union Oil Rodeo Refinery
Shell Oil Company Martinez
Phillips Petroleum Martinez
Los Angeles Area Refineries '
Capacity***
1,000 Barrels per
Calender Day
190
60
100
110
730
(pounds
Farticulate
13
13
32
62
11
1970
per
S02
313
343
358
598
151
Emissions 'b^
day per 1,000
Hydrocarbon
220
187
198
284
137
B/CD)
NO*
208
93
214
313
68
CO
15
~
•266
20
82
(a) Oil & Gas Journal, 69., "99 (March 22, 1971).
(b) Bay Area Air Pollution Control District, Source Inventory of Air Pollutant
Emissions, San Francisco Bay Area, 1970.
(c) National Petroleum Council, Environmental Conservation, Vol. 2, p 183, (based on January 1969
publication).
-------
TABLE L-2. POTENTIAL SOURCES OF SPECIFIC EMISSIONS
FROM OIL REFINERIES
Emission Potential Sources
Sulfur Compounds Boilers, process heaters, catalytic-cracking unit regenerators,
treating units, H2S flares, decoding operations
Hydrocarbons Loading facilities, turnarounds, sampling, storage tanks, waste
water separators, blowdoun systems, catalyse regenerators, pumps,
valves, blind changing, cooling towers, vacuum jets, barometric
condensers, air-blowing, high-pressure equipment handling vola-
tile hydrocarbons, process heaters, boilers, compressor engines.
Oxides of Nitrogen Process heaters, boilers, cc-npressar e.-.*i.-.£s. catalyst rese=era-
£ tors, flares
Participate Matter Catalyst regenerators, boilers, process heaters, decoking opera-
tions, incinerators
Aldehydes Catalyst regenerators
Ammonia Catalyst regenerators
Odors Treating units (air-blowing, steam-blowing), drains, tank vents,
barometric condenser sumps, waste water separators
Carbon Monoxide Catalyst regeneration^decoking, compressor engines, incinera-
tors
Source: U.S. Department of Health, Education and Welfare, Atmospheric Emission From Petroleum
Refineries. A Guide for Measurement and Control. Publication No. 763 (HEW Public Health
Service, I960).
-------
cracking units, Che emission of sulfur dioxide is about 525 pounds per
thousand barrels feed. With moving bed catalytic cracking units (TCC
units) the emissions would be about 60 pounds per million barrels fresh
feed.\i"2) if One assumes that new refineries will install fluid cata-
lytic cracking units, as has been the recent trend, and that the ratio
of catalytic cracking fresh feed to crude capacity remains at the
January, 1972, ratio of 0.33, the emissions of sulfur dioxide from new
cat crackers would be about 175 pounds per thousand barrels crude pro-
cessed. Reference to Table L-l will quickly indicate that cracking
accounts for a significant fraction of the sulfur dioxide emissions.
Desulfurization. A 1966 study indicated that the average sulfur con-
tent of crude oil processed in U.S. refineries was 0.76 percent.(L-l)
The same study indicated that 30 percent of the sulfur went into the
products. Most of the rest of this sulfur is converted to hydrogen sul-
fide during refining operations. Technology exists, and is in fact used
In many refineries, to recover this hydrogen sulfidc by absorption and
to convert the absorbed hydrogen sulfide to elemental sulfur. About 95
percent conversion of this hydrogen sulfide to sulfur is considered to
be typical in a two-stage Glaus sulfur plant.(L"3)
If one assumes that 70 percent of the sulfur entering a refinery will
be converted to hydrogen sulfide and that 95 percent of this will be
recovered as elemental sulfur, then the emissions of sulfur dioxide will
be equivalent to 3.5 percent of the sulfur present in the crude. On
this basis, the emissions of sulfur dioxide (in pounds per thousand
barrels crude) would be 224 times the percent sulfur in crude oil.
Applying this factor to the national crude sulfur average for 1966 of
0.76 percent sulfur, the emissions of sulfur dioxide expected would be
170 pounds per thousand barrels crude. When added to the 175 pounds
expected from cat-cracking operations, one gets a total of 345 pounds
sulfur dioxide per thousand barrels crude oil. This is in remarkable
agreement with the emissions reported in Table L-l. (Assuming that low-
sulfur gas rather than high-sulfur residual was the primary fuel in
these refineries in the years for which data are available.)
With the addition of a process for removal of^sulfur from the sulfur-
plant tail gas, overall recovery efficiencies can be increased from 95
to about 99.8 percent. (Claims for the Beavon process are 99.9(L"4)
percent removal, but although commercial units are currently under con-
struction, none have yet been commercially demonstrated.) This would
reduce the emission of sulfur dioxide (in pounds per thousand barrels
crude run to stills) from this source to about 9 times the percent sul-
fur in the crude oil. The Beavon process or similar technology will
probably be standard practice in new refineries by 1975.
Combustion. As can be seen from Table L-2, another significant source
of sulfur oxides in a refinery is combustion of fuel. Obviously, the
quantity of sulfur dioxide emitted depends upon the concentration of
sulfur oxides from the flue gas. Many of the process heaters used in
a refinery have heat inputs of less than 250 million Btu per hour, and
296
-------
are therefore exempt from the Federal emission regulations currently in
effect. Fortunately, a major fraction of the refinery fuel is natural
gas or refinery gas from which sulfur can be readily removed. In 1969,
U.S. refineries consumed 998 billion cubic feet of natural gas. This
natural gas accounted for approximately 36 percent of the total refinery
energy input. In addition, 985 billion- cubic feet of refinery gas was
burned. Coke and residual oil each accounted for about 10 to 11 percent
of refinery energy input in 1969. If future refineries are located at
sites other .than the Gulf Coast, or if natural gas is not available to
future Gulf Coast refineries, one can expect the use of fuel oil with
higher sulfur contents to increase.
Refinery energy consumption in the 1965 to 1969 period averaged 704,000
Btu per barrel crude oil.O-^5) Of this about 3 percent was purchased
electricity or steam, leaving an average of about 680,000 Btu per barrel.
If fuel oil with the maximum sulfur content meeting the Federal emission
regulations of 0.8 pound sulfur dioxide per million Btu were consumed at
the average fuel rate, a typical refinery would emit 540 pounds sulfur
dioxide per thousand barrels crude run to stills.
In a typical new refinery where natural gas is unavailable, about 35
percent of the energy requirements might be obtained from refinery gas,
the rest from fuel oil. Again assuming emissions from the fuel oil to
be 0.8 pound sulfur dioxide per million Btu, the average refinery emis-
sions would be about 350 pounds sulfur dioxide per 1,000 barrels crude
oil processed. The actual emissions are more likely to be controlled
by state rather than Federal limits, however, because many process
heaters have heat inputs of less than 250 million Btu per hour and are
therefore exempt from Federal regulations. Nevertheless, the assump-
tion of the Federal sulfur dioxide limitations is believed to provide
a sufficiently accurate estimate of maximum emissions for the purposes
of this investigation.
Overall Sulfur Oxide Emissions. The average sulfur content of crude
processed by U.S. refineries" in 1966 was 0.76 percent. '*•-!) Since
imports (mostly Canadian and Venezuelan) accounted for only 13 percent
•of crude runs to stills in 1966,(L-6) this is representative of domestic
production. Since it appears likely that the United States will become
increasingly dependent on Eastern Hemisphere crude oil, it is important
to recognize the impact that these new crude sources will have on the
environment. Because many of the refinery emissions of sulfur oxides
depend upon the sulfur content of the crude oil processed, a number of
cases must be considered. The cases considered and average sulfur con-
tent are summarized in Table L-3. It should be recognized that these
are typical sulfur analyses, but that the sulfur contents of crudes
from any location will vary.
The fuel consumed at the refinery is also an important consideration.
It is likely that natural gas would be consumed at a new Gulf Coast re-
finery but that residual oil and refinery gases would fuel a refinery
at other locations. The sulfur content of this residual oil would
297
-------
TABLE L-3. ESTIMATED REFINERY SULFUR DIOXIDE EMISSIONS
Crude Gravity, Sulfur Content,
S02 Emissions,
lb/1000 bbl
VO
00
Refinery Fuel
Natural gas
Residual (0.757. S)
Residual (2.3 x
Crude %S)
Crude Source °API
Nigeria (Delta) 31.0
1966 mix
Alaska (Prudhoe Bay) 27.0
Venezuela (Tia Juana) 27.0
Saudi Arabian mix 34.9
Kuwait 31.4
Nigeria (Delta)
1966 mix
Alaska (Prudhoe Bay)
Venezuela (Tia Juana)
Saudi Arabian mix
Kuwait
Nigeria (Delta)
1966 mix
Alaska
Venezuela
Saudi Arabian mix
Kuwait
% Pre-1975
0.18 54
0.76 345
0.86 383
1.5 680
1.63 740
2.5 1,140
404
695
733
1,030
1,090
1,490
248
1,261
1,308
2,290
2,490
3,820
Post-1975
43
183
207
360
392
600
393
533
557
710
742
950
237
999
1,132
1,970
2,142
3,280
-------
probably be a function of location. For illustration, residual oils
with sulfur contents of 0.73 percent and 2.3 times the percent sulfur
in the crude were chosen. The former level corresponds to the Federal
emission standard for liquid fuel while the latter approximates the
sulfur content of residual oil without desulfurization.
Nitrogen Oxides. The major source of nitrogen oxides in refineries is
in combustion operations. Refineries contribute a relatively small
proportion of the national nitrogen oxide emissions. An extensive study
of 1968 emissions in the Los Angeles area, which has a large concentra-
tion of refineries, indicates that the nitrogen oxide emissions from
refineries represented abouL 2.6 percent of total nitrogen oxide emis-
sions for the area.C^-l) The weighted percent of nitrogen oxide emis-
sions from Table L-l is 126 pounds per thousand barrels crude processed
applying standard emission factors only to the fuel oil, natural gas
and refinery gas consumed at refineries in 1969, one obtains a value of
138 pounds per thousand barrels. This ignores minor contributions from
burning of coal, coke, and other fuels in refineries. Based on these
simple calculations, it appears that a typical value for nitrogen oxide
emissions from refineries would be about 130 pounds per thousand barrels
crude processed.
Particulate Emissions. The major potential source of particulate emis-
sions from a refinery is the catalyst fines from catalytic cracking.
Lesser sources of particulate emissions are combustion, and possibly
coking operations. The standard emission factor for catalyst of parti-
culatcs from fluid catalytic cracking units is 61 pounds par thousand
barrels fresh feed.(L-2) This would be the equivalent of about 20 pounds
per thousand barrels crude. Most refineries use two-stage conventional
cyclones to recover catalyst fines, and many also use an electrostatic
precipitator to treat the flue gas from catalyst regenerators before it
is discharged to the atmosphere. Based on the data in Table L-l, it
•is believed that particulate emissions of about 12 pounds per thousand
barrels crude represent good refinery practice.-
Carbon Monoxide. The only significant source of carbon monoxide emis-
sions in the petroleum refinery is the catalytic cracking catalyst re-
generator. Carbon monoxide emissions from these units can be eliminated
by incinerating the gases in waste heat boilers. In addition to oxidiz-
ing carbon monoxide to carbon dioxide, traces of aldehydes, hydrocarbons,
and cyanides are also destroyed by this incineration. Refinery emissions
of carbon monoxide are trivial when compared with automotive and other
sources. For this investigation, it is assumed that carbon monoxide
emissions will amount to 15 pounds per thousand barrels crude processed
when carbon monoxide boilers are used.
Hydrocarbons. Hydrocarbon emissions in petroleum refineries generally
299
-------
originate from storage tanks, loading and transfer facilities, and acci-
cental spills and leaks. Hydrocarbon emissions from petroleum refiner-
ies may range from 0.1 to 0.6 weight percent of the crude oil processed
according to a 1969 report by the U.S. Department of Health, Education
and Welfare.(L~7) The equivalent of 0.1 weight percent is about 345
pounds hydrocarbon emissions per thousand barrels. The data in Table
L-l indicate that California refineries have considerably lower emis-
sions and probably represent the best control technology available.
Based on data from these refineries, an emission factor of 140 pounds
hydrocarbon per 1,000 barrels crude oil is assumed.
Odors. There are a number of malodorous compounds associated with
petroleum refining which can be detected by the human nose at extremely
low concentrations. These compounds are generally sulfides, amines,
aldehydes, and phenols. M'.ny can be detected at concentrations of one
part per billion or less. Incineration of gases containing these malo-
dorous compounds will generally eliminate them. The various smells and
odors around a refinery represent a nuisance rather than a hazard and
can be regarded as having a small, although very noticeable, impact on
the environment.
Water Pollution
The major sources of aqueous effluents from refineries are summarized
in Figure L-2.
These effluent waters from a petroleum refinery may contain many foreign
substances, including dissolved and suspended organic compounds, sus-
pended solids, dissolved salts, acids, and alkalis. The organic com-
pounds in refinery effluent consist primarily of oil, but also include
phenolic compounds, aldehydes, ketones, amines, and other organic com-
pounds.
The. usual measures of the organic content of water are the biological
oxygen demand (BOD) and chemical oxygen demand (COD). BOD is the quan-
tity of oxygen utilized by microorganisms to stabilize the waste in a
specified period of time. COD is the quantity of oxygen needed to chem-
ically oxidize the effluent water. All organic compounds normally found
in the effluent witer contribute to COD and most contribute to BOD.
Typical refinery effluent figures for the major contaminants in aqueous
effluents are summarized in Table L-4. These data were obtained in 1967.
The results of a new survey currently under way should be avail-
able by early 1973. Preliminary results of the new survey were not re-
leased for inclusion in this study.
The refineries surveyed to obtain the data in Table L-4 represented
86.5 percent of the U.S. refinery capacity. Atypical refining capacity
like asphalt plants, lube oil blending plants, and specialty plants were
specifically excluded from the tabulation. The refinery classifications
and percentage of U.S. refining capacity are:
300
-------
TYPE OF
WASTE WATER
OIL-FREE
OIUV COOLING
PROCESS
SANITARY
SOURCES OF WASTES
COLLECTION
SYSTEM
OIL-rrtCE STORM WATFR
ONCf-IHUOUCH COOLIV& WATCH
(CiA'JULIGI'TCW :>t'RV!CF.)
COOLl*<£ IWI R1'l uvifXiiVM
(Cv\"M ii iiTi •!:,' ftvirc)
SIFAU iui!iir«r ro-jni N'lLi'wAJLR
Alll rCiNDiriOV'Nv. COOLING WATER
ROOf miA'-JAG*
noLi u IHOW/DIWN
UA1FH T»EATVIf.TPl.«NT FILTER OACKWASH
A'-JO ION !• \C-4A\r.f 'JECrvEHATION WASTES
LIQUID I UOM V.-A1 f !* SCI-TtNFM
SLKDCh DEttAl LWNC
TREATMENT
OR
DISPOSITION
-»-i -ir
>l SEPARATOR
U
ONCE -IH
(C»AM1 lirAViCK SERVICE)
COOLING TOXVBR BLOW DOWN
(Cc >MJn nlAVieu .SERVICE)
OILY ST'JPM v/AI LR - UNCONTROLLED
OILY Slul.W WAI L1* -CO^TIIOLLED
PLiiALTFR WA1IR
TANii IIIIAIVOFFS
CONDI II'AIL I II-'M STRIPPING
PllMC t.l AM3 ^OCLIKC WATER
OAIH M-l flic CO\OEfl3ER »VATCR
i ni A i INC, PLANT WASH WATER
on v corus-c WAT CD
SEwtHS
PROCESS IVATFR
SPCCIAL-PURPOSC
SEPARAion
j .'lECONDAlY I
I UNITS
lOCKtlt II'JJVS A\0 LAXATOUIE5
TllROur.HO'jT THE PLANT
TllR(
5AIM-TARY SFV.FI^
.It >•.••-.-. E
I H ANT
OR
Source: American Petroleum Institute Manual on Disposal of Refinery
Wastes, p 3-5, (1969).
FIGURE L-2. EXAMPLE OF A PLAN FOR THE COLLECTION AND TREATMENT
OF REFINERY LIQUID WASTES
-------
TABLE-L-4. SUMMARY OP EFFLUENT DATA
o
to
' *.!.*• (ni0.ta.fl)
HlnUw
OU
KS &2U
*£!;..
£,£ !?i2U
i^.giaui
r.::r. !"£L»
pjii«'..l S.IIM.
HIM-**
lUMrji
•««r.r* (Afllh)
•••rv* («»10»U4)
*v:;i.
•...XI fullk)
'|U. )]'h
19.0 13.*
1.3 1? I
• 0.1
O.I U.h
O.i -13>
Hl.l JH.7
K • n.i
34 t 63 1
HOMO 1497.1
nn'h ml?
M4 t I'J
31 1 109.1
73.0 107.9
0.1 hi |
Ok 11 1
0.4 }.{
1.1
0.1
0.1
O.I
l»o
»•
».«
as i u
u_r
E
ii|i
ijii
IJhO
19 t
ft,
"So-
il.
3.6
It
J».»
10.0
701
hr.l
410
1U7.1
JI.J
hi 3
M 1
7.1
1.0
t.h
n«
S:J
»
£•
,.tl.
I 1
111 t 118 t
Jk&.l 113.1
IMI 1 3« 0
T7 » IS1 I
I1C 3 ttr.9
mi tt i
h.i 1 1
33 1 »7.3
47.1 39.}
t:i !.2
7.h 1.4
10 1 4.6
Ul 0 Jt.i
01 317
6.7 71.0
UTT.h 3390
III 9 7».h
mi iih i
114 3 171 .6
Si tr> J
.7 4>l
31 1 Ih3.1
U7.7
Mh
1.5
l!o
n;
h.i
1 1
Ml* hv ftftv tar T^.l*«M4 ta^r*1* Pi ft
*n« or itnjinrf TVTJI^ITV
1">"— "—
u^t
18 t tt 9 9tt
IJ 4 119 73.6
97 1 hi 3 M.I
17.1 k).h 43.8
79 0 lht.1 191 )
hi 1 !< 0 . 1» 9
JT.h 91 3 m 4
se.l les.i nj.o
M < 3 ».7 u 6
0.4 O.I 1 1 74
I.T h.h 11 4 Ik 4
U 3.1 17.1 K.h
1.1 I.I 11.4
o.n o • o.|
04 I.I I.I
O.| 1.) i.t
133.0 13 T H.I
1 1 10 I 0.1
T8 4 11 1 lB.h
U) 131 M4
Ss!4 701 1
|.t 71 1 109.1
1.1 l.h 11.0
1.4 hi h in.i
M b«.l , 101.1
w.r
4.1
M
l.t
':?
i i i t S
1
Am
"S3
•71
K.I
4000
ho
77,4
oil
. 11
tk V
O.3 1.0
0.3 O.I
>JJ:5
Kl
•07
7>57
0 3
U9 1
K7
1 0
1.7
9.1
0.01
1.1
19.0
O.03
....
i U
«;..,,.;
Ill 4,4
mo U9h
K 9 K ]
97 0 167 1
17.9 141 h
1 7 0.»
lh..k 17.1
I>.L 14. J
7.0 11.1
• 001
1.6 1.3
1.9 1.9
14.1 71 1
1.0 h.O
11 7 11 3
JJ « 14.}
116.7 7*1.1
m T M7.7
(ll.l 171 t
•» 1 U7.I
97.1
ll.l
10 9
M h.j
1 1 I.I
I.I. 1.0
1.1 1.0
O.I 0.1
1.1 0.1
1.0 O.h
T.O 41.7
I.I 1.7
19 n.o
14 V.I
6 4
«
lUh
43 1
Ul 1
107.7
MM t
** 1
St.
7l!l
•o.»
4.1.
6.)
130.0
97.0
117 1
US.7
»h.r
70.6
1U.T
1U.I
4.7
I.I
3.1
.
l" •
IW
1
S:!
I3WI
90
T69.0
3U 1
«• 1
04
io.
1.1
' O T
0.9
"So
hl.l
U.I
Ufeoo
v/n o
101.1
1 l
> 7
0.9
e.i
03
a.
MlMfll
O.I
n't
Cmo
h.9
llh.3
l».f
»'l
K 0
11.7
»..
«
>3.7
17.)
hSorJ.«
0.1
TK7
0.1
117 0
09.9
hi 1
3 1
1.7
9.1
0.01
we
O.O)
19.1
n.o
I»
•rIM »
"SS
U.I
*I09
109.1
107. l
s!
11.6
>.9
17
"S!
3<7
n.o
Ttjoo
IllfO
971
1 h
hi 8
hj.4
10 7
h 7
37
1.9
O.I
1.1
1.0
11.4
9.1
U.J
f>
-""
1184
IhSl.l
770 h
•n l
O.h
309
U h
e 01
II) 0
e i
13.1
iin.h
Si
ss
U.)
117.7
in i
141
1 |
0 1
0 7
497
111
11.1
J»
63.1
I00«
101.4
IV I
hit h
3W.1
T;
4l!l
•H
40
6.1
130.0
,s.
"S!
nv. g
I1O 1
63 i
119.9
IM.J
4T
',1
9J
ir
n.7
as.
2
Source: American Petroleum Institute, 1967 Donestic Refinery
Effluent Profile (Sept, 1968). .
-------
Percent
A Topping plants 3
B Topping and cracking 28
C Topping, cracking, and petro- 19
chemical
D Integrated (topping, cracking, 20.5
and lube processing)
E Integrated and petrochemical 16
The types of waste water treatment described in Table L-4 are primary,
intermediate, and biological. Of the refinery capacity included in the
survey, 38 percent used primary, 13 percent intermediate, and 49 per-
cent biological treatment. Primary treatment is gravity separation
only. This is accomplished in API separators or similar equipment.
Intermediate treatment includes chemical flocculation, air flotation
with or without chemical addition, or filtration. Biological treatment
includes activated sludge, trickling filter, stabilization ponds with
and without aerators, and biological oxidation in cooling towers.
The arithmetic average referred to in Table L-4 is the average of the
refineries reporting, while the weighted average is the average of the
crude oil throughout. The weighted average will be closer to practice
in larger, newer refineries, although the differences between the arith-
metic arivi weighted averages are probably not significant.
For the purposes of estimating effluents from future conventional re-
fineries, the data in Table L-4 on refinery categories B, C, D, and E
were combined on a judgmental basis. Category B would be most repre-
sentative, but it includes many smaller, older refineries. C and E
include petrochemicals which are excluded from this analysis. D and E
include lube oil processing which will be included in some but not all
new refineries. New refineries will probably be equipped with biological
or intermediate waste water treatment systems. The estimated water
pollutants from new refineries are summarized in Table L-5. These esti-
mates are highly subjective and should be replaced when better data be-
come available.
Solid Wastes
There are three types of waste which comprise most of the solid wastes
from a petroleum refinery. These are sludges containing water and
solids; sludges containing oil, water, and solids; and biological
solids. There is also the usual trash, paper, etc., associated with
most businesses.
The sludges containing water and solids but no hydrocarbons generally
come from raw-water treatment. The quantities of these solids depend
almost entirely upon the quality and quantity of raw water used by the
303
-------
refi: ery. These solids are generally recovered In settling ponds, or
by filtration or centrifugation. They will generally be disposed of
eventually in landfill. Another source of solids which do not contain
oil are catalyst fines. As the particulate emission standards arc en-
forced, the spent catalyst fines will represent an increasing source of
solid waste. Again landfill will be the ultimate disposal method. The
fines obtained in the manufacture of petroleum coke are usually dis-
posed of by percolating a slurry of these fines through the coke car.
The fines arc filtered out in this percolation.
TABLE L-5. ESTIMATED AQUEOUS EFFLUENTS FROM
NEW REFINERIES
Founds per Day per
Thousand Barrels per
Day
BOD 30
COD 110
Oil 8
Phenols 2
Suspended solids 20
Dissolved solids 500
Alkalinity nil
Sulfide 2.5
Phosphorus 1
Nitrogen 4
Sludges that contain oil in addition to water and solids present the
most difficult solid waste disposal problems at a refinery. These
sludges are obtained primarily from API separators and consist of water,
iron oxides and sulfides, sand, silt, and clay obtained from the crude
oil. Tank bottom sludges, and sludges from biological treatment pro-
cesses 'are additional sources of these solid wastes. These sludges are
frequently dewatered by centrifugation or filtration and then either
incinerated or spread thinly over vacant land at the refinery site to
enable decomposition by soil bacteria.
Biological solids are produced by most biological processes. The quan-
tities of excess biological solids from biological treatment processes
depend upon the operation of the process.
Little useful quantitative data on the amount of solids which must be
disposed of from a typical refining operation were obtained during this
investigation. Some data on solid wastes collected by the State of
Pennsylvania were reviewed, but the quantities appeared to contain mostly
water and were not, therefore, considered useful. It is believed that
the State of California has also surveyed solid wastes emissions from
304
-------
petroleum refining, but these data were not available for our review
during this investigation.
Data on typical sludge volumes from one 42,000 barrel-per-day refinery
were obtained, however. These volumes would be 700 to 1000 cubic yards
per year. This is equivalent to 0.061 to 0.087 cubic yard per 1000
barrels crude run to stills. (L-8) The quantities of solid wastes will
be greatly influenced by the refinery location and by the degree of
enforcement of air and water emission regulations. One generalization
which can be made: as the air and water emission regulations become
increasingly more restrictive, the solid waste disposal problem due to
increased treatment will increase. A value of 0.08 cubic yard sludge
per 1000 barrels was taken as typical for the purposes of this study.
Energy Requirements and Thermal Emissions
In the five years, 1965 through 1969, U.S. refineries consumed an aver-
age of 704,000 Btu per barrel crude oil run to stills.(L-5) This energy
consumption will have an impact in that it is energy not available for
other uses. Furthermore, this energy consumption is, for the most part,
rejected to the environment in the form of heat. This heat escapes as
flue gas, heated water, and as radiation to the atmosphere. Such re-
jected heat does not necessarily constitute a form of pollution, however.
In many instances it may even provide beneficial effects on the environ-
ment. Nevertheless this energy requirement and heat rejection is a
factor which should be considered in any thorough analysis. A breakdown
of refinery fuel consumption by type of fuel is given in Table L-6.
Noise
There is a certain amount of noise associated with normal refinery oper-
ations. Since most U.S. refineries are located far from residential
areas, however, this noise does not generally present a problem. Re-
finers like many other industrialists recognize that excessive noise can
present problems and generally strive to obtain the quiet operation in
new facilities when this can be achieved at low cost. In this investi-
gation noise from refinery operations is considered to have a negligible
impact on the environment.
Land Use
A modern petroleum refinery requires a large area. Most of this land is
needed for tank farms to store crude oil and products. Relatively
little land by comparison is used for the process facilities. An in-
creasing amount of land will be needed for pollution control, e.g.,
settling ponds, water treatment plants, disposal sites for oily sludge,
etc. In addition, there is usually a buffer zone at least 500 feet
wide surrounding the entire refinery.
It is very difficult to generalize on the land requirements for a new
grass roots refinery because each site represents a special situation.
305
-------
TABLE L-6. FUELS CONSUMES AT U.S. REFINERIES. 1925-1969
V«f
|94t*»t««4>a*l
it'.t"!^"!
1941
lit*
I9«l
19-1
IHI. .......
11-9
Hll
l,,|
mi*'1.!""
IVt
ii'i
Illl
mi
11!!
iri!!!!!'.l!
it.t
mi
17.7. .......
11.1
ii"".'.!!!!!!
mi
11*1"*""""*
1111 1.,..^,,
in) .,.,.,.,
Itlt
1111 ........
l**l
Ilil
H':'!!.'"!'
mi'
ii-i
11)9*
itji!"!""
11:1 !!!!!!'.!
r.ieui
W GJ'.""J)
4) 111
41 ill
inii
114*9
114*1
11 111
It 111
49*11
41 III
•U«l
114 1
11 111
17.111
H.1H
49911
11 -II
41 !>l
1'JU
mil
If -17
II 1.1
11 III
I*CII
11 III
21 ICI
11.114
;t ft
11 • t
II* IT
11. '41
11:11
11 Ml
Mill
41 Hi
11.1*4
44.1*11
4-44!
41 411
1C .111
&.
•f DvM.ll
tJ
1(1
111
191
141
ICO
491
911
1.191
Ull
11 •
SJi.
l*:o
1 111
4.1)1
1.101
4.1:1
1719
11)9
s::i
4 4.11
4J14
4JI7
4*11
*.OC1
1 1(7
*!i»
4 I;F
1111
4101
'*!*
l.lil
::::
«n£.U
T»«i)
110
lit
lit
til
114
Tl!
Ill
711
14;
Ml
1 01'
I'l
I*}!
ill
in
I.IIO
1011
[.Oil
I**t
1 111
l.lll
lill
l.lll
1 III
I!IM
1 OH
tit
141
111
1 191
1 110
i.iii
Kit
in
1*11
ii-t
IJOO
J>il
1011
toil
1.1 11
lhl.nl Cil
reel)
171 JS4
1 11*11
lit Ml
11 : 101
•17 tit
i:i*7i
7M11I
911 111
191 Jit
en )14
4-1 ::o
471 '41
41) :*)
J41JI1
591(11
411014
411 117
4*-<70
1 U111
i.'i ):o
1)1111
111)11
9'IJ'I
101 lio
1*1 ill
fi>il
19« 111
HUM
tl III
19111
1U41
Jl^ll
11 HI
10) lit
M":o
1:1 >ii
'Hi!!
i*i.i .*••
r«»ij
in HI
111 l<9
IlUlt
H: ):>
111011
1)0.1 '1
i?* tos
linn
71! Ill
74)011
7:i ill
|1<4'9
101 J 14
411 111
*:i in
I7C C1I
1(1.411
111 111
li'iil
)ll.ll>
11(311
141111
1110:1
19: in
j'liu
I1! Ill
i:* 471
in in
n* i* i
11! «1
111(1*
1*1111
111)11
11.117
11.11 1
11*11
1:017
fc'."5i"
!u»llt
ii«7cco
til* WO
II II". OM
II 711 " J
ll.ti:OCO
II 4** CM
10 11! CM
fill CM
S4.11PCS
145' "10
4.1:1:19
i r. noi
• »:.oii
lii'iii
1 til Ml
1111*11
JliUll
Jill III
1011 111
l.'ll III
IOH III
1 '11111
l.MI Oil
JJ4J.11*
1.400 <-l
1 lie ill
I 111 0:1
107. 1*1
1.0:1111
•CO*4I
til til
• >••
::::
*Cii
•r
BlfTtlt)
11:9
3 C«»
10 <11
9 *99
i'"
T*
JOJ
4.10>
«...
• • •
• • •
• i •
..••
••••
..I.
1 ••>••
• ••••
• •••
• >•>•
• *•• '
...•
• *••
• •••
::::
tsr*
•rr.i.iwo '
14 III
i: 11 1
mil
it nt
n VH
:o.:n
:**! *4I
>: t ::>
!!•• I.I
>l '. Ill
till IT)
j::-. 1-5
ifn :i*
in* '.11
i.ri HI
t 5'1! *l "0
1.1-4 101
i :i* en
1,'lClJI
Ml* 'It
1.1:1:19
to 111
11111:
"** tii
4I5.«"J
ICI^'I
Clt f '.I
1)1 l-t
911 :n
111 471
I'm)
II1 *93
I1KO
110 III
ICI "14
11X11
41! Ml
Cnt.ft
.' Oi^Ts)
'. . • 1 ll".?!
) 11* It]
i i:n!t
1 i:*csi
I -tt.'i
it i in
lll.M'l
1111111
: i-( 111
I1T l»»
i:\ ri
II!4I'.I
.> ,-!'^ii
i i« ::i
IC'I lit
11 iilT
i linn
Ut! Ill
i *:i ~n
IJ>< 91
1 07111
! :" "*
1.111 ".f
1.11*4*9
93*>)l
IIV •»!
lit 491
197 :*i
711 :n
!•5o99
*I4 C^l
7)f-M
TJ* ' .)
9IIM/I
71:''^
7:7 c^o
Itt C',5
4-1 6--i
III 0*4
4*C '. ^0
in cn
tit ::t
i:* va
41:0-0
4*-C-0
*J!r'°
i/JiO
III P'*9
4:1; o
i;ijy»
•tl r7)
• 4« 'j*WJ
i;:c-o
iii:-j4
i
II'I
MI:*
ii i
Ifjl
1-1*
ii|l
"I""! l11!^
ri:
Illl
i;n
!.;^
I;!!!!! iiu
II'I
Illl
1*11
DO
ID;
mi
mi
n *
mi
nil
nil
111!.
iti.i
17 J
•••.... i*:i
1:1
it:i
I Irtiufri tmill ;ioi 10 HJT.liqucncd pciiotiura piu< pvitiund ittim in not npetucui t:»i(c h litc:v<<(] vlili (till ell.
» FIIM 10 192". puicluKt il:culciv 1> "<" itfmwl icpinttly.
Auimniyl Zjnu 4>f KlMi. Htotritliitvirrr Sfrtfi. Titrolnim Juum'mu."
Source: Axe rlean Petroleum Institute, Petroleum Facts & Figures. 1971 Edition.
-------
A very crude estimate of minimum requirements would be 2 acres per
thousand barrels per day for the refinery itself. Actual total land
for new grass roots refineries averages about 21.8 acres per thousand
barrels per day.(L~9) This generally allows room for expansion. Ex-
isting refineries, which have been expanded, average about 12.5 acres
per thousand barrels.
Fue1 Oil Refinery
At the present time, import regulations encourage the importation of
residual fuel oil while discouraging imports of other petroleum products.
This import policy, combined with the conventional pricing of petroleum
products, discourages production of fuel oil in domestic refineries. If
a change in regulations were made, it is probable that a number of re-
fineries might be constructed in the Eastern United States to maximize
fuel oil. Such a refinery would be quite different from the conven-
tional U.S. petroleum refinery. Although there are many different re-
finery configurations, for the purposes of this investigation it is
expected that a typical topping refinery would include crude oil re-
ceiving and storage facilities, a crude desalting unit, atmospheric crude
still, residual oil and distillate hydrodesulfurization units, a hydro-
gen plant, a sulfur plant, and product storage facilities. Sulfur
dioxide emissions from the sulfur plant with and without a sulfur-plant
tail gas desulfurization unit are considered in this section.
It is expected that the topping refinery would operate on a Mid-East
crude. Refinery yields would be expected to be about 60 percent fuel
oil and 30 percent naphtha. Unless otherwise indicated during the dis-
cussion, a typical Kuwait crude (2.5 percent S, 31.4° API)(L-10) is
assumed as feed. The sulfur content of this crude would be about 7.6
pounds sulfur per barrel. It is assumed that the fuel oil from this
refinery will have a sulfur content of 0.7 percent.
Air Emissions
The air emissions from the topping refinery will come from sources
similar to those listed in Table L-2 for the conventional refinery but,
because of differences in refinery configuration, there will obviously
be differences in the emissions.
Sulfur Dioxide. Sulfur Plant. In a topping refinery, the two major
sources of sulfur dioxide emissions will be the tail gas from the sulfur
plant and sulfur dioxide emitted in combustion gases. Based on the
assumptions stated in the description of the refinery, and ignoring the
small amount of sulfur present in the naphtha, and assuming that the Claus
sulfur plant will recover 95 percent of the sulfur from' the desulfuri-
zation units, the emissions of sulfur dioxide in the rail gas from the
307
-------
sulfur plant would be 632 pounds sulfur dioxide per thousand barrels
crude processed. Addition of a Beavon process or other process to re-
move sulfur from the sulfur plant tail gas would result in an overall
recovery of about 99.8 percent and emissions would be reduced to 25
pounds per thousand barrels crude.
Combustion. Because the topping refinery is somewhat simpler than the
conventional refinery, it is expected that somewhat less energy would be
required for its operation. Although a detailed energy balance would
be required in order to obtain an accurate figure, for the purposes of
estimating the emissions, it has been assumed that the fuel oil consump-
tion will be the equivalent of about 70 percent of the energy, consumed
in a conventional refinery. Assuming that the fuel emits 0.8 pound
sulfur dioxide per million Btu (i.e., that the refinery is forced to
burn fuel oil rather than natural gas) the emissions of sulfur dioxide
from combustion in the refinery would be about 380 pounds per thousand
barrels crude run to stills.
Nitrogen Oxides. Essentially all nitrogen oxides from the topping
refinery would result from combustion operations. It is anticipated
that fuel oil and refinery gas will be the only source of refinery
energy for such a refinery. Assuming that the topping refinery uses
about 70 percent of the energy per barrel consumed in a conventional
refinery, and using the standard emission factor of 2.9 pounds nitrogen
oxide per barrel oil burned,(L-2) the emissions of nitrogen oxide
would be about 170 pounds per thousand barrels of crude processed. It
is assumed that nitrogen oxide emissions will be somewhat reduced by
improved burner design. To allow for this reduction, emissions, due to
burning refinery gas were ignored.
Particulates. In the topping refinery the combustion of refinery fuel
will account for essentially all particulate emissions. Based on the
same assumptions discussed above, and using the standard emission fac-
tor of 0.84 pound particulates per barrel oil burned,(L-2) the particu-
late emissions would be 49 pounds per thousand barrels crude oil
processed.
Carbon Monoxide. The emissions of carbon monoxide from the topping re-
finery will be negligible.
Hydrocarbons. Hydrocarbon emissions in the topping refinery will origi-
nate from storage tanks, loading and transfer facilities, and accidental
spills and leaks. Because a typical topping refinery will have a
smaller quantity of light products than the conventional refinery which
is designed to maximize gasoline production, the hydrocarbon emissions
from the topping refinery will be less. Thus, the emission level of
about 140 pounds hydrocarbon per thousand barrels crude from a conven-
tional refinery with good emission controls will set an upper limit.
Assuming the emissions are about 60 percent of those from the conven-
tional, gasoline-maximizing refinery, the hydrocarbon emissions would
be about 84 pounds per thousand barrels crude run to stills.
308
-------
Water Pollution
The major sources of water pollution from a topping refinery will be
the same as those from a conventional refinery, although the quantities
of phenols will generally be lower. The quantity of water pollutants
from a modern topping refinery wore derived using our best judgment
from the data collected in 1967 (see Table L-A). These estimates, which
are highly subjective, are summarized in Table L-7.
TABLE L-7. ESTIMATED AQUEOUS EFFLUENTS FROM NEW4
TOPPING REFINERIES
Pounds per Day per
Thousand Barrels per Day
BOD 30
COD 110
Oil 8
Phenols 0.8
Suspended solids 20
Dissolved solids 500
Alkalinity nil
Sulfide 0.5
Phosphorus 1
Nitrogen 4
Energy Consumption
A detailed energy and material balance would be required to estimate the
fuel consumed in a topping refinery. Although the energy requirements
may be somewhat lower than that for a conventional refinery because there
are fewer stills, pumps, etc., there are a number of units like the
crude still and hydrogen plant that will consume significant quantities
of energy. Therefore, as a first approximation it is assumed that the
topping refinery, like the conventional refinery, will consume about
700,000 Btu per thousand barrels crude run to stills. Further, it is
assumed that about 70 percent will be supplied as fuel oil, 30 percent
as low-sulfur refinery gas, and light distillates.
Allocation of Pollutants to Products
A petroleum refinery makes numerous products, and it is rarely possible
to associate a specific pollutant with any one product. For the pur-
poses of calculating the emissions associated with the modules in this
study, the emissions were allocated on the basis of the heat content of
crude oil input. The world average heat value of 5,850,000 Btu per
barrel crude oil was used.'k-H) This is somewhat higher than the U.S.
309
-------
average of 5.6 million Btu per barrel crude. It is anticipated that
new refineries will rely almost totally on foreign crude. Therefore,
the world average was thought to be the better value. A further assump-
tion used in allocating pollutants was that all the energy consumed in
refinery operation will be derived from crude oil or petroleum products.
A sample calculation of nitrogen oxide emissions based on these assump-
tions is carried out as follows:
0.130 Ib NO /bbl crude • -
x = 0.0254 Ib NO /10 Btu
, „,. ,n6 _ .... , (. 704 Btu consumed ^\ --- - x
5.85 10 Btu/bbl crude x
-------
Another approach would be to attempt to allocate the pollutant to the
source within the refinery, and thence to the specific product. Most
of the sulfur is concentrated in the heavy fractions of crude oil and
could be logically allocated to the residual fuel oil and other heavy
products. Similarly, the carbon monoxide from regeneration of cracking
catalysts could be Logically assigned to gasoline manufacture.
For the purposes of policy planning, little advantage is seen in attempt-
ing to apply increasingly sophisticated allocation methods. The final
results should not be greatly affected by the allocation method, and
the method used is believed to be suitable.
Alternatives have been briefly discussed to enable the reader to make
his own judgments and modifications to suit his specific purpose.
By-Products
The major nonfuel by-products from a petroleum refinery are sulfur and
petrochemical feedstocks. Petrochemical feedstocks, which can also be
used as fuel', have not been considered in this study.
In 1966, 30 percent of the sulfur contained in crude oil went into the
products. 0-"'-) This would have been the equivalent of about 0.23 per-
cent sulfur in the crude ending in the products. Since 1966, the sulfur
content of No. 2 heating oil has decreased about 12 percent and of No. 6
fuel oil (residual) by about 3 percent.(L-6) Most of the sulfur in pro-
ducts is not in these heavier fractions. To allow for further reduction
in the sulfur content of petroleum products, it has been assumed that
the equivalent of 0.2 percent sulfur in the crude oil will be in the
products.
For the purposes of estimating sulfur by-product, it is assumed that
the remaining sulfur present in the crude oil is converted to elemental
sulfur, and that this sulfur is allocated on the basis of heating value
of the crude oil less the energy consumed as refinery fuel. A density
of 7.29 pounds per gallon (API 30) was assumed. A sample calculation
of sulfur by-product for crude with 2.5 percent S is carried out as
follows:
(2.5-0.2) Ibs 7.29(42) Ib crude I Btu crude
100 Ib crude X 6.3 10° Btu X 0.88 Btu products
«=' 1.27,lb S/106 Btu.
Based on these assumptions, the approximate production of by-product
sulfur from the processing of various crudes is summarized below.
311
-------
Sulfur in Crude, Sulfur By-Product,
Crude J. Ib/million Btu
Nigeria (Delta) 0.18 0
1966 Domestic Mix 0.76 0.33
Alaska (Prudhoc Bay) 0.86 0.39
Venezuela (Tia Juana) 1.5 0.77
Saudi Arabian Mix 1.63 0.85
Kuwait 2.5 1.27
The accuracy of the data does not justify more sophisticated estimates.
The next level of sophistication would take actual product sulfur con-
tents and the sulfur dioxide emissions into account. The improvements
obtained by such a calculation would be small compared to the uncertain-
ties in the source and composition of crude oil.
Cost of Pollution Control
The cost of pollution control by refineries may be broken down into
the costs due to the use of low-sulfur fuel for refinery operations and
the costs due to installation of equipment to control emissions other
than those from fuel combustion.
Nonfuel Costs
The measures which must be taken to reduce pollution from refineries
under current or anticipated regulations include
1. Removal of hydrogen sulfide from all refinery fuel gases, conver-
sion of this hydrogen sulfide to elemental sulfur in sulfur plants
equipped with tail gas scrubbing
2. Installation of floating roof tanks for all gasoline and volatile
crude storage tanks with capacity greater than 40,000 gallons
3.- Installation of electrostatic precipitators to remove catalysts
fines from the vent gases from cracking catalyst regeneration units.
It is anticipated that controls would be required only on units with
capacities over 10,000 barrels per stream day. (This excludes 27
crackers in 25 refineries representing 10 percent of the total cracking
capacity.)
4. Incineration of the gases from regeneration of cracking catalysts
in a carbon monoxide boiler. (The same exclusion of small units as in
Number 3 is anticipated.)
5. Reduction of biological oxygen demand, and removal of oil and sus-
pended solids from waste water in an effluent treatment plant.
312
-------
In a new refinery, the cost of installing the necessary pollution con-
trol equipment described above is estimated to be $46 per daily barrel
of capacity, while in existing refineries the cost is estimated at $56
per daily barrel.1^-12) Assuming that capita] related charges amount
to 35 percent of capital investment annually, this would amount to
$0.045 per barrel crude processed in new refineries. These capital re-
lated charges could be broken down to include 6.25 percent for depreci-
ation (16 year, straight-line); 2.75 percent for insurance, taxes, etc.;
3 percent for maintenance costs; and 23 percent before tax return-on-
investment. The costs of operating pollution control equipment is esti-
mated at $0.004 per barrel crude.(1—12) Thus, the expected increase in
the cost of petroleum products from new refineries which is attributable
to the installation of pollution control equipment, would be about $0.05
per barrel crude run to stills.
Fuel Costs
It is very likely that a new refinery will be unable to purchase
natural gas for use as a refinery fuel, and will therefore burn residual
fuel oil. Most of the process heaters in refineries have he;:t inputs
of less than 250 million Btu per hour and are exempt from the Federal
sulfur emission regulations. Depending upon the refinery location,
state regulations would probably require the use of a low-sulfur fuel.
In a typical refining operation, about 700,000 Btu are required per
barrel crude oil processed. Assuming 30 percent of this heat require-
ment can be supplied by burning refinery gases, the remaining 70 per-
cent would be supplied in the form of fuel oil. It is also possible
that a refiner might burn crude oil, but the crude oil is more valuable
than the heavy fuel oil. Unless there is some extreme economic distor-
tion caused by Government action, crude oil will be refined rather
than consumed as refinery fuel. If one assumes that the fuel oil must
be low sulfur (0.7 percent) and is valued at $3.50 per barrel, and
that current refiners consume natural gas valued at $0.22 per million
Btu, the increased cost due to the use of low-sulfur fuel oil would be
about $0.17 per barrel crude run to stills. In practice, the cost
increase will be a function of specific refinery characteristics, but
it will probably be in the $0.15 to $0.20 per barrel range.
References
L-l. National Petroleum Council, Environmental Conservation, Vol.' 2,
p 182, February, 1972.
L-2. U.S. Environmental Protection Agency, Office of Air Programs,
Compilation of Air Pollutant Emission Factors (revised), February,
1972.
313
-------
L-3. EPA draft of Technical Report No. 8, Petroleum Refineries Burning
of Gaseous Fuels, April 27, 1972..
L-4. Beavon, D. K., Pollution Engineering, p 34, Jan/Feb, 1972..
L-5. American Petroleum Institute, Petroleum Facts and Figures. 1971
Edition.
L-6. U.S. Bureau of Mines, "Crude Petroleum and Petroleum Products:
1966", Mineral Industry Surveys, December 5, 1967.
L-7. U.S. Department of Health, Education, and Welfare, Atmospheric
Emission from Petroleum Refineries, A Guide for Measurement and
Control, Publication No. 763, p 188, 1969.
L-8. Private communication with industry.
L-9. Nelson, W. L., Oil Gas Journal, TQ. (56), December 4, 1972.
L-10. International Petroleum Encyclopedia, 1972 Edition, Petroleum
Publishing Company, 1972.
L-ll. U.S. Bureau of Mines, Burner Fuel Oils, 1972, Petroleum Product
Survey 76, July, 1972.
L-12. Stephen Sobotka & Company, "The Impact of Costs Associated with
New Environmental Standards Upon the Petroleum Refining Industry",
prepared for the Council on Environmental Quality, November 23,
1971.
314
-------
APPENDIX M
GASIFICATION' OF CRUDE OIL AND NAPHTHA
Table of Contents
Crude Oil Gasification « . . . 315
Naphtha Gasification 324
References- 326
List of Tables
M-l. Gaseous Emissions from Naphtha Gasification Plant .... 325
M-2. Liquid Effluents from Naphtha Gasification Plant 325
List of Figures
M-l. Schematic Drawing of Energy Refinery for Processing
High-Sulfur Crude Oil 318
315
-------
APPENDIX M
GASIFICATION OF CRUDE OIL AND NAPHTHA
Crude Oil Gasification
Summary
As of late 1972 there are no gasification plants anywhere of the sizes
proposed for the United States, for cither naphtha or crude oil.
Technology for the gasification of light petroleum feed stocks such as
naphtha has been developed and there are over 70 such plants in Europe
and Japan.^ ' However, these plants produce a gas in the 500 to 560
Btu/scf range, lower than that required for SMG (1,000 Dtu/scf). The
relatively limited supplies of naphtha will necessitate addition of
crude oil as a feed stock rather quickly and, within a few years, the
majority of plants producing SNG will undoubtedly be based on crude oil
with the products being SNG and low-sulfur fuel oil. Gasification pro-
cesses will be based on the Catalytic Rich Gas (CRG) process, the
Methane Rich Gas (MRG) process, the Fluid-Bed Hydrogcnation (FBH.) pro-
cess, or variations of these.
The projected emissions of air pollutants from crude oil SNG plants
during the 1975 to 1990 base period arc estimated to be approximately
as follows:
Ib/M bbl Input lb/106 Btu (Output) lb/MKhr
S02 250-500 0.05-0.10 0.50-1.0
Particulates 10 0.002 0.02
CO Negligible Negligible Negligible
HC 20 0.004 0.04
NOX 400 0.08 0.8
Salt content of crude oil may be in the range of 100 Ib/M bbl, and one
of the principal liquid wastes from a crude oil SNG plant will be the
brine resulting from desalting the crude oil. With proper precautions
there will be almost no other liquid wastes issuing from a well-designed
SNG plant.
Solid wastes attributable to the production of SNG from crude oil will
include those from the treatment of the water required by the plant,
and from treatment of the waste streams. There will be, in addition,
discharges of spent catalysts not worth reclaiming. As an approxima-
tion, a figure of 0.25 T/M bbl (based on one projected plant design)
is taken.
316
-------
Because of the wide variety of feed stocks and purification techniques
available, it is difficult to present meaningful cost information.
Based on some unpublished information, cost of conversion of a high-
sulfur crude to SNG is in the range of $0.50-0.60/10^ Btu (for a
100,000 bbl/day plant). This does not include the cost of the crude
oil. To obtain the SNG selling price, calculate the crude price in
$/106 Btu and multiply by a factor of 1.3 (i.e., 1/0.77) due to the
thermal efficiency of the plant, and add it to the crude-to-SNG con-
version cost given above.
Technology
As of late 1972 there are no gasification plants anywhere of the sizes
proposed for the United States, for either naphtha or crude oil. There
are also no plants producing a substitute natural gas (SNG) with the
heat content of 1,000 Btu/scf required in the United States'for pipe-
line quality gas. Technology for the gasification of light petroleum
feed stocks such as naphtha has been developed and there are over 70
such plants in Europe and Japan.(M~l) However, these plants produce
a lower-Btu gas, in the 500 to 650 Btu/scf range.
The technology required for the gasification of crude oil is available,
in that the several operations involved have been individually proved,
but to date they have not been demonstrated as a unified whole. For
this reason, and because of the present costs and availability of
naphtha, most (20 or so) of the gasification plants projected for the
immediate future will gasify naphtha.(JI~2) However, the relatively
limited supplies of naphtha will necessitate addition of crude oil as
a feed stock rather quickly and within a few years the majority of
plants producing SNG-will undoubtedly be based on crude oil. By 1975
it is estimated that there will be at least a half-dozen crude oil SNG
plants constructed, with a capacity of 2,500 to 4,000 106cu ft/day. By
the fall of 1972 seven crude oil to SNG plants had been proposed, all
of 100,000 bbl/day or more capacity. All will make SNG and all but two
VTill make low-sulfur fuel oil as vrell.(M~3) Gasification processes
used will be the Catalytic Rich Gas (CRG) process, the Methane Rich Gas
(MRG), or the Fluid-Bed Hydrogenation (FBH) process, or variations of
these< Another possibility is to utilize existing conventional re-
finery technology to crack middle distillates and heavier to naphtha
by hydrocracking followed by gasification of the naphtha. This will
probably be in conjunction with production of low-sulfur residual fuel
oil as a co-product.(M-4) The heavy residue may be coked, with subse-
quent gasification of the coke to produce a low-Btu gas (100-150 Btu/
scf) for plant consumption.
A typical flowsheet for this scheme is illustrated by one proposed by
M. W. Kellog Company for the lower-cost, fairly high-sulfur crude that
is usually most readily available to the energy refinery.(M-3) xhe
process is shown schematically in Figure M-l. Basic elements of the
process are as follows:
317
-------
* SNG
Coke with metals
FIGURE M-l. SCHEMATIC DRAWING OF ENERGY REFINERY FOR
PROCESSING HIGH-SULFUR CRUDE OIL
318
-------
"Virgin naphtha from crude distillation goes directly to the SNG
plants, after dcsulfurization. Atmospheric and vacuum gas oils are
either hydrocrackcd to make more naphtha for Lhc SNG unit or are hydro-
desulfurizcd for low-sulfur fuel oil. Asphalt or crude stillbottoms
arc partially oxidized to make the hydrogen needed for the hydrocracker
and the various desulfurization units. H2S is converted to elemental
sulfur.
With lighter crude oil such as Iranian light, the flowsheet could
be simplified. The vacuum distillation unit might not be-'required, and
the dcasphalting and partial oxidation wouldn't be needed. Furthermore,
a light crude might be desulfurized whole, doing away with the need for
downstream desulfurizing of various products. Thus, this energy
refinery would be little more than a topping plant, typical of the
overseas refineries built to make naphtha and fuel oil."
All of these processes will require methanation of the initial gas pro-
duct in order to increase its heating value to the 1,000 Btu/scf
required for pipeline gas. If the gas were produced in a satellite
plant connected to a central power station, a lower-Btu gas would
suffice, and the methanation step could be avoided. This may be a
future development over the next decade.
Since the basic SNG process technology has not yet reached the stage of
normal commercial application, neither has the pollution control tech-
nology whicli will be associated with these plants. Nevertheless, the
control problems are sufficiently analogous to those of refineries that
they can be satisfactorily defined.
Environmental Factors
Air. The principal pollution problem will undoubtedly be sulfur
dioxide. Characteristically, crude-oil SNG plants will draw their feed
stocks from lower-grade, nonpremium crudes, and sulfur contents in the
2 to 4 percent range will be typical. Thus, for a nominal 100,000 bbl/
day plant, from 325 to 650 T/D of sulfur must be disposed of. Most of
the sulfur will be released during processing as t^S, which is amenable
to removal and recovery by successfully demonstrated processes. Usually
this will be accomplished by a Glaus plant, backed up by a tail gas
treatment plant using one of several available processes. Total re-
coveries in the 99.5+ percent range can be achieved on the main gas
stream with "reasonably available technology". Depending on the
particular processing scheme employed, an overall plant sulfur removal
of about 98 percent can be anticipated in the 1975-80 period. For
"typical" crudes available for SNG, this will place S02 emissions in
the range of approximately 250 to 500 pounds S02/M bbl processed.
The sulfur found in cither the residuum or the coke will not be as
easily recovered. Several hundred tons of coke per day is produced,
which may be high in sulfur unless the feed is hydrodesulfurized before
coking. If the coke is burned for fuel directly, flue gas scrubbing
319
-------
or a'comparable control measure may be necessary to meet existing regu-
lations. Alternatively, the coke can be gasified by a partial oxidation
scheme, and the low Btu gas desulfurized before its utilization as
refinery fuel. Another alternative incorporates a hydrodcsulfurizcr
and fluid catalytic cracker ahead of the cokcr, which will reduce the
sulfur content of the coke.
SNG plants will supply their own fuel. Normal fuel for the various
process heaters and furnaces will be hydrodcsulfurized oil or refinery
gas drawn from the process (otherwise the sulfur content would be far
too great). These will be high-grade fuels, low in sulfur, and S02 and
particulate emissions will be minimal.
Particulate losses may be expected to occur primarily where any coke
produced is burned or in the catalyst regenerator, if a cat-cracker is
included in the process flowsheet.
If a cat-cracker is used, approximately one-third of the fresh feed may
be cracked. With previous technology, characteristic particulate
emission rates found by EPA were about 61 Ib/M bbl of fresh feed,™ ^'
equivalent to approximately 20 Ib/M bbl of refinery throughput. With
present particulate removal technology, this is substantially reduced,
to the extent that total particulate emissions in the range of 10 Ib/M
bbl of crude oil input are anticipated for SNG plants.
CO emissions will have significant potential only in the case where a
cat-cracker ic employed. However, since use of CO boiler for combus-
tion of regenerator gases will undoubtedly be required by soon-to-be-
enactcd regulations, CO emissions will be negligible, in the few ppm
range.
Hydrocarbon emissions from an SNG plant will be essentially only those
from tankage; any other hydrocarbon emissions should be minimal, since
the processing is conducted in a closed system, and there are not the
multiplicity of products to work up and clean up, as in the usual
refinery.
The product SNG is not stored so any hydrocarbon losses are restricted
to "feed stock and intermediates storage. In order to insure continuity
of operations, total feed stock and intermediates storage will probably
be in the range of 50 days throughput. However, since the major stored
materials are the relatively nonvolatile crude oil, residuum, and gas
oils, losses are negligible. Based on EFA emission factors, daily
losses of no more than 20 Ib/M bbl throughput are estimated.
Nitrogen oxides will be released in all combustion operations; by
suitable design of the combustion equipment these can be kept below the
allowable level of 0.3 lb/106Btu permitted by present EPA regulations
for new stationary sources burning liquid fuel.
320
-------
Energy efficiency of a crude oil SNG plant will be in the 75 to 80 per-
cent range, i.e., 75 to 80 percent of the input Btu's are available in
the product gas. The other 20 to 25 percent is consumed in the opera-
tion of the process. Taking an average energy efficiency of 77 percent
and assuming all of the 23 percent consumed is as liquid fuel, total
allowable nitrogen oxide emissions are approximately 400 Ib/M bbl.
Water. Salt content of crude oil may be in the range of 100 Lb/M
bbl, and one of the principal liquid vastes from a crude oil SNG plant
will be the brine resulting from desalting the crude oil.
There will, of course, also always be concentrated blowdown streams
from boilers and cooling towers to dispose of. These will most likely
be combined with the desalter brine for disposal. It will not be
possible to dispose of these waste streams to water courses. Po'ssible
disposal procedures are to utilize them as water ballast for the tanker
supplying the crude or to dispose of them to the ocean (for seacoast
SNG plants). In numerous locations, inland plants will be able to dis-
pose of them to deep injection wells. By a suitable combination of
chemical and physical processing, including biological treatment, an
essentially closed water cycle can be established, except for the brine
and the blowdowns. Thus, there will be almost no liquid wastes issuing
from a well-designed SNG plant.
Sol-id Waste. Solid wastes attributable to the production of SNG
from crude oil will include those from the treatment of the water re-
quired by the plant, and from treatment of the waste streams. There
will be, in addition, discharges of spent catalysts not worth reclaim-
ing. As an approximation, a figure of 0.25 T/M bbl (based on one pro-
jected plant design) is taken.
Land Use. An SNG plant gasifying 100,000 bbl/day of crude oil will
require a site of 500 acres or greater in size for the plant, the asso-
ciated tank farm, and a solid waste disposal area. To minimize
possibilities of environmental impact upon its neighbors, site size
will frequently be increased over this; 1000 acres is taken as a nomi-
nal figure.
Other Environmental Factors. Of the energy input to a crude oil
SNG plant, about 77 percent is recovered as product; the other approxi-
mately 23 percent is consumed in the processing operations and is re-
jected to the environment in the form of heat. Taking crude oil at
6 x 106 Btu/bbl, thermal energy liberated is about 1,400 x 10& Btu/M
bbl. Except for the heat rejected in flue gases (possibly 20 to 25
percent), the manner of rejection of the remainder is primarily a func-
tion of plant design. Whether the heat is rejected to water or to the
air will depend upon the particular circumstances of a given plant, and
may range almost anywhere between the two extremes. In the tabular
summation of data given in Appendix A, a nominal value midway between
the extremes was selected.
321
-------
Pollution Controls
Methods. As noted earlier, by far the greatest problem in pro-
ducing SNG from crude oil is the removal of sulfur. The basic method
is based on the splitting of the sulfur from the oil by treatment with
hydrogen (hydrodcsulfurization) and treatment of the evolved l^S hy the
Claus process. In the Claus process H2S is combusted under precisely
controlled conditions so that one-third of it is converted to S02- The
cooled combustion products are catalytically reacted to form elemental
sulfur:
2H2S + S02 ^± 3S + 2H20
after which the sulfur is condensed and separated. However, recovery
is not complete even with three converters, and as much as 5 percent of
the entering sulfur is contained in the exit (tail) gas. Recently
developed technology (e.g., The Beavon, Clcanair, and IFF processes)
achieves recovery of almost all of the remainder. Gradual improvements
will be made in tail gas cleanup. However, there is not much room for
further improvement, since present regulations already require 99.5 per-
cent elimination, and exit gas concentrations are already down to a few
hundred parts per million.
The principal improvements will come in the cleanup of S02~containing
flue gases. The problems of flue gas cleanup are described elsewhere
in this report and are not repeated here. There are unavoidably some
combustion operations in SNG plants with sulfur-containing fuels, and
the remaining reductions in sulfur emissions will occur in this area.
By 1990, 99.0 to 99.5 percent removal of the sulfur input to a crude
oil SNG plant can be envisioned. This will reduce unit emissions from
the 250 to 500 Ib/M bbl in the 1975 to 1980 base period to the 65 to
250 pound range, assuming sulfur levels in crude to not increase
significantly.
Particulate emissions in a crude oil SNG plant are comparable to those
occurring from steam generators fired with solid fuels, and the same
types of control equipment are used. No breakthroughs in particulate
emission control technology for SNG production arc foreseen over the
1975 to 1990 period. Improvements are more likely to result from the
application of already-known more complex and costly techniques to
situations not heretofore regarded as warranting their use. Electric
precipitators and bughouses instead of cyclone separators are examples
of this substitution; their use will undoubtedly increase as particu-
late emission limitations become more stringent.
«.
Hydrocarbon emissions in a crude oil SNG plant are associated primarily
with storage of petroleum fractions. Control is achieved by the use
of floating roof tanks, for moderately volatile materials such as crude
oil, and by pressure vessels for the volatile materials like propane
322
-------
and butane. Rates of hydrocarbon emissions are minimal from a modern
plant of this type, and little changes in technology are anticipated.
CO emissions may be large from an uncontrolled fluid cat-cracker regen-
erator, but arc reduced to insignificant levels by the addition of a CO
boiler. Since it is unlikely that any new FCC units will be built with-
out a CO boiler, CO emissions arc not expected to be a problem in any
SNG plant.
Effectiveness and Cost. Data are not available on the cost of the
——————— —_—_——. A
individual pollution control measures applied to the manufacture of SNG
from crude oil. However, the conversion of high-sulfur crude oils to
SNG is in itself a pollution control measure, which can be compared
with other alternative pollution control measures, e.g., hydrodcsulfur-
ization of crude oil, or flue gas scrubbing.
The extent to which SNG from crude oil is utilized as a future energy
source in the United States will depend in large measure upon a number
of factors, including the relative availability and cost of crude oil
feed stock versus alternative sources, the relative cost of conversion
to SNG, and the costs of pollution control. Each of these factors has
its own set of variables, so that generalizations are difficult.
However, one generalization that can be made is that the more energy
expended in converting a fuel to another form, the higher will be the
cost per net Btu. Accordingly, the manufacture of SNG from crude oil
will inevitably be more costly on a unit basis than merely desulfurizing
crude to make fuel oil.
Thus, for major energy users such as central power stations, desulfur-
ized fuel oil will be basically a cheaper fuel than SNG. Depending on
size, location, and age of plant, it may be more economical for an
existing generating plant burning gas to convert to burning fuel oil
than to continue to burn gas, when that gas has the $l-f/M cu ft cost
of SNG. It may also be more economical for such a plant to burn de-
sulfurized fuel oil than to install a flue gas scrubbing system.
The principal alternative processes for manufacture of a low-sulfur
fuel not requiring flue gas scrubbing arc desulfurization of crude oil,
manufacture of SNG from crude oil, and manufacture of SNG from lighter
petroleum fractions such as naphtha. Because of the wide variety of
feed stocks and purification techniques available, it is difficult to
compare meaningful cost information. However, the costs are believed
to compare as follows. Cost of conversion of naphtha to SNG is in
the range of $0.27 to 0.30/106 Btu for a complete plant of 250 x 106 cu
ft/day (50,000 bbl naphtha/day) capacity.(M~2) Based on some unpub-
lished information, cost of conversion of a high-sulfur crude to SNG
via a naphtha intermediate is in the range of $0.50 to 0.60/10^ Btu.
This is confirmed in essence by the data presented by Prescott.(M"3)
The difference between naphtha gasification and crude oil gasification
via naphtha ought to be approximately equivalent to the production of
323
-------
desulfurisced fuel oil, or a little more, since less processing is needed
to produce fuel oil than naphtha. From the data above, this would place
the cost in the range of $0.25 to 0.35/10G Btu. This is confirmed by
Chapel and RogersC*'1"6) in which desulfurization of whole Kuwait (high-
sulfur) crude to 0.6 percent sulfur was estimated to cost $1.35 to
1.50/bbl fuel oil, or about $0.22 to 0.25/106 Btu.
The costs of pollution control will also influence the choice of energy
source. Costs for flue gas scrubbing have been projected in the range
of $0.10 to 0.70/106 Btu, decreasing with increasing size of plant and
increasing with increasing percentage of sulfur in the fuel. The spread
is obviously so broad that each individual case would be decided on its
own merits. However, it is apparent that for central power stations,
for example, at least in some instances burning of high-sulfur residual
fuel oil and scrubbing the flue gas would be the optimum economic solu-
tion. In other cases, the alternate options of the use of desulfurizcd
fuel oil or SNG might lead to the lowest overall cost. The optimum
choice will be clearly indicated in the usual industrial applications
and the use of SNG will normally be the preferred choice for space
heating, in spite of its higher cost because it can be easily utilized
in existing gas-fired furnaces.
Naphtha Gas:fication
A process has been developed by the Eritish Gas Council and M. W.
Kellogg to produce a synthetic natural gas having a gross heating value
of 1000 Btu/scf. Recently, the M. W. Kellogg Company prepared a report
on the process and an inventory of both gaseous and liquid emissions
from the process. (M"7) The description of the process and emission
values are summarized here from that report.
Process Description
The feed stock to the process is a naphtha stream containing 500 pptn
of sulfur. The gas produced is about 98 percent 0114, with some HZ,
CO, and CC^-
The first part of the process is a naphtha desulfurization. The sulfur
removal is accomplished by mixing naphtha vapor with a hydrogen-rich
stream, and passing this mixture over a catalyst to produce ^S. The
is converted to sulfur via the Claus process.
Naphtha reforming is done by passing naphtha vapor and steam over a
catalyst to produce CH4, H2, CC-2, and CO. This stream is then sent to
a methanator in which the CO and some of the CO 2 react with H2 gas to
form City and il20. Cooling the gas at this point removes the water,
leaving a stream containing mainly CH/^ and C02-
32A
-------
The C02 in the gas is then absorbed in a hot K2C03 system to reduce the
C02 content to less than 1 percent. Finally, the synthetic natural gas
is dried with glycol.
Major Effluents From the Naphtha Gasification Process
The gaseous emissions and the liquid wastes are shown in Tables M-l and
M-2, respectively. The major gaseous pollutants are NOX from the fur-
naces and methane from the C(>2 stripping.
TABLE M-l. GASEOUS EMISSIONS FROM NAPHTHA GASIFICATION PLANT
(250 x 106 scfd)
Operation
Furnace
Glaus plant
C02 stripper
Condensate stripper
TOTALS
Pollutant
SO?
HC(a)
N0x(a)
S02
S02
CH4
NOX
Quantity, Concentration,
TPD ppm
0.56
0.24
4.7
0.02
10
0.2
= 0.58 TPD
and HC = 10.44 TPD
= 4.7 TPD
55
23
460
83
1600
(a) Based on emission factors from Reference M-5.
TABLE M-2. LIQUID EFFLUENTS FROM NAPHTHA GASIFICATION PLANT
(250 x 106 scfd)
Operation
Boiler blowdown
Cooling tower blowdown
Backwash water from boiler
water treatment
' TOTAL
Dissolved Solids
Quantity, TPD
0.48
0.67
17.3
18.5 TPD
Concentration,
ppm
1500
1770
34,000
325
-------
The wastcwater from the boiler, cooling tower, and water treatment plant
contain ionic constituents such as NaSO^, CaSOi, MgSO/,, and NaHC03. At
present, it is planned to neutralize the backwash water to a pH of about
8.5 before discharging to a stream or river and to discharge the other
two directly as their pH is high.
Controls. The control of S02, NOX, and hydrocarbons is discussed
elsewhere in this report. The major problem in control arises in con-
sideration of the liquid streams containing soluble ionic constituents.
These ionic constituents have essentially no economic worth. One
method of handling these wastes would be to use a process proposed by
Mane va ];(M-8) namely, flash evaporation, followed by casting the molten
salt into cubes, encasement in plastic, and burying the cubes. Maneval
estimated the cost of a plant to process 5 x 10^ gallons/day would be
$14 million with direct operation costs of $0.40/1000 gallons. The
plant for naphtha dcsulfurization discharges about 0.3 x 106 gallons/
day. Using a cost index of 0.6 (a fairly common value in the chemical
industry), and capital charges of about 25 percent, a plant to treat
the liquid waste effluent would cost about $2.7 million, capital, and
operating costs of $0.008 per 1000 ft^ of gas. This represents a small
increase in plant cost of about 1 percent, and an increase in gas cost
of about 0.5 percent for control of the liquid waste effluent streams.
References
M-l. Dutkiewicz, B., and Spitz, P. H., "A Survey of Processes for Pro-
ducing Substitute Natural Gas From Crude Oil and Naphtha". Paper
presented at 71st National AIChE Meeting, Dallas, Texas,
February 21-23, 1972.
M-2. Brcsler, S. A., and Ireland, J. D., "Substitute Natural Gas:
Processes, Equipment, Costs". Chemical Engineering J9, 94-108,
October 16, 1972.
M-3. Prescott, J. H., "Energy Refineries are Eyed". Chemical Engineer-
ing 29, 80-82, September 18, 1972.
M-4. Anonymous, "Synthetic Fuels: What, When?". Chemical Engineering
22, 62-63, April 17, 1972.
M-5. "Compilation of Air Pollutant Emission Factors" (Revised), U. S.
Environmental Protection Agency, February, 1972.
M-6. Chapel, D. G., and Rogers, H. W., "Low Sulfur Fuel Oil - Which
Route". Paper presented at 7lst National AIChE Meeting, Dallas,
Texas, February 20-23, 1972.
M-7. 250 MMSCFn SNG From Naphtha British Gas Council (CRG) Process,
Task No. 14 report to Environmental Protection Agency from M. W.
Kellogg Company, March 30, 1972.
326
-------
M-8. Mane/a1, J., paper presented at the AIME symposium on Mining and
Metallurgy of Lead and Zinc, St. Louis, Missouri, October 21-23,
1970.
327
-------
APPENDIX N
PHYSICAL DESULFURIZATION OF COAL
Table of Contents
Summary ». . . . 330
Introduction 331
Technology 331
Environmental Factors 335
Pollution Controls 338
References . • 340
List of Tables
N-l. Emission Factors from Operation of Thermal Dryers in Coal
Preparation Plants in Pounds per 10^ Btu 336
N-2. Water Usage at Bituminous Coal and Lignite Preparation
Plants in the United States, 1962, by States 337
N-3. Estimates of Water Pollution Resulting from Oocration
of Coal Washing Plants in Pounds per 106 Btu 337
List of Figures
N-l. Variations in Total Sulfur, Sulfur Forms, and Removable
Pyrite in Face Samples of Pittsburgh Seam Coal From
a Single Nine in Greene County, Pennsylvania 332
N-2. Float and Sink Curves for Illinois No. 6 Bed Coal 332
N-3. A Schematic Flowsheet of a Coal Washing Plant 334
329
-------
APPENDIX N
PHYSICAL DESULFURIZATION OF COAL
Summary
The partial desulfurization of coal by physical means involves removal
of impurities by methods that are employed in the separation of solids
in the ore-dressing industry. Some coals are more amenable than others
to these methods depending on the physical characteristics of the coal
and the impurities it contains. However, the generalization may be made
that, if all the coal mined in the United States were physically cleaned,
about 30 percent of all the sulfur would be removed. No other proposed
action has the prospect for such an immediate result. In addition, up
to 50 percent of the ash is removed. This reduces transportation costs
and reduces the load on the power plant ash-handling and particulate-
collection facilities. There is a loss of about 10 percent of the coal
during physical cleaning but the removal of greater amounts of im-
purities results in a net increase in the heat content of the coal.
The cost of physical cleaning for eastern coal is about 66 mils per 10 6
Btu of product .
Typical emission factors arising from the process after application of
controls may be as follows :
1. Air pollution resulting from the operation of thermal dryers ex-
pressed as pounds per 10 6 Btu
SOX 0.002
NOX 0.006
Particulates 0.010
2. . Water pollution as a result of drainage from settling ponds and
compacted and revegetated refuse piles in the amount of 0.001 pound
of H2S04 per 106 Btu.
3. Solid waste, in the form of tailings from the washing plant, ranging
between 10 and 21 pounds per 106 Btu.
The typical costs of control have been estimated for the various sources
as mils per 106 Btu
• Air 2.65
• Water 0.65
• Solid Waste 0.65
330
-------
Introduction
Sulfur is present in coal in several forms. In the organic form it is
chemically bonded to the carbon atoms and as such cannot be removed by
physical means. In American coals it represents approximately 20 to 85
percent of the total sulfur present. The inorganic form is present
mainly as the chemical species FeS2 or ferrous disulfide, with relative-
ly small amounts of the sulfates of calcium and iron. The total sulfur
content of coal varies between less than 1.0 and more than 4 percent.
Also, there is a large variability in the percentage of removable sulfur
not only in coals from different regions, but also in coals obtained from
the same mine. This is illustrated by Figure N-l in which total, removable
and organic sulfur were determined for samples of a Pittsburgh seam
coal.(N-2)
The amenability of the coal for sulfur removal by physical means is
established by "float and sink" analyses or washability tests. ™-^; jn
these tests, the coal is crushed to various sizes and each size is intro-
duced into vessels containing liquids in the specific gravity range of
1.2 to 2.0. The upper part of the range approaches the specific gravity
of impurities such as shale or rock and the lower part approaches the
specific gravity of pure coal. The specific gravity of pyrite is about
4.90.
In the above-mentioned vessels the float material is termed the yield
while the sink material is called the refuse. Figure N-2 is a "float
and sink curve" for a No. 6 Bed Illinois coal, showing the effect of the
specific gravity of liquid effecting separation on yield and sulfur
removal.(N-3) it is seen that, although sulfur removal is increased
by using a low specific gravity liquid, the total yield of product coal
in the float material is reduced. Steam coal cleaning plants operate
with liquids of specific gravity about 1.6 and yields in the neighbor-
hood of 85 percent.(N~3)
Technology
Coal washing has been carried out for the past several decades using
many physical separation techniques singly or in combination. In 1965,
the percentages of existing coal washing processes using one or more of
the named unit processes are as follows:
Process Percentages Process Percentages
Jigging 46 Classifier 2
Dense-Medium 28 Launder 1
Tabling 13 Flotation 2__
Pneumatic 8
Total 100
331
-------
'v-r7I77/
W////,.
////// Fixed pyritic sulfur
I Organic sulfur
1.6
U -
FIGURE N-l. VARIATION'S IN TOTAL SULFUR, SULFUR FOR.MS, AND REMOVABLE PYRITE
IN FACE SAMPLES OF PITTSBURGH SEAM COAL FROM A SINGLE MIKE IN
GREENE-COUNTY, PENNSYLVANIA. Ref. (N-2) .
Note: Each bar represents one sample.
•*w
CO
GO
7O
BO
90
OO
c
FLO
DMA
—1 1—
IMIN'E A-
s
*A
\7 ASK V.\
^^
s
\
-=>
4
ILLINC
FLO
!
\^
)!S N
IT SULFUR •
i
-------
A survey of the processes presented in Reference N-l and inspection of
the table mentioned above seems to indicate that the flowsheet given in
Figure N-3 is fairly representative of current washing operations. In
this process, run-of-mine coal is crushed to a top size of 3 inches and
introduced into a Baurr.-type jig, where the bed of coal is subjected to
up and down pulses of flowing dense medium of 1.6 specific gravity.
This action results in a separation of the bed into three layers of
differing specific gravity, the lowest layer containing the highest
specific gravity or refuse material. The top layer is collected and
further crushed to a top size of 3/8 inch and fed to the sieve bends of
the dense-media cyclone plant. The 30 mesh x 0 material which passes
through the screen is sent to the froth flotation plant whereas the 3/8
inch x 30 mesh material is sent through the dense-media cyclones. The
dense medium is a slurry of magnetite in water of such concentration as
to make the specific gravity 1.35. The float coal, of density less than
1.35, leaves the overflow orifice of the cyclone whereas the sink material
exits the apex of the cyclone. Then it is washed, wet ground, and
classified to 30 mesh x 0 and sent to the collecting sump of the froth
flotation plant. In froth flotation of the fines, the coal particles
surface is rendered nonwetable by treatment with collectors such as
alcohols, pine oil, or kerosene to facilitate its adherancc to rising
air bubbles. Depressants such as lime or sodium cyanide are added to
inhibit the rise of pyrite and clay particles. The resulting froth is
skimmed, thickened and vacuum filtered, and sent to the thermal dryers
along with the centrifugally dried 3/8 inch x 30 mesh float material
from the dense-media cyclone plant overflow.
In all operations involving separation of pyrite and coal using dense
medium of various compositions, the tailings as well as the product
become contaminated with magnetite. Therefore, it is standard practice
to have both rinsed before ultimate disposal of refuse or recovery of
product. The magnetite in this rinse water is concentrated and most of
it recovered by first thickening the rinse water and then passing the
concentrate through a magnetic separator. Heavy medium losses may
amount to 1 pound per ton processed at a cost of 3 cents/pound.
The average costs, in mils per 10& Btu, involved in cleaning eastern
coals(N-1) may be broken down as follows:
o Depreciation
• Operation and Maintenance
o Tax
• Value of coal lost at $5.00/ton
(ROM) and 90 percent yield
o Total mils/106 Btu 65.8
As mentioned earlier, only inorganic sulfur can be removed by means as
previously described. It is believed that processes in operation today
and those expected during the 1975 to 1990 period are inherently incap-
able of achieving total inorganic sulfur removal. The approach to this
333
-------
f
Ml
UN or ]
nc COAL]
1
IORCn.tr. o^
CRUSHER
^""itioDLTNCs"
1 .
j 1 OAUM
1 i
V • . L..
v- -{MIDDLINGS
r
WATER
TYPE JIG
1
t
J REFUSE
4 O V
LCD SR en.
LOAT COAL
CLASSIF
OEV.AT
SAT
nric 0
EKS ^
1
s o V i s/a*
\
| IMPACT CRUSKIP ]
|
I SCKEEK AT VS* 1
r
S/6' • 0
^IfVE PCi.'O 6 SOW tO
nrii mine. *° M « °. . co
SCREENS x^X &w
j O
S/B* i SOW
,_
• __., 1 £
CYCLOhCS f^n "^ 1
/7?) -L15SPGR. ^"^ t
Vlij' FLOAT COAL YfE7
ICEHTniFUCiL MILLS
1" DRYERS ' '
X^ s/e* i "sow
_LCCTIHC SOMiO ^ 1W0 STAGE
P 6 PUMPS HYOROCYCLC:;ES
1
. t
IIIIGH SULFUR
RCJEC1S ^
_, /
o«;r«, f
1
FROTH
FLOTATIOV
UNITS
JfdOTM COfi'CCNTRXTCS 1 **
, ( ^
(VACUUM FILTER
•
^S~
_^r | IIEAT DRYING
^^ \ SYSTEM
^ r-
3/8" x 0
DRIED PRODUCT
•
FIGURE N-3. A SCHEMATIC FLOWSHEET OF A COAL WASHING PLANT WITH
3/8 INCH x 0 PRODUCT, USING THE OPERATIONS OF
JIGGING, DENSE-MEDIA SEPARATION, AND FROTH
FLOTATION. Reference (3)
334
-------
limit would involve crushing the coal to relatively small sizes (200
mesh) and the extensive application of such fine separation processes
as froth flotation. This is the subject of current research.(N~5)
Current operations would give a typical yield of 80 to 90 percent and
achieve inorganic sulfur removals of about 60 percent.
Environmental Factors
The coal-washing operations and processes that were previously described
may have a significant effect on the environment. The consequence of
washing large amounts of run-of-mine coal is the production of a pro-
portionately large amount of refuse or waste material. Owing to in-
creased mining by mechanical means and decreased availability of low
sulfur fuels, refuse material from washing operations may be as high as
30 percent of the raw coal being processed.trt-1) coal washing operations
may affect both the air and water aspects of the environment. The assess-
ment of the emissions from these operations will be made by adhering as
closely as possible to data reported on the operational experience of
the industry. Where no operational experience of emission factors was
reported, estimates were made on the basis of coal with washability
curves as given in Figure N-l. The plant was assumed to effect a
separation at a typical specific gravity of 1.6 and have an output of
1000 tons per hour (tph).
Air
Here the most significant emission results from the operation of the
thermal dryers.(N-6) The wet coal obtained from both fine and coarse
separation is introduced to dryers operated by the combustion of pul-
verized coal. The hot gases resulting from Ihis combustion are allowed
to directly contact the wet product, thereby evaporating the water
through the release of their sensible heat. In the absence of proper
controls, particulates in the form of fine coal dust and ash from coal
combustion together with the products of combustion, KOX and SOX, may
be released. However, the recent enactment of more stringent air pollu-
tion regulations has resulted in the incorporation of gas cleaning
devices as standard equipment in most recently modified or completed
installations.(N-7) A description of these controls will be given in
a later section. The emission factors with and without existing con-
trols are presented in Table N-l.
Another potential source of air pollution may be the sulfur-rich coal-
containing refuse obtained as sink material. If this waste is not
properly disposed of, low temperature oxidation of the coal may take
place and a gradual temperature buildup in the refuse pile may cause it
to ignite spontaneously after the ignition temperature is reached. This
may cause noxious emissions of SOX, NOX, ami hydrocarbons. In 1966,
there were 400 burning coal refuse sites of significance throughout the
15 of 26 coal-burning states in the United States.(N"1) However, there
335
-------
are no current data available on the extent of emissions resulting from
the burning of refuse piles.
TABLE N-l. EMISSION FACTORS FROM OPERATION OF
THERMAL DRYERS IN COAL PREPARATION
PLANTS IN POUNDS PER LO& Btu
sox
NOX
Particulates
Without (a)
Controls
0.012
0.006
1.000
With
Controls
• 0.000200
0.006
O.Ol(c)
(a) Data obtained from Reference N-6.
(b) Alkalis are used to remove 85 percent of S02«
(c) High energy venturi used at efficiency of 99.9 percent.
Water
Coal washing operations require large amounts of water. Table N-2 shows
the amount of water used or discharged by coal preparation plants in
1962. The operation of jigging which is used in 50 percent of all coal
washing operations requires 1500 to 2000 gallons of water per ton of
coal processed.(N-8) Table N-2 shows that although 81 percent of the
water was recirculated, more than 15 percent was discharged to the
environment during that year. Furthermore, only 18 percent of the total
water discharged was treated prior to disposal. This water usually con-
sists of about 15 percent suspended solids consisting of fine clay and
coal and a maximum of 1 percent dissolved solids.(N~l) If water ob-
tained from acid mine drainage may be considered analgous to the dis-
charged water, at least in a qualitative sense, then the dissolved solids
consist mainly of the SO^ ion in conjunction with the ions of iron,
aluminum, calcium, magnesium, sodium, and potassium.(N-l)
Modern coal cleaning plants operate by total recirculation of water.
However, in order to keep the total solids concentration below a criti-
cal value of 15 to 20 percent, blowdown is necessary. This, in addition
to the water lost in the thermal dryers, is made up by fresh water drawn
from water treatment plants to be described later.
Over the past decade there has been a marked increase in the production
of coal by mechanical means. This has led to an increase in the amount
of coal fines to be recovered, usually by froth floation. Up to 20
percent of plant feed may be processed in this fashion. The flow in
this circuit is treated with surface-active organic compounds, such as
alcohols, or kerosene, to enhance frothability. The amounts may vary
between 0.03 to 0.3 pound of alcohol per ton of solids processed.
336
-------
TABLE N-2. WATER USAGE AT BITUMINOUS COAL AND LIGNITE
PREPARATION PLANTS IN T1IE UNITED STATES,
1962, BY STATES^'"1 >
Waler Usage x IP gal
Water Disposal x Iff gal
Slate
Alabama
Alaska
California
Colorado
Illinois
Indiana
Kansas
Kentucky
Missouri
Montana
New Mexico
Ohio
Oklahoma
Pennsylvania
Tennessee
Utah
Virginia
Washington
West Virginia
Wyoming
TOTAL
New
Water
2,330
1,344
18
5
5.304
1,190
147
8,096
226
2
41
645
26
2,682
1
995
1,593
18
7,169
1
31.833
Kerlrciilated
Water
7,363
J32
18
15
22.40!)
8,685
1,715
14.623
1.067
20
300
7,091
132
23,483
1,399
8,010
25
42,024
138.511
Total
9,693
1,476
36
20 '
27,713
9,875
1,862
22,719
1,293
22
341
7,736
158
26,165
1
2.394
9,603
43
49,193
1
170.344
Consumed
352
3
10
1
427
142
101
535
109
4
290
11
768
626
278
4
2,028
5,689
Discharged
1.978
1,340
8
4
4.877
1,0 JS
46
7,561
116
2
38
355
15
1,914
1
369
1.316
14
5.N1
1
26.144
Refuse piles resulting from the washing of coal may also be a source of
water pollution in the absence of pollution controls. This may happen
by oxidation of pyritc to sulfuric acid in the presence of oxygen and
water. Surface runoff would subsequently act as carrier of the acid
effluent to nearby streams.
The emission factors for the various sources of water contamination
were estimated for the two cases in which environmental controls are or
are not applied. The results are presented in Table N-3.
TABLE N-3. ESTIMATES OF'WATER POLLUTION RESULTING FROM
OPERATION OF COAL WASHING PLANTS IN POUNDS PER 105 Btu
Suspended Solids
Dissolved Solids
Total Organic Materials
Acid H2S04
Without
Controls
2.13
O.Ol(d)
With Us)
Controls
0
0
0
o.ooi(f)
337
-------
Footnotes for Table N-3:
(a) Assuming a concentration of 150 grams per liter and using water
discharge and coal production data for W. Va. in 1962.
(b) Assuming a concentration of 10 grams per liter.
(c) This assumes an alcohol addition of 0.3 pound per ton of fines
(20 percent) processed.
(d) Calculated on the basis of data given in References N-9 and N-10
and a 1,000 tph plant with 90 percent yield.
(e) Assumed 100 percent efficiency in control schemes unless otherwise
noted.
(f) 90 percent removal by spreading and covering refuse pile.
Reference N-10.
Solid Waste
This waste is an accumulation of sulfur-rich plant rejects resulting
from the coal washing process. The amount of these rejects would depend
on the specific gravity of separation used in the plant for steam coal.
The rate of disposal of these rejects would be in the range of 10 to 21
pounds per 10& Btu.of plant output. In addition to their impacts on the
air and water environments, as previously discussed, these plant rejects
represent a commitment of the land resource at the rate of 1 to 2 x 10~^
acre.-hr/lo6 Bfu. It is estimated that a modern 1,000 tph plant would
require a land area between 40 and 90 acres. The upper part of the
range may be required if lagooning or ponding of plant wastes are under-
taken.
Pollution Controls
The installation of air and water pollution control equipment has
recently become standard in coal washing plants which are either planned
or recently completed.(N-7) As mentioned earlier, this is the result of
enforcing more stringent state and federal regulations. The methods and
costs of controls, to be described shortly, are those which have received
at least some application in various locations. Although existing
technology is capable of reducing emissions to acceptable levels, economic
considerations seem to detract from the task of complete abatement.
Air
Since operation of thermal dryers is considered to be the main source of
emissions to the air environment, recent efforts have been directed at
minimizing this source. In one instance,(N-10) a high energy venturi
scrubber was installed to remove particulates from gases exiting a
fluidized-bcd dryer capable of processing 500 tph of dried product. After
scrubbing, the gases contained about 0.1 grain/cu ft. of particulates.
Although no mention was made of any lime additions to the scrub water,
338
-------
a SOX removal of about 85 percent is possible by this technique. The
costs associated with venturi scrubbing were estimated at 2.65 mils/10^
Btu for n gas flow of 270,000 cfm and a production of 500 tons per
hour.(N-H, N-10, N-6)
The gaseous emissions of SOX, NOX and hydrocarbons that may result from
the burning of refuse piles can be effectively eliminated by the proper
disposal of solid waste to be described later.
Water
The water discharged from coal preparation plants is very similar in
chemical characteristics to that resulting from acid mine drainage. The
main difference is the high concentration of suspended solids in the
plant discharge. Treatment of this acid water involves neutralization
with lime, rhe addition of flocculants, as alum, or ferrous sulfate, and
subsequent aeration and ponding. Make-up water for the plant is obtained
from the clear supernatant of the settling ponds. Contamination of
ground and surface waters by percolation of effluent from the settling
ponds should be minimal when they arc properly designed.(N~12) ^he cost
of lime treatment is highly variable.(N-13) Factors affecting this cost
may be the acidity and quantity of the treated effluent and geographical
location of treatment plant. The average cost of the treatment was esti-
mated as 0.65 mil per 10& Btu of product coal.(N~15) This cost may,
however, range between 0.1 and 1.30 mils per 10^ Btu.(N-12)
As explained earlier refuse that has not been properly disposed of may
become a source of acid water. In actual experiments conducted on a 2
million cubic yard pile, (l'!~10) ^t was found that acid water drainage
amounted to 198 pounds (expressed as CaCC^) per acre of pile per day.
Employing disposal methods, to be described later, the drainage was re-
duced by 90 percent.
Solid Waste
The solid refuse resulting from coal washing plants can be disposed of
in such a way as to minimize air and water pollution.(N-10) j^e methods
employed in disposal have been discussed elsewhere.(N-10) Briefly, the
procedures involve spreading and compacting the refuse, covering it with
a layer of soil and revegetating with plants, such as grass. Fertilizers
are usually added to the soil to expedite the vegetation process.
The costs of refuse disposal by methods as outlined above are highly
variable. For a 1000 tpd plant with a refuse pile of 50 acres, these
costs may range between 0.3 r.nd 1.0 mil per 10^ Btu. The factors'
affecting cost may be land topology and the availability of suitable
cover material.
339
-------
References
N-l. Coal Preparation, J. W. Leonard and D. R. Mitchell, Editors, 3rd
Edition, AIHE, New York, 1968.
N-2. Glenn, R. A., and R. D. Harris, Liberation of Pytfite from Steam
Coals, Paper presented at 23rd Annual Meeting of the American
Power Conference, March 21-23, 1961, Chicago, Illinois.
N-3. Zimmerman, R. E., Economics of Coal Desulfurization, Chemical
Engineering Progress, J32 (10), pp 61-66, October, 1966.
N-4. Yeager, K. E., and L. Hoffman, The Physical Desulfurization of
Coal—Major Considerations for SOX Emissions Control, Proceedings
of the American Power Conference, Vol 33, 1971.
N-5. Anonymous, Coal Comes Clean for Burning, Chemical Week, August 17,
1968, pp 64-65.
N-6. Compilation of Air Pollutant Emission Factors, U. S. Environmental
Protection Agency, Office of Air Programs, Publication No. AP-42,
Research Triangle Park, North Carolina, February 1972.
N-7. Anonymous, Coal Age, 1? (2), p 69, February 1972.
N-8. Perry's Chemical Engineers Handbook, 4th Edition, R. H. Perry,
C.U. Chilton, and S. D. Kirkpatrick, Editors, McGraw-Hill, New
York, 1963.
N-9. Barthauer, G. L., AIME Environmental Quality Conference,
Washington, D. C., June 7-9.
N-10. Anonymous, Coal Age, 22 (10)» P 122-138, October 1972.
N-ll. Ellison, W., Power, p 62, February 1967.
N-12. Hughes, G. M. and K. Cartwright, Civil Engineering-ASCE, 42 (3),
p 70, March 1972.
N-13. Anonymous, Coal Age, J77 (7), p 129-224, July 1972.
N-14. Zimmerman, 0. T., Cost Engineering, ,16 (4), p 11, October 1971.
340
-------
APPENDIX 0
CHEMICAL DESULFURIZATION OF COAL
Table of Contents
Summary 342
Technological Background 343
Chemical Dasulfurization 344
Slate-of-Che-Art Technology Projection 347
Emissions 347
Process Economics 350
Ferric Salt Leaching ,350
References 351
List of Tables
0-1. Emissions from Pyritic Sulfur Removal Process 350
List of Figures
0-1. Process Flow Chart 346
341
-------
APPENDIX 0
CHEMICAL- DESULFURIZATION OF COAL
'Summary
An alternative to combat air pollution created by the combustion of high
sulfur coal is to remove the sulfur from the coal before combustion. One
technique for sulfur removal, referred to as chemical dcsulfurization,
would entail treating the coal with a reagent capable of converting the
sulfur to a form which could be extracted or readily volatilized from the
coal matrix.
The technical feasibility of producing low sulfur coal by chemical desul-
furization has been established in bench-scale operations. The pyritic
sulfur and approximately 50 percent of the organic sulfur were extracted
from an Ohio coal by applying hydrothermal technology using an aqueous
caustic solution as the leachant. Heating various coals in aqueous ferric
salt solutions, in molten salt baths, and in a mixture of steam and air
removed the pyritic sulfur, producing a coal containing only the organic
sulfur. Subjecting various coals to hot leaching with organic solvents
resulted in the removal of up to 80 percent of the organic sulfur. Leach-
ing with organic solvents had no effect on the pyritic sulfur.
Emissions from chemical desulfurization processing will depend on the
process employed. In general, sulfur emissions to the atmosphere are
expected to be negligible. The majority of the emissions would be from
the waste liquid effluents and solid by-products. For example, total
emissions from the ferric salt leaching process were estimated at 4.7
pound per 106 Btu and, from the organic leaching process, 3.3 pound per
106 Btu. However, by employing resource recovery practices and by regen-
erating and recycling of the leachants, emissions could be further re-
duced .
Quantitative costs for chemical desulfurization of coal cannot be calcu-
lated because of the stage of development of this technology. Qualita-
tively, costs, based on scale-up of bench-scale data, are estimated to be
approximately 13 cents per 10& Btu.
Assuming chemical desulfurization of coal is economically feasible, it is
projected that approximately 10-15 years will be required to establish
commercial feasibility. This time span could be reduced significantly if
a concentrated effort is made to do so.
342
-------
Technological Background
'Types of Sulfur in Coal
Sulfur is an undesirable constituent of all coals. It is present in
amounts ranging from traces to greater than 10 percent. The bulk, of the
commercial coals of the Eastern United States contain from 0.5 to 4.0
percent sulfur.(0-1)
Sulfur is present in coal as sulfatc sulfur, organic sulfur, and pyritic
sulfur. Sulfate sulfur is of minor concern as its concentration in coal
is in the neighborhood of 0.1 percent. Sulfate sulfur is present as
indiscrete particles of gypsum, with copperas (FeSOv^^O) and in the
mineral jarasite [(NaiK), Fe3(S04)2(OH)g]. The iron sulfatcs become
important only in weathered coals and, like all sulfate sulfur, are a
minor problem with respect to atmospheric pollution.
This cannot be said for the pyritic and organic sulfurs. Pyritic sulfur
is found in coal as ferrous disulfide (FeS2) in pyrite and/or marcasite.
The two minerals have the same chemical composition but have different
crystalline forms. Pyrite is the most commonly reported'form of the two
and is ubiquitous in coal.
Pyrite sulfur occurs in coal in many forms—veins, lenses, nodules, or
balls, and pyritized plant tissue. The pyritic particles nvny be macro-
scopic in size which are visible to the naked eye or present as particles
which can be seen only with the aid of a microscope. Much of the pyritic
sulfur is present as microscopic particles, making physical desuifuriza-
tion difficult. Concentration of pyritic sulfur varies from about 0.2 to
over 8 weight percent, making up from 20 to 80 percent of the total sulfur
content of coal.
The third form of sulfur in coal, organic sulfur, occurs as part of and
linked into coal.(0-2) Concentration ranges from about 0.3.to about 2.A
weight percent, making up from 20 to about 85 percent of the total sulfur.
According to Given and Wyss,(0-3) organic sulfur is found in coal in the
following forms.
(1) Mercaptan or thiol, RSH
(2) Sulfide or thio-ether, RSR
(3) Disulfide, RSSR
(4) Aromatic systems containing the thiophene ring.
Supposedly, organic sulfur cannot be removed unless the chemical bonds
holding it are broken. Thus, the^amount of organic sulfur present defines
the lowest limit to which a coal can be cleaned by physical methods.
343
-------
Chemical Dcsulfurization
From an environmental viewpoint, one of the problems with coal as a fuel
Is its high sulfur content. Physical desulfurization is not entirely
satisfactory as (1) some coals are not amenable to removal of the pyrite
by physical means, (2) complete removal of pyrite is not possible, and
(3) organic sulfur is not removed by physical methods. Thus, because of
the high residual sulfur content of physically cleaned coals, consumers
of coal are searching for innovative approaches to the production of low
sulfur coal. One route which is being viewed extensively is the chemical
desulfurization approach whereby the sulfur content of the coal is re-
duced to within acceptable limits by treating the coal with a reagent to
react with or liberate the sulfur. Separation of the sulfur prior to
combustion would then result in a low-sulfur coal which could be consumed
directly with minimal pollution control of stack gases.
In the removal of sulfur prior to combustion, the majority of the effort
has emphasized the reduction of pyritic sulfur as the organic sulfur is
reportedly molecularly bound to the coal and is less subject to attack.
Thus, the removal of the organic sulfur is more difficult.
Pyritic Sulfur Removal
Currently, chemical desulfurization of coal is not being practiced
commercially. However, this area is and has been under study through-
out the United States and in time chemical desulfurization is expected
to become a reality. Presently, this work is in the experimental stage.
Pyrite (FeS2) is found in coal as discrete nodules in heteregenous mix-
ture and is therefore subject to attack by a wide variety of chemical
reagents. These reagents are generally used in conjunction with elevated
temperature coal treatment processes.
Chemical methods for leaching the mineral matter from coal using aqueous
solutions of nitric acid, chlorine, hydrofluoric acid, and caustic have
been reported to be successful.(0-4) One chemical method employed molten
caustic (sodium/potassium hydroxide in a ratio of 1:1) at various tempera-
tures to dissolve pyritic sulfur from conventionally cleaned Pittsburgh
seam coal.(0-5) in this work, complete removal of pyritic sulfur was
achieved by treating 1 part coal (minus 40 mesh) with 4 parts of caustic
at temperatures between 150 to 250 C. Below 150 C, no removal of sulfur
was achieved. At temperatures between 250 to 400 C, the extraction was
rapid, requiring approximately 5 minutes. In this system, the organic
sulfur is not attacked.
High temperature steam-air treatment has been reported to be effective in
reducing the sulfur concentration. The treatment of Rumanian and Indian
coals resulted in sulfur reductions of 30 percent and 56 to 58 percent,
respectively. The addition of ammonia along with the steam resulted in
the removal of 88 percent of the sulfur from the Indian coals.(0-5) The
344
-------
treatment of coal with steam and air at 150 to 20Q psi and temperatures
up to 250 F resulted in the removal of the pyritic sulfur which made up
approximately 50 percent of the total sulfur. The organic sulfur was not
touched. (0-6)
The treatment of coal with aqueous solutions is effective for tae removal
of pyritic sulfur and, depending on the leachant, for the removal or
organic sulfur as well. Leaching of ground coal with aqueous solutions
of ferric chloride or ferric sulfate (Figure 0-1) at temperatures up to
100 C has resulted in the extraction of the majority of the pyritic
sulfur. (0-7) By this process, pyritic sulfur is converted to sulfate and
elemental sulfur. A continuous countercurrent leaching operation may be
employed. The elemental sulfur formed in the coal is separated from the
coal matrix by vacuum distillation or extraction with a solvent such as
toluene or kerosene. By-products from the process are sulfur and iron
sulfate. Iron oxide is sometimes formed depending upon process conditions.
Leaching ground coal with aqueous caustic solutions under hydrothermal
conditions has resulted in removal of all of the pyritic sulfur and
approximately 50 percent of the organic sulfur. By this process, the
sulfur in the coal is converted to a water-soluble form by treating the
coal with sodium hydroxide solutions at temperatures greater than 100 C
and steam pressure greater than one atmosphere. (0-8)
Other treatments such as the following are said to decompose pyrites and
might be u&eful in treating coals. (0-3)
(1) Sodium bicarbonate and heavy metal carbonate in a sealed tube at
185 C.
(2) Steam at 300 to 400 C.
(3) Sulfur monochloride vapors at 140 C.
(4) Moist carbon dioxide at 250 C.
(5) Carbon tetrachloride at 250 C.
The use of chemicals in combination with somewhat higher temperatures has
been found to be effective in reducing the sulfur content of coal. How-
ever, the final product is a "char" rather than coal. (0-9) For example,
when 20- to 40- mesh size coal was treated for four hours at 1000 C in
atmosphere of nitrogen, carbon dioxide, carbon -monoxide, methane or
ethylene, approximately 50 to 60 percent of the sulfur was removed.
Treatment with (1) water gas removed 76 percent, (2) anhydrous ammonia
removed 82 percent, (3) hydrogen removed 87 percent, and (4) steam re-
moved 82 percent of the original sulfur present.
345
-------
Sulfur
Coal ^
(FeS2)
Coal
LEACHER
OUJ.J.UIT
N-
r
SEPARATOR
Coal
Sulfur
>
WASHER
Coal
Sulfur
* .
SULFUR
REMOVAL
Coal
*
t
Fe'
Dilute Fe SO
2-
Air
OXIDATION
Fe
V
Iron Oxide
PRECIPITATOR
V
Iron Sulfate
FIGURE 0-1. PROCESS FLOW CHART: (1) the coal is treated with aqueous ferric
solution in a batch or countercurrent leaching unit; (2) the coal
is separated from residual iron salts in a batch or countercurrent
washing unit; (3) the elemental sulfur formed is removed by
vacuum flash distillation, inert gas vaporization, or solvent
extraction to give desulfurized coal; (4) the depleted ferric
solution is air-oxidized, producing iron oxide, and (5) the
regenerated ferric solution is recycled to the leaching unit.
-------
Statc-of-the Art Technology Projection
Currently, there appears to be no commercial installation producing low
sulfur coal by chemical desulfurization. However, from the current re-
sults of bench-scale research on the extraction of total sulfur (pyrite
and organic), it is conceivable that commercial chemical desulfurization
of coal will become a reality in a few years.
Bench-scale research has established the technical feasibility of the
removal of pyritic sulfur from coal by chemical desulfurization. Esti-
mated time span for subsequent development of this technology to commer-
cial production is 9 to 11 years. This projection is based on a time
span of 1 year for additional bench-scale research, 2 to 3 years for pilot
planting, 3 to 4 years for construction and operation of a demonstration
plant, and 3 years for construction of a commercial plant.
Current bench-scale research has resulted in the extraction of approxi-
mately 50 percent of the organic sulfur from coal. The task of removing
the additional organic should be surmountable; thus, the projected time
span for commercial production of a coal containing no pyritic sulfur and
essentially no organic sulfur is 10 to 15 years (by 1982-1985). Achieving
this goal will, of course, depend on the rate of effort. Assuming that a
modest rate of effort is put forth, it is estimated that bench-scale
technical feasibility can be established by about 1973 to 1975. Allowing
2 to 3 years for piloting of the process and another 3 to 4 years for
design, construction, and operation of the demonstration plant, it is
estimated that by about 1982 to 1985, commercial feasibility will be
established. This projected time span could probably be reduced signifi-
cantly if an all out effort were made.
Emissions
In 1969, the United States power industry discharged to the atmosphere
about 7 million tons of sulfur in the form of SC^. In the absence of
controls other than tall stacks, the discharge in 1980 is estimated to
be about 18 million tons of sulfur. Sulfur emissions control systems for
the flue gases are about 75 percent efficient. Assuming all flue gases
are controlled at the 75 percent level, sulfur emissions from power plants
are estimated to be about 4.5 million tons by 1980.
These levels of sulfur emissions explain why there is an intensified
search for new or improved technology for removal of sulfur from coal
before combustion. Achievement of this goal would reduce sulfur emissions
from power plants to practically zero.
Chemical desulfurization offers one potential solution to the sulfur
emissions problem now facing the United States. Removal of all or a major
347
-------
part of the sulfur from coal prior to combustion will result in a fuel
which can be used with a low atmospheric pollution potential. Sulfur
emissions would be negligible. Levels of other types of emissions such
as the toxic metals may be reduced significantly, depending on the pro-
ces.s employed.
The majority of the emissions to the environment to be expected from
chemical desulfurization operations will be in the form of aqueous
effluents and solid wastes. Quantities and types will depend on the
process employed and the degree of. resource recovery which can be imple-
mented. At this stage of development, the environmental impact of
employing chemical desulfurization of coal cannot be calculated on a
quantitative basis, only on a qualitative basis. This is because the
chemical desulfurization scheme is at the bench-scale state of devel-
opment. However, the probability of a low environmental impact appears
high.
The ferric salt leaching process as shown in Figure 0-1 contains the
following probable sources of wastewater, air pollution, and solid
wastes:
1. Spent leach solution from the leaching circuit.
2. By-product iron sulfate from the leaching circuit.
3. Elemental sulfur from the sulfur recovery circuit.
l\. Solvent-vapos loss from the sulfur recovery circuit.
No firm data are available at this time to project accurately the quanti-
ties of the effluent streams. The estimates given below are based on
assumptions as indicated.
Spent Leach Solution
The process claims to regenerate the leach solution by air oxidation of
ferrous iron to ferric iron and recycle of the regenerated solution within
the leaching circuit. However, continuous build-up of impurities ex-
tracted from the coal, such as certain ash components and water soluble
organic compounds, suggests the need for removing a part of the leach
solution from the circuit as waste. The quality of this wastewater stream
will depend upon the quantity of impurities generated and the extent to
which the impurities are allowed to build up in the leach solution.
Based on an assumption that the impurities are produced at a level equiva-
lent to 0.5 percent by weight of coal feed and the impurity concentration
is allowed to build up to 10 percent by weight in the leach solution, the
wastewater effluent from the leaching circuit is estimated as follows.
Basis: 1 ton of coal processed
Waste leach solution = •' '^ ~ ^ = 0.05 ton waste/ton coal
U • 1
348
-------
.Iron Sulfate
Iron sulfate and elemental sulfur are produced from the leaching circuit
during regeneration of the leach solution. These materials could be
sold, if a suitable buyer could be found, or must be disposed of by some
other means. The quantities of these materials produced from the pro-
cess vere estimated by overall sulfur and iron balance calculations as
follows.
Basis: 1 ton of coal processed
89 percent removal of pyritic sulfur
40 percent of sulfur removed is converted to
elemental sulfur
60 percent of sulfur removed is converted to
sulfate
Input
Total sulfur:
Pyritic sulfur:
Sulfate sulfur:
Organic sulfur:
Fe in
0.03 ton
0.02 ten
0.002 ton
0.008 ton
(0.02) (55.8)
(2) (32.1)
„ 0.017 ton
Output
(assuming 89 percent removal of pyritic sulfur)
Total sulfur removed from coal: 0.0178 ton
Sulfur converted to elemental sulfur: 0.0178
(0.4) = 0.0071 ton
Sulfur converted to FeSC>4: 0.0178 (0.6) = 0.011 ton
Total FeS04 produced; 0.011 ton r!52 -i = 0.052 ton
L32.1J
ji removed with waste leach solution: 0.05 ton
(15%) = 0.0075 ton (assuming 15 percent FeSO^ in
the leach solution)
FeS04(?) (solid) produced: 0.052 ton - 0.0075 ton =
0.045 ton
Elemental Sulfur
Sulfur balance calculations shown above indicate that elemental sulfur
is produced at a rate of 0.0071 ton per ton of coal processed. The
sulfur produced is claimed to have a 99.9 percent purity, indicating a
potential return from the sale of the recovered sulfur.
Summary^ of Emission Estimates
Estimated quantities of effluents from the process are summarized in
Table 0-1.
349
-------
TABLE 0-1, EMISSIONS FROM PYRITIC SULFUR REMOVAL PROCESS
Basis: 1 ton of coal, 3.0%S, 2.0% pyritic
Heating Value: 12,000 Btu/lb
Effluent
Wastewater
Solids:' Elemental Sulfur
- FeS04
Total,
Ib
.100
14.2
90
Emission, Factor,
lb/10 Btu
4.20
0.59
3.75
(a) Containing 15 percent by weight of FcSO, and additional
10 percent by weight of various inorganic and organic
compounds extracted from coal.
(b) These solids have a market potential. In this case,
they would not be considered pollutants.
Process Economics
Although the feasibility of applying chemical desulfurization technology
for producing low sulfur coals has been established, the scale of oper-
ation has not been large enough to obtain accurate cost estimates on any
of the processes and cost estimates on some of the process would be
meaningless until further experimental work is conducted. However, to
obtain preliminary costs for comparison with other processes for pro-
ducing low sulfur fuels, economics of ferric salt leaching to remove
pyritic sulfur were estimated.
Ferric Salt Leaching0"10)
By this process (Figure 0-1), aqueous ferric solution at 100 C selective-
ly oxidizes the pyritic sulfur content of coal to form free sulfur (with
part of the sulfur content being oxidised to sulfate which dissolves in
the aqueous solution). The aqueous solution is separated from the coal,
and the coal is washed to remove residual iron salts. The free sulfur
may then be removed from the coal matrix by steam or vacuum vaporization
(or solvent extraction with toluene or kerosene), and the oxidizing
agent may be regenerated in any number of ways, including air oxidation
of ferrous ion to ferric ion (Eq. 0-3). The resulting coal is basically
pyrite-free and may be used as low-sulfur fuel. The chemistry is out-
lined in Eqs. 0-1 through 0-3.
2Fe3+ + FeS2 -> 3Fe2+ + 2S (0-1)
350
-------
S ' coal -> S + Coal (0-2)
3Fe2+ + 3/2[o] -* 3Fe3+ + 3/2 [o2"] (0-3)
Since "iron is used to remove iron", on regeneration it is not necessary
to separate the iron, which is extracted from the coal, from a metal
oxidizing agent.
Total cost for installation of unit for processing 100 tons/hour of coal
is estimated at $4 million.
Operating costs are estimated at $1.95/ton of coal. This brings total
cost to about 8 cents/million Btu (0.083 ccnt/kwhr).
References
0-1. Lotnry, H. H., The Chemistry of Coal Utilization, John Wiley and
Sons, Inc., London, p 425 (1945).
0-2. Leonard, J. W., and D. R. Mitchell, "Coal Preparation", AIME,
New York, p 1-45 (1968).
0-3. Given, P. H., and Wyss, W. F., "The Chemistry of Sulphur in Coal",
British Coal Utilization Research Association Monthly Bulletin,
.25, p 166 (1961)
0-4. Masciantoni, P. X., Fuel, £4 pp 269-275 (1965).
0-5. Leonard, J. W., and Cockrell, C. F., Mining Congress Journal,
pp 65-70 (December 1970).
0-6. Environmental Science end Technology, p 474 (June 1970).
0-7. Chemical Week, pp 41-42 (September 13, 1972).
0-8. Unpublished research conducted at Battclle's Columbus Laboratories,
Columbus, Ohio.
0-9. Snow, R. D., "Conversion of Coal Sulfur to Volatile Sulfur Com-
pounds", Industrial and Engineering Chemistry, (August 1932).
0-10. Science .177, pp 1187-1188 (September 29, 1972).
351
-------
APPENDIX P
PRODUCTION OF SYNTHETIC HYDROCARBON LIQUIDS FROM COAL (LIQUEFACTION)
Table of Contents
Page
Summary i . . . 354
Technology 355
Emissions 361
Pollution Controls 362
Areas of Uncertainty 355
References . - ogg
List of Tables
P-l. Material Balance Information-Solvent Refined Coal Process. 360
List of Figures
P-l. Solvent Refined Coal Process 357
P-2. Solvent Refined Coal Process 358
353
-------
APPENDIX P
PRODUCTION OF SYNTHETIC HYDROCARBON LIQUIDS
FROM COAL (LIQUEFACTION)
Summary
Currently there are seven processes that have as their main objective
the production of liquid hydrocarbons from coal. These are:
1. Fisher - Tropsch Synthesis
2. Pittsburg and Midway Coal Co. - Solvent Refined Coal Process
3. Consolidated Coal Company - Solvent Refining and Hydrogenation
Process
4. Hydrocarbon Research Incorporated - H-Coal Process
5. Project Seacoke Process
6. COED Process
7. University of Utah - Intermediate Coal Hydrogenation Process
These seven processes are in various stages of development with the Sol-
vent Refined Coal Process being the most advanced and the Intermediate
Coal Hydrogenation Process being the least advanced. Two pilot plants
(6 and 50 ton/day plants) have recently been announced Lo demonstrate the
SRC process.
The Solvent Refined Coal process can produce an ashless, low-sulfur product
of sufficiently high quality and Btu content that it can be substituted for
coal, or when used in liquid form, fuel oil. The product as now conceived
can produce fuel having 16,000 Btu/lb, 0.6 percent sulfur, and 0.05 percent
ash.
Typical emission factors arising from a 222 x 109 Btu/day (about 950 MW)
Solvent Refined Coal plant are compiled with others in the body of the
report. Pittsburg and Midway Coal Company estimated the cost of the
solvent refining step (i.e., the cost of the process exclusive of the cost
of the feed coal) to be:
1. 30 cents/10^ Btu (based on 20 year amortization)
2. A3 cents/10 Btu (based on 5 year amortization)
354
-------
The cost of coal has not been included in the calculations because it
varies from one plant situation to another. The total product selling
price can be developed by adding to the above prices the coal cost in
cents per million Btu multiplied by a factor of 1.33. This factor takes
into account thp 75 percent overall fuel efficiency of the process. Of
the 30 cents/10 Btu cost figure (20 year amortization), all costs would
be attributed to pollution control since the process was developed as a
means of obtaining a clean burning fuel. Pollution control costs for a
SRC plant located adjacent to the power station including* coal loss would
range as follows:
20-Year 5-Year
Coal Cost Amortization, Amortization
$/ton cents/106 Btu cents/106 Btu
0 (Processing Cost) 30 43
3 34 47
8 41 54
12 47 60
The above costs were estimated on the basis of a process design study and
have yet to be verified at the pilot-plant level.
Technology
The production of liquids from coal can follow one of four general paths:
(a) production of a hydrogen-carbon monoxide mixture from coal, followed
by catalytic synthesis of hydrocarbons (variations of the Fischer-Tropsch
process); (b) solvent refining (essentially dissolving of coal with
minimum hydrogcnation to produce a low-ash and low-sulfur heavy bottoms
product; (c) pressure hydrogenation of coal from the approximate compo-
sition CHg.75 to nearer CIl]^0 using H2 or H2-CO mixtures (variations on
the Bergius or Pott-Brochc processes); and (d) staged pyrolysis (heating
to drive off volatile elements) to minimize the residue. The last of
these methods produces gas as well as liquid products.
Currently, there are seven processes that have as their main objective the
production of liquid hydrocarbons from coal. These are:
1. Fischer-Tropsch Synthesis
2. Pittsburgh and Midway Coal Co. - Solvent Refined Coal Process
3. Consolidated Coal Company - Solvent Refining and Hydrogenation
Process
^
4. Hydrocarbon Research Incorporated - H-Coal Process
5. Project Seacoke Process
355
-------
I.
6. COED Process
7. University of Utah - Intermediate Coal Hydrogenation Process
These seven processes are in various stages of development with the
Pittsburg and Midway Solvent Refined Coal Process being the most
advanced and the Intermediate Coal Hydrogenation Process (Utah State
University) being the least advanced. The latter is included only for
completeness and has not yet been thoroughly researched on the bench
scale. The Fischer-Tropsch process is included in the'above list for
historical purposes. The major products from this process are gasoline,
diesel fuel, waxes, and a wide spectrum of organic chemicals. The pro-
cess makes very expensive products by American standards, and is generally
considered unattractive in the United States.
A very detailed review of the available technical literature regarding the
above processes has been performed by Hottel and Howard(P-l) and
Schurr.(^"2) Details of these reviews will not be reproduced here.
Emphasis in the present work will be placed on the Pittsburg and Midway
Solvent Refined Coal Process. It is, in Battelle's judgment, the
furthest along in development for commercial application and seems well
suited to the needs of the electric utility industry. Two pilot plants
for studying the process have recently been announced.(P~3,P-4) ^ six.
ton per-day pilot plant for studying the steps in the Solvent-Refining
Process will be built at the Southern Electric Generating Company's
Ernest C. Gaston plant.(P~4) Funding for the project will come from the
Edison Electric Institute ($4 million) and Southern Company's operating
affiliates ($2 million). Groundbreaking ceremonies for a 50-ton-pcr-hour
plant at Tacoma, Washington, were held on October 27, 1972.(^"3) Funding
for this project will come from the Office of Coal Research.
Pittsburg and Midway
Solvent-Refined Coal Process
Solvent refining was initiated with the limited objective of producing a
low-cost antipollution alternative to residual oil and natural gas for
use in boilers. Since the process is not primarily designed to produce
lighter oil products, only limited hydrogenation is required. The
hydrogenation step is followed by ash separation and conversion of sulfur
to a removable form. The original laboratory development of the chemical
process involved was carried out by Spencer Chemical Corp. (now Pittsburg
and Midway Coal Mining Company) and an economic evaluation of a full-scale
plant has been published.(P~5) More recently Process Research, Incor-
porated'*" ' updated this work.
The process can use any rank coal, from lignite to low-volatile bituminous.
The Solvent Refined Coal process is illustrated in Figures P-l and P-2.
Using the process, an ashless, low-sulfur fuel having a heating value of
about 16,000 Btu per pound can be produced from coal. The fuel product is
produced by dissolving coal in a coal-derived solvent in the presence of
hydrogen at a pressure of 1,000 psi or greater and a temperature of 825 F.
356
-------
Dissolve^
preheate
Solvent from
splitter column
Coal
preparation
VI
Cool
935.000
Ib/hr
Coal-l.027.778
• . Ib/hr
. BCR.
gasifier
Gas to purification
sulfur- 27.364 Ib/hr
s-88.8%
To solvent recovery_
To phenol end
cresylic ocid recovery
Water from phenol
and cresol recovery
V/ash solvent
.Mineral
residue recycle
Slog-147.711 Ib/hr
.sulfur- 0
FilTrcJion
Coal-solvent solution
To
Ash-148,000 Ib/hr
Sulfur- 30.833 Ib/hr
s-100%
evaporator
FIGURE P-l. • SOLVENT REFINED -COAL PROCESS
Basis: 3.0% Sulfur; 14.4 % Ash; 12.000 Btu/lb
222 MMM Btu/day Capacity (950 mw)
-------
Solvent from
gas-liquid
separator
Solvent to.
coat preparation
Wash solvent
to filtration
Splitter
Column
Light ends
column
Solvent
recovery system
Light
oil •—.
From.
filtration"
Evapo-
rator
4 (To soles)
1 Light oils
Clous
Plant
Toil gos
sulfur-27 IbThr
. s-0.1%
. s-300ppm
Plant fuel
From
gas-liquid
ssporgtion^
gas
removal
Aqueous layer from
gas-liquid separation
Elemental
sulfur-27364lb/hr
.s-88.7%
Water to
dissolver
^~ Product - 578,125 ID/hr
. Ash-289
Sulfur -'3469 Ib/hr
s - 11.2%
FIGURE P-2. SOLVENT REFINED COAL PROCESS
Basis: 3.0% Sulfur; 14.4% Ash; 12,000 Blu/lb
222 MMM Btu/day Capacity (950 mw)
-------
The coal-solvent solution is then filtered and evaporated to yield the
fuel product with ash and sulfur both substantially removed. The fuel
product can be utilized as either a liquid or solid.
Initially, the coal is crushed to 1/8 inch or less and dried to a
moisture content of 3 percent. It is then fed to a slurry mix tank
where it is mixed with an anthracene oil at a temperature of about 300 F
to form a slurry, The coal-solvent slurry is then pumped through a line
where synthesis gas (a mixture of methane, hydrogen, carbon monoxide,
and carbon dioxide) is added.
The coal-solvent slurry and synthesis gas are pumped through the dissolver
preheater into the dissolver. The coal depolymerizatibn and dissolving
process begins in the preheater where the material B°es through a gel
stage. Dissolving is completed in the dissolver. Simultaneously intro-
duced into the preheater is a water stream recycled from the phenol and
cresol separation section of the plant.
As a result of the solution and hydrogenation reactions which occur in
the dissolver, hydrocarbons, H2S, heavy oils and C02 are formed. The
total product stream flows from the dissolver to tHc high pressure flash
vessel in which vapor and liquid are separated. The vapor stream,
containing light hydrocarbons, phenols, crcsols, water vapor, 112$, C02
and fuel gas, is fed to the gas-liquid separation section of the plant.
After further pressure reduction, the liquid stream is fed to rotary
pressure filters.
The filters remove ash and undissolved carbon from the coal-solvent
solution. The filter cake is washed with light solvent to remove coal-
solvent solution. The remaining mineral residue, containing about 70
percent ash and 30 percent carbon, is then recycled to the coal gasifier.
The coal-solvent solution is then fed to the vacuum flash evaporator
where it is flashed at 625 F to separate the liquid coal from the anthra-
cene oil-and light solvent. The flashed anthracene oil wash solvent,
light hydrocarbons and dissolved gases are condensed and fed to the sol-
vent recovery unit. The liquid coal, with light oil blended back in, is
then ready for fuel use. It can be fed as a hot liquid directly to an
on-site user or it can be solidified for shipment to a distant use point.
In the gas-liquid separation section of the plant, three streams are
isolated for further processing. A gas stream, consisting of I^S, CC>2
methane and other gases, is fed to the acid gas removal system. A
hydrocarbon-rich stream is combined with the vacuum flash 'evaporator
condensate and fed to the solvent recovery system. A water-rich stream
containing phenols and cresols is fed to the phenol and cresol separation
unit.
In the acid gas removal system, CO2 and H2S are separated from the gas
stream and sent to a Glaus unit (and tail gas treatment system) where
the H2§ is converted to elemental sulfur. The other gases, with 99.9
359
-------
percent of the H2§ removed, are used for plant fuel.
In the solvent recovery system, the solvent mixture is first fed to the
wash solvent splitter column. In this column, wash solvent and lighter
material are boiled off overhead to the light ends column, leaving the
anthracene oil for recycle to the coal preparation system.
The wash solvent and other light materials are fed to the light ends
column. In this column, light oil is boiled off leaving the wash solvent
for recycle to the rotary pressure filters, The light oil flows to
the phenol and cresol separation unit, if economics dictate such a unit,
otherwise only a water-light oil separation unit will exist. .
In the phenol and cresol separation unit, phenols and cresols are removed
from the light oil and from the water-rich stream coming from gas-liquid
separation. The phenols and cresols arc blended back into the liquid
coal product. The light oil can be blended into the liquid coal product
also, or it cam be sold directly as a by-product. The water is recylced
to the preheater.
Process Research, Inc. performed a conceptual design study on a 222 billion
Btu per day Solvent Refined Coal Plant(p~6), i.e., for a plant large enough
to supply fuel to a 950 MW power station. The material balance is sho\m
in Table P-l and on the flowsheets (Figures P-l and P-2). The above plant
Btu output is based upon producing a single product with phenols, cresols,
and light oil included as part of the product. The feed material basis
is bituminous coal having 3.0 percent moisture, 14.5 percent ash, and
3.00 percent sulfur. The fuel product contains 0.6 percent sulfur and
0.05 percent ash.
TABLE P-l. MATERIAL BALAK7CE INFORMATION-
SOLVENT REFINED COAL PROCESS
AT 222 109 Btu/DAY
PLANT CAPACITY (950 MW)
Eastern Coal(a)
Input, tons/hr
Coal 514
Energy, Btu/hr 12.35 x 109
Output, tons/hr
SRC 289
Slag 73.9
Sulfur 13.7
Tail Gas Sulfur —
Coal Consumed 225
Heat 9.25 x 109
Overall Fuel Efficiency, percent 75
(a) Typical eastern coal having 3.00% S, 14.4 Ash and
12,000 Btu/lb.
360
-------
Emissions
For the material balance shown in Table P-l, estimated emission arising
from the Solvent Refined Coal process are presented in the module data
sheet.
Air
Typical process air emission were estimated using EPA emission factors^
for N0}., CO, particulate matter, and total organic matter. The principal
air emissions arising will be NOX and CO obtained from consumption of
coal (in the form of fuel gas) in the process to fulfill the required
heat balance. There will, of course, be some sulfur emissions, expected
in the form of sulfur dioxide, in a tail gas released during the gas
purification and sulfur removal step. In the process sulfur is removed
and recovered using Glaus plant technology, backed up if need be by a
tail gas treatment plant using one of several processes available. For
the purposes of this discussion it was assumed that the Glaus plant used
in the process would be equipped with the latest advances in tail gas
treatment. Sulfur recovery efficiency would, therefore, be 99.9 percent
and only 27 pounds per hour of sulfur as S02 would be emitted to the atmos
phere. The tail gas being emitted to the atmosphere would contain approx-
imately 300 ppm (about 0.02 grain per scf) of sulfur.
Water
VJater emissions from the plant should be minimal. In a well designed
plant, closed-loop cooling would be employed and maximum use made of
cooling towers and air coolers. Process water would be required mainly
as a raw material for its hydrogen content in the BCR gasifier. However,
all process water not used as a raw material would be recycled. There
will, of course, be some concentrated blowdo\m streams from boilers and
cooling towers to be disposed of. These should not be significant and
arise from dissolved and suspended solids in the raw material water coming-
into the plant.
Solid Waste
There will be at least one solid waste stream arising from the Solvent
Refined Coal Process. This is a process slag of about 73.9 tons/hr
from the BCR gasifier and consists mainly of the ash removed from the
solvent refined coal product. Elemental sulfur will also be recovered
(13.7 tons/hr)'. If this could not be sold it would constitute a solid
waste, or perhaps better considered a storable resource. For the design
Study performed, elemental sulfur would amount to 13.7 tons/hr.
Land Use
t
It is estimated that a 222 MMM Btu/day Solvent Referred Coal plant (about
361
-------
950 MW) will require a site about 750 acres in size for the plant, the
associated coal storage piles, and a solid waste disposal area for the
resultant slag. In estimating the land area required for slag (solid
waste) disposal, the basis considered was a 20-year plant life, 1 x 10
tons, and an average slag depth of 10 feet.
Other
It is possible that by-products could be recovered and,sold. In addition
to sulfur, such materials as cresols, phenols, and light oil could be
recovered under certain attractive commercial conditions and sold as
chemicals. If not, they would have to be blended into the product and
sold as fuel. As previously mentioned, it is also possible that sulfur
could be sold. Alternatively, it would have to be disposed of as a dry
landfill.
Pollution Controls
Methods
The Solvent Refined Coal process is itself a pollution control method and
represents an alternative to flue gas cleaning for fly ash and sulfur
removal from coal.
In the process, no aqueous waste waters are discharged to the environment,
and all contaminated waters are recycled. In this sense, it would appear
to be superior to flue gas cleaning processes based upon absorption
technology which use fairly liberal quantities of x;ater and give rise to
sludges which are often ponded for indefinite periods.
The ash in the coal is removed as a slag from the BCR gasifier and the
refined product contains about 0.05 percent ash. When this fuel is
burned with 20 percent excess air in a power station, for example, the
particulate content of the flue gas would be about 0.02 grain per standard
cubic foot (0.03 Ib Ash/10^ Btu) and, therefore, would not require any
treatment for particulate removal, since it \7ould easily meet pollution
control standards. By way of comparison, post-combustion processing
removes ash partially as bottom ash off the boiler and fly ash in a
particulate control device, i.e., in an electrostatic precipitator,
scrubber, fabric filter, etc. In a post-combustion removal process
burning coal having the composition shown in Table P-l in 20 percent ex-
cess air, the particulate control device would have to be approximately
99.6 percent efficient to achieve an outlet flue gas loading of 0.02
grain per standard cubic foot, i.e., to achieve a dust loading equivalent
to that of burning Solvent Refined Coal.
Similar to gasification processes, sulfur is removed from the coal in the
SRC process by hydrodesulfurization, i.e., by treatment with hydrogen and
362
-------
recovery of the evolved H2S as elemental sulfur in a Claus process with
tail gas treatment if necessary. The currently obtainable level of sulfur
in the product is about 0.6 percent. In the Claus process, H2S is com-
busted under precisely controlled conditions so that one-third of it is
converted to SO?. The cooled combustion products arc catalytically
reacted to form elemental sulfur
Cat
2H2S + S02 .£> 3S + 2H20
after which the sulfur is condensed and separated. However, recovery is
not complete even with three converters, and as much as 5 percent of the
entering sulfur is contained in the exit (tail) gas. Recently developed
tail gas treating technology, e.g., the Beavon, Cleanair, and IFF pro-
cesses, achieves recovery of almost all of the remainder. Consequently,
sulfur removal of 99.5 to 99.9 percent is achieved on the incoming
Since the process is only now planned for pilot testing at a modest
scale(P"3»P'4), it is still speculative whether the process can achieve
the 0.6 percent sulfur level in the product in large quantities on a
routine basis. If this can be done, then burning SRC product in a power
station would achieve a sulfur level of approximately 400 ppm SOo in the
flue gas with no additional treatment (i.e., assuming 20 percent excess
air for combustion). This would be equivalent to about 0.75 lb S02/10^
Btu of SRC burned. Such a level would meet the current EPA standard of
1.2 lb S02/10 Btu. If the standard became more stringent, it is conceiv-
able that the sulfur level in the SRC product would have to be decreased.
By way of comparison to flue gas desulfurization processes (3 percent
sulfur coal with a heating value of 12,000 Btu/lb), the flue gas de-
sulfurization process would have to remove 85 percent of the sulfur to
achieve the 0.75 lb S02/106 Btu level attainable from burning SRC pro-
duct (i.e., go from about 5 lb 302/10^ Btu with no control when 3 par-
cent sulfur coal is burned to 0.75 lb S02/106 Btu with the SRC product).
Effectiveness and Cost
Estimating reasonably accurate pollution control costs for the Solvent
Refined Coal process is extremely complicated since the process is only
now planned for pilot testing on a large scale. The assumption is made
that solvent refined coal can be substituted for any of the other fuels
without difficulty and is itself a pollution control strategy. The cost
to utilities of achieving pollution control through the substitution of
solvent refined coal for currently burned conventional fuels will depend
on the price at which solvent refined coal is available locally relative
to that of other fuels.
attempted to estimate pollution control costs in 1966 based
on little pilot-plant data. Jimeson's cost estimation technique was as
follows. First, the cost of solvent refined coal was determined at four
selected plant locations scattered over the United States. Second, the
transportation cost of distributing the refined product to each state was
added to obtain the delivered price of solvent refined coal in each.
363
-------
Third, the delivered price was compared to the price of fuels currently
being burned in power plants in each state. The difference represented
the cost of air pollution control achieved by sutstituting refined coal
for presently burned contaminated fuels in existing power plants. Also
since solvent refined coal can be melted and pumped to a burner in the
same manner as a residual oil, the expense of the coal handling and feed-
ing mechanism, the grate, and the ash disposal equipment common to coal-
fired units can be conserved. Credits equal to these savings in capital,
maintenance, and operating costs were then applied to new plants burning
SRC.
Jimeson estimated processing costs (in terms of 1966 dollars) range
between 18.8 and 19.2 cents per million Btu's. The price of solvent re-
fined coal at t.he plants ranged from 27.1 to 32.4 cents per million Btu's
for coals costing between $1.30/ton (8.3 cenus/lO^Btu) and $2.97/ton
(13.2 cents/10 Btu) at the mine. The average cost of pollution control,
through replacement of coal used by the utility with solvent refined coal
in existing power stations was estimated to range from 4 to 29 cents/10°
Btu. Expressed as a national average the estimated cost was 14 cents/10^
Btu, Jimeson also estimated costs for new plants taking credit applied
when SRC is used. These estimates were even more optimistic.
New cost estimates were made in 1970 by Pittsburg and Midway(^~5) and
later reported by Process Research, Inc.(p"") The P&M estimate indicated
a commercial 222 billion Dtu per day capacity plant will cost about $80
million. Two selling prices (processing costs) of the product were
computed not including the cost of feed coal. The prices reported are:
Based on 20 year amortization 30 cents/10 Btu
Based on 5 year amortization 43 cents/10^ Btu
These prices were based upon the "Office of Coal Research Tentative Stan-
dards for Cost Estimating of Investor-Ouned Plants for Producing Pipe-
line Gas from Coal". Constants used in the computations are:
Gross return 9 percent of rate base
Debt financing 65 percent of rate base
Interest cost 7.5 percent of rate base
Federal income tax 48 percent of rate base
The cost of coal was not included in the calculations because it varied
from one plant situation to another. The total product selling price at
the plant can be developed by adding to the above prices the cost in
cents per million Btu multiplied by a factor of 1.33. This factor takes
into account the 75 percent overall fuel efficiency of the process.
The pollution control cost (P) in cents/10 Btu for a SRC plant located
adjacent to the power station (including coal losses) can be estimated by
the equations:
364
-------
P n 1.33 A + 30 '(20 year amortization)
"P «= 1.33 A + 43 (5 year amortization)
where A is the cost of feed coal in dollars per ton and the coal has the
composition shown in Table P-l. For this simplified case, typical
pollution control costs would range as follows:
20 Year 5 Year
Coal Cost, Amortization, Amortization,
$/ton cents/106 Btu cents/106 Btu
0 (processing cost) 30 43
3 34 47
• 8 41 54
12 47 60
This can be compared to flue gas cleaning which ranges between 11.3 to
79.0 cents/10 Btu.
Areas of Uncertainty
In the period 1962 through 1964, the process was studied in a batch auto-
clave and in a 1 pound per hour continuous bench-scale unit. In 1964 a
continuous 2-ton per day process development unit was started and operated
until 1965. Process Research Inc.'P~ ' reports that the longest single
continuous run lasted about one month. Currently the SRC process is being
planned for pilot testing in both 6 and 50 ton/day plants. The Ft. Lewis,
Washington, pilot plant (50 ton/day) is expected to be completed by late
1973. Developmental operations arc expected to require 2 to 3 years for
completion.
The following technical problems remaining are reported by Process Re-
search, Inc.*>p"^) It is expected that test work in the Ft. Lewis pilot
plant will focus on the following:
1. Verify the process economics, since currently they are based
solely on the bench-scale data.
2. Determine the adequacy of the materials of construction for each
vessel in the process. The current estimated capital cost for the
commercial scale plant is based on use of carbon steel and low alloy
steel. If pilot-plant study shows that these materials are inade-
quate from a corrosion standpoint, then the initial plant investment
could be significantly increased. At present, the developers are
working to determine the lowest feasible grades for construction
materials.
3. Study operating parameters in the dissolver to reduce the amount
of sulfur in the product.
365
-------
4. Study the optimum method of solidifying the product to permit
marketing.
5. Determine the actual necessity for the two-column distillation
system now conceived for solvent separation.
6. The filtration step in the process will require study to assure
high recovery of wash solvent and to determine the performance of
filter seals and bearings when operating at high temperature and
pressure. This could be very important to process economics.
Not to be studied at Lhe pilot plant, but under consideration is:
7. The suitability of Lhe high-pressure slagging coal gasifier as a
means of producing the necessary synthesis gas. If the gasifier is
found unsuitable, the synthesis gas can be produced by steam reforming
of product gases or by partial oxidation of the light oil. However,
in that case, disposal of the mineral residue consisting of 70 percent
ash and 30 percent carbon would then become a serious problem.
References
P-l. Hottel, H. C., and Howard, J. B., New Energy Technology--Some Facts
and Asse ssment s, MIT Press, Cambridge, Massachusetts (1971) pp
161-186".
P-2. Schurir, S. H., "Energy Research Needs", Government report PB-207-
516 (October, 1971).
P-3. Anonymous, "Solvent-Refining of Coal Continues to Come Closer",
Chemical Engineering, 52 (October 16, 1972).
P-4. Anonymous, "Six Million Dollar Joint Project Aims for Clean Coal",
Electrical World, 178 (8), 30 (October 15, 1972).
P-5. Pittsburg and Midway Coal Mining Company, "Economics of a Process
to Produce Ashless, Low-Sulfur Fuel from Coal", Research and
Development Report No. 1, prepared for Office of Coal Research,
Dept. of the InLerior, Washington, D.C., (June, 1970).
P-6. Process Research, Inc., "Evaluation of Fuel Treatment and Conver-
sion Processes", report prepared for the EPA, Contract No. 68-02-
0242, and CPA-70-1 (July 7, 1972).
P-7. U.S. EPA, "Compilation of Air Pollutant Emission Factors", Office
of Air Programs Publication Number AP-42.
P-8. Jimeson, R.M., "Utilizing Solvent Refined Coal in Power Plants",
Chemical Engineering Prog., 62(101). 53(1966).
366
-------
P-9. Hill, G.R. (Director of the Office of'Coal Research), "Status of
Processes for Utilization of Hi.gh Sulfur Coal in Conversion and
Power Generation Systems", paper presented before the Electrical
World's Technical Conference entitled Sulfur in Utilit.v Fuels:
The Growing Dilemma. Chicago, Illinois (October 26, 1972).
367
-------
APPENDIX Q
COAL'GASIFICATION
Table of Contents
Page
Summary 370
Technology *. . . . 371
Emissions 376
Pollution Control 378
References -. . 335
List of Tables
Q-l. Environmental Emissions Arising from Coal Gasification
Processes 377
Q-2. Estimated Coal Gasification Process Economics 381
List of Figures
Q-l. Schematic Flow Diagram for Producing High Btu Fuel
Bases 373
369
-------
APPENDIX Q
COAL GASIFICATION
Summary
The gasification of coal is a technique to change the form of coal from
a solid to a gaseous fuel. Two types of classes of processes are being
developed: those Lhat produce a low heating value fuel gas (100 to
500 Btu/ft^ STP) and those that produce a high heating value product,
equivalent to that of natural gas (about 1,000 Btu/ff STP).
Present coal gasification processing alternatives may be characterized
as those that add oxygen (either pure or as air) to the gasifier, those
that add hydrogen, and those that use an externally fired circulating
heat carrier. There are many variations on the general coal gasifica-
tion process scheme. Consequently, for use in this analysis, four
processes were considered:
(1) Low Btu gas
(a) Lurgi process
(b) Two-Stage Coal Combustion process (molten
iron combustion)
(2) High Btu- gas
(a) Hygas process
(b) C02 Acceptor process.
Selection of these processes corresponds to two options. Processes
that produce low Btu gas would be located in close proximity to the
power plant that use the fuel gas. Thus in this option, coal would
still be transported to the utility site. Processes that produce high
Btu gas would be located at the coal source and the product gas would
be transported by pipeline to the utility. High Btu gas would also be
used for space heating and industrial applications.
Typical emissions estimated for gasification plants of approximately
250 x 10 Btu/day for each of the above processes are given in the
nodule data sheets in Appendix A of this report. Estimates for the
cost of pollution control (i.e., the cost of the process exclusive of
the cost of feed coal and transportation) are:
Low Btu gas .- about 30c/10 Btu
High Btu gas - 30 to 50C/106 Btu.
370
-------
Technology
The gasification of coal is a technique to change the form of coal from
a solid to a gaseous fuel. Two types of classes of processes exist,
those that produce a low heating value fuel gas (100 to 500 Btu/ft^
STP) and those that produce a high heating value, equivalent to that
of natural gas (about 1,000 Btu/ft3 STP). The latter is often referred
to as SNG (substitute natural gas) or "pipeline" quality gas.
In the production of low Btu fuel gas, the basic gasification process
consists of reacting steam with coal at elevated temperatures. The
main reaction occurring is:
C + H20 J= CO + H2 (Q-l)
This reaction is endothermic, the heat for this reaction being supplied
by combusting a portion of the coal in air or oxygen:
C + 1/2 02 = CO (Q-2)
C + 02 * C02 (Q-3)
In addition, the water-gas shift reaction occurs
CO + H20 s C02 + H2. (Q-A)
In the production of pipeline quality gas from coal in addition to the
above, the basic reactions may be summarized as follows:
Coal - C (Char) + CH^ -I- a mixture of liquids and (Q-5)
gases
C + 2H2 tf CH4. (Q-6)
Equation (Q-5) represents the devolatilization of coal. The mechanisms
for the production of methane can be illustrated by Equation (Q-6),
which is exothermic, or by a combination of Equations (Q-4) and (Q-l)
to give
C + 2H20 * C02 + 2H2, (Q-7)
which may be combined with Equation (Q-6) to give
2C + 2H20 s± C02 + CH4 (Q-8)
Whether high Btu gas or low Btu gas is produced depends upon the con-
ditions (temperature, pressure, residence time, etc.) in which the
gasifier is operated and the methanation step in the processes.
Present gasification processing alternatives may be characterized as
those that add oxygen or air to the gasifier, those that add hydrogen,
371
-------
and those that use an externally fired, circulating heat carrier. Most
processes use the first technique. A generalized flowsheet for most
coal gasification processes for producing cither low Btu or high Btu
fuel gas is shown schematically in Figure Q-l. This flowsheet is not
representative of the two-stage combustion process. Initially, the
coal is prepared to remove refuse and pretreated to prevent caking.
It is then sent to the gasifier where hydrogen, oxygen, or an external
heat source are added to bring about the gasification reactions. The
mixture leaving the gasifier requires further treatment to convert it
into either low Btu fuel gas suitable for use by utilities or SNG.
Steps in the treatment are essentially the same regardless of the gas-
ification method, although design details, heat recovery, sulfur
removal, etc. may be different. The gas mixtures pass through cyclone
separators to remove fine particles and dust. It is then scrubbed to
remove condensible materials and sent through a shift converter (if
needed) to obtain the proper ratio of hydrogen to carbon monoxide for
methane-formation. The stream is then scrubbed with activated potassi-
um carbonate, Rectisal, Purisol, or other proprietary solvent to remove
carbon dioxide and hydrogen sulfide and, perhaps, is passed over acti-
vated carbon to remove organic compounds. At this point the Btu con-
tent of the gas is about 100-500 Btu/ft3 STP and the option is available
to use this material directly in generating electricity or further pro-
cessing into a high Btu (1000 Btu/ft3 STP) gas. In the latter case,
iron oxide or equivalent absorbents remove any remaining traces of
sulfur. The gas is methanated to increase its heating value and re-
duce thp CO content to an acceptable limit. The methanated gas is
dried and, if necessary, compressed to pipeline pressure.
There are many variations of the above scheme, some of the more common
of which are:
(1) Oxygen or Air Addition Methods
a. Lurgi process
b. Koppers - Totzek process
c. Bi-Gas (Bituminous Coal Research, Inc.)
d. Synthane (Bureau of Mines)
e. Molten-Salt Gasification (M. W. Kellogg Co.)
£. Two-Stage Coal Combustion Process (Applied
Technology Corporation)
(2) Hydrogen-Addition Methods
a. Hygas (Institute of Gas Technology)
b. Electrofluidic Coal Process (Iowa State University)
(3) Heat-Carrier Methods
a. C02 Acceptor Process (Consolidation Coal Company)
372
-------
Hydrogen (or hydrogen-rich ge*}**»—"
H:Sto
• Oxygen j |
Xs5^ Coal • Prctreatment
-<£*i-:si.-*> preparation — P* to p'?wcnt ' 'A *" Cdsifieatlon '
Coalfiom P ' cakino f
r
i
Shift
converter
mi.ien-outh | , ! 1 Scrubber!
Refuse Ash
1 /
-J
re
a
[r
u-iur
»
ecovery
i^cid
moval
i
Trace
sulfur
removed
1 U
L-
Trace
ornsnics
romowjl
*
r
Meihanation
Drying
-^jiVlethanation
-
Drying
awu to
pipeline
1 A f
Le»[ Compression L.J
Low Btu Gas
Alternative
(to utility boilers)
FIGURE Q-l. SCHEMATIC FLOW DIAGRAM FOR PRODUCING HIGH BTU FUEL
BASES(a)
(a) Process streams are indicated by solid lines and alternatives by
broken lines. Source: Reference (1).
-------
For use in this analysis, four processes were considered: two that
produced a low Btu gas corresponding to the option in which the fuel
gas is combusted directly in a boiler to produce electrical energy
(i.e., the gasification facility is closely coupled to the power plant);
and two processes that produced high Btu gas corresponding to the
option of transporting high Btu gas from a centralized gasification
facility to several power plants and for use in space heating and in-
dustrial applications. Detailed process descriptions are given by
Robson et al.,'Q~*' and Process Research Incorporated^"^', and will
not be repeated here. The processes selected for this study are:
(1) Low Btu gas
a, Lurgi process
b. Two-stage Coal Combustion Process (molten iron
combustion)
(2) High Btu gas
a. Hygas process
b. C(>2 Acceptor process.
The Lurgi Process is considered a "first-generation" system, i.e., a
system based upon presently available, but not necessarily commercially
utilized technology. All others are either "second- or third-genera-
tion" systems and are based on technology to be developed within the
next 10 to 20 years. Also by making the above selection of processes,
a.hydrogen addition method was represented (Hygas) as well as a heat
carrier method (C02 Acceptor). The two-stage coal combustion process
appears to be the least developed of the four processes considered.
Low Btu Fuel Gas
Lurgi Process. Coal is introduced into the top of the gasifier through
a coal lock, and distributed over a bed of coal that rests on a rotat-
ing grate. Oxygen and steam are introduced at the base of the bed, and
flow countercurrently to the descending bed of coal. The gasification
reactions occur in zones through the bed of coal in the gasifier. In-
itially coal reacts with air to form C02 according to Equation Q-2
while simultaneously coal reacts with steam to produce CO and H2 accord-
ing to Equation Q-l. The latter reaction is endothermic, hence, the bed
temperature is kept below the fusion temperature of the ash. As the
combustion gases proceed upward through the bed additional endothermic
gasification reactions occur together with the water-gas shift reaction,
Equation Q-4. Methane is produced by the reaction of coal with the
hydrogen from the shift reaction and additional methane and higher
hydrocarbons are produced by the devolatilization of the coal,
Equation Q-5. Gasified materials leave from the top of the gasifier
at 950 F, while ash is withdrawn from the base of the water-jacketed
generator through an ash lock. Operating pressure may be close to
500 psi.
374
-------
The gas mixture produced contains 3 to 15 percent methane (typically 10
percent). It is scrubbed to remove organic material, and then processed
as described previously in Figure Q-l to produce low Btu fuel gas.
Feed to the gasifier must be lumps of coal, 1/8 to 1-1/4 inch. Smaller
pieces and dust particles are briquetted and then used. Noncaking coal
is preferred. Subbituminous coals in the Western states seem to be
better suited for the Lurgi process. The amount of oxygen required
varies with the reactivity of coal, but typically might be equal to
30 percent of the weight of the charged coal.
Two-Stafte Coal Combustion Process. The Two-Stage Coal Combustion
process (Applied Technology Corporation) produces boiler fuel gas
having a heating value of approximately 300 Btu per standard cubic
foot. This gas is produced by the combustion of coal in a bath of
molten iron in the presence of a substoichometric amount of air at
essentially atmospheric pressure. The gas, rich in carbon monoxide
and essentially sulfur-free, is then fed at a temperature of 2700 F
directly to the burners of a boiler. Sulfur from the coal is removed
via a slag layer and slag-iron separator and converted into elemental
sulfur through a slag desulfurizer, condenser, and Claus unit.
High Btu Fuel Gas
Hygas Process (Institute of Gas Technology). The basic process fea-
tures production of hydrogen from char by the use of electric energy.
Coal is crushed and dried and for caking coals, the surface is oxidized
by pretreatment with air at 800 F. It is then slurried with a light
oil, pressurized to 1100 psi , and pumped to the top of the hydrogasi-
fier. The hydrogasifier contains three sections. In the upper section
the slurry is dried. Oil is driven off with the raw gas (containing
about 17 to 25 percent methane) and is recovered and recycled. In the
second section, coal is heated to 1200 to 1400 F and devolatilized. In
the third section, the coal is heated to 1700 to 1800 F in the presence
of a hot hydrogen-rich stream and steam,' and is gasified.'^" '
About half of the carbon entering the reactor is gasified. The re-
maining char is conveyed to an electrothermal gasifier. There,
electric energy is used to heat the bed. Steam is introduced, forming
hydrogen and carbon oxides. The gas mixture, at about 1900 F and
1100 psi, is sent to the hydrogasifier. The remaining char is conveyed
to a power plant where it is burned to generate steam and elctrical
energy needed by the process. A 75-ton/day pilot-plant unit, includ-
ing an electrothermal gasifier, is scheduled to begin operation this
year.
CO? Acceptor Process (Consolidation Coal Company). Heat is supplied
to the reacting coal by circulating bed of heated dolomite (MgO'CaO).
The latter is reheated in a separate vessel by burning char with air.
The process required neither oxygen nor hydrogen. However, the
375
-------
maximum temperature that can be used in the gasificr is limited to
about 1600 F to avoid melting the circulating calcine. Operating
pressures range from 150 to 300 psi. Under these conditions, the
reaction rate of steam with bituminous coals is very low and the only
satisfactory raw materials are lignites and some subbituminous coals.
However, it is expected that further developments will permit the
process to be adapted to higher grades of coal.
The lignite is ground, dried, and introduced into a fluidized-bed de-
volatilizer. Here it is reacted with a stream of gases rising from the
gasifier, and with a portion of the calcined dolomite. The dolomite
reacts with carbon dioxide, forming calcium carbonate. This reaction
Is exothermic, liberating heat for the carbon-steam reaction. The
dolomite also absorbs sulfur compounds. Spent dolomite is returned
to the generator'and char is conveyed to the gasifier.
Additional amounts of calcined dolomite, and steam, are introduced in-
to the fluidized-bed gasifier. Carbon reacts with steam, forming
hydrogen and carbon monoxide. Removal of carbon dioxide promotes the
water-gas shift reaction. Gases leave the top of the gasifier and
enter the devolatilizer. Spent dolomite and unreacted char are con-
veyed to a fluidized-bed regenerator. Unreacted char is burned with
air at about 1950 F, calcining the dolomite to restart the cycle. t
Gas leaving the devolatilizer may contain about 20 percent CH^ (dry
basis). The procedure for converting this gas to high Btu gas has
been described previously. However, in this process, the ratio of
carbon to hydrogen may be such that the shift conversion step can
be omitted. Bench-scale tests have been completed, and operations
have started in a 30-ton/day gasification pilot-plant.
Emissions
Coal gasification, whether to produce a high or low Btu gas, results
In a wide variety of process emissions. The exact nature of these
waste streams will depend on the basis unit operation of the process.
For each of the four processes considered in this program, material
balances were made and emissions factors estimated. The environmental
emissions are summarized in the module data sheets in Appendix A of
this report. The qualitative types of emissions to be expected from
coal gasification processes are shewn in Table Q-l.
Air
In the production of both high and low Btu gas, air emissions include
sulfur, mainly as S02» emanating from Glaus plant tail gases. Since
the production of low Btu gas involves the direct combustion in a
boiler at the same site, power plant flue gas is also emitted. In
most gasification processes (both low and high Btu product gas), C0£
376
-------
TABLE
ENVIRONMZMTAL EMISSIONS ARISING FROM COAL GASIFICATION PROCESSES
Process Module
Lurgi process & con-
ventional boiler
Two-stage coal cca-
bustion & conven-
tional boiler
HYGAS
CO. acceptor process
1.
2.
1.
2.
3.
1.
2.
1.
2.
Emissions
Solid
Air Mater Waste
Claus plant tail gas Minimal Slag
Power plant flue gas
Power plant flue gas Kaste waters Slag
Carbon dioxide
Claus plant tall gas
Claus plant tail gas Waste waters 1. Ash
CO- 2. Gypsum sludge
Gaseous sulfur compounds Kaste waters Mixed solids
(S02, H2S and S)
a. Claus plant tail gas
b. Lignite drying step
co2
Othar
(By-Products)
Elemental sulfur
Iron
Elemental sulfur
Elemental .sulfur
Elemental sulfur
(a) Arises from removal of SO. and Claus tall gas treatment*
(b) Ash plus unburned char plus spent acceptor rollds.
-------
I
is also emitted. In general, the higher the Btu content the greater
the amount of C02 emitted.
Water
Coal gasification processes are liberal users of water, both as a raw
material in the process for its hydrogen content and also as a process
fluid. The higher the Btu quality of the gas, the larger the water re-
quirements per unit of product. In most coal gasification processes,
waste waters are also generated and must be treated. *
Solid Waste
Coal gasification processes give rise to large quantities of solid
wastes. They arise mainly due to the ash content of the coal, but also
from processing to achieve sulfur removal. Typical solid waste streams
(see Table Q-l) include slags (both Lurgi and Two-Stage Combustion
Processes), ash (Hygac process), gypsum sludges (Hygas process), and
mixed solids (C02 Acceptor process). In addition all produce elemental
sulfur which, if it cannot be sold to the chemical industry, may be con-
sidered a solid waste.
Land Use
-------
alternative to flue gas cleaning, solvent refining, chemical cleaning,
coal washing, fuel switching, etc. to meet emission regulations.
In most processes, aqueous waste waters are treated using conventional
technology, i.e., biological oxidation,, gravity separation, and a wide
variety of physical chemical unit operations (ion exchange, reverse
osmosis, adsorption, filtration, chlorination, etc.). No one techni-
que or method is universally employed.
The ash in the coal is usually removed in front-end processing equip-
ment. For example, in the Lurgi process it is removed off the bottom
of the gasifier, while in the CC^-Acceptor process it is removed along
with unhurried char and spent acceptor (reacted dolomite) from the
acceptor-stripper unit just downstream from the gasifier.
Sulfur is removed from the coal in coal gasification processes using a
wide variety of technology. Most often it is volatilized under reducing
conditions to form H?S, scrubbed from the fuel gas, stripped from the
absorption liquor as a concentrated H2S stream, and converted to sulfur
using Glaus plant technology. If necessary, a Glaus plant tail gas
treatment process is also provided. The volatilization process usually
occurs in the gasifier per se with the sulfur appearing in the off-gas
principally as ^S along with small quantities of COS and C$2. The
fuel gas scrubbing and stripping steps to remove and concentrate these
sulfur compounds (mainly t^S) is accomplished by any one of a vast
array of processes: (1) amine scrubbing systems, (2) hot potassium
carbonate process, (3) sulfinal process (Shell Oil Company), (4) sea-
board and vacuum carbonate processes (Koppers Company), (5) the
phosphate process (Shell Development Company), (6) v;et iron box process,
(7) the Thylox process, (8) hot-ferric oxide process, and (9) dolomite
acceptor process to name a few. The concentrated I^S stream is usually
then sent to a Glaus plant.
In the Glaus process, l^S is combusted under precisely controlled con-
dition so that one-third of it is converted to SC^. The cooled com-
bustion products are catalytically reacted to form elemental sulfur
according to the following equation.
cat
2H2S + S02 ss 3S + 2H20
after which the sulfur is condensed and separated. However, recovery
is not complete even with three converters, and as much as 5 percent of
the entering sulfur is contained in the exit (tail) gas. Recently
developed tail gas treating technology, e.g., the Beavon, Cleanair,
and IFF processes, achieves recovery of almost all of the remainder.
Consequently sulfur removal of 99.5 to 99.9 percent is achieved on the
incoming H2S.
379
-------
Effcctivonoss and Cost
The cost to utilities of achieving pollution control through the sub-
stitution of clean fuel gas '(either low or high Btu gas) will depend on
the price at which the fuel gas is available locally relative to that
of other fuels. Process Research Incorporated'^ ' estimated coal gas-
ification costs (process conversion costs) in c/106 Btu for the Two-
Stage Combustion, CO^ Acceptor, and Hygas processes. These process
conversion costs do not include the price of coal or inathe case of high
Btu gas, transportation costs. Economic evaluations were based on the
following standard American Gas Association accounting procedures which
were adopted by the Office of Coal Research as standard:
20-year plant life
Straight line depreciation
9 percent gross return on rate base
Financing - 65 percent debt - 35 percent equity
Interest rate - 7.5 percent
Federal income tax - 48 percent.
Also, Robson et al. ^" ' estimated the performance and economics of a
plant producing fuel gas for a 1000 MW low pressure plant with a 70 per-
cent operating factor. The major capital cash areas were gasification -
45 percent, air compression - 20 percent, coal handling and preparation
(mainly briquetting) 11 percent, and general facilities - 9 percent.
Additional items make up approximately 15 percent of the capital costs.
The results of both studies arc summarized in Table Q-2.
As seen in Table Q-2, plant costs for the low Btu gas processes range
from about 20 to 46 million dollars or between $20 to $48 per kw if the
gasification plant is owned by the utility. Pollution control costs
range from under lc to about 29C/10 Btu (output). The lower value for
the conversion costs («lc/10^ Btu) is for the two-stage combustion
process and takes into account by-product credits for slag, iron, and
sulfur. It should be pointed out that, to date, only prototype com-
bustor studies and laboratory bench-scale studies have been performed.
Due to the small size of the experimental equipment, and lack of pilot-
scale studies, these low estimates are viewed with considerable
skepticism.
The cost of coal is not included in the above estimates because it varies
from one plant location to another. The total product selling price at
the plant can be developed by adding to the above prices the cost of
coal in cents per million Btu multiplied by a factor 1.01E where (E) is
the efficiency of the gasification process.
For high Btu gas, plant costs range from $124.9 to 209 million for a
250 x 105 scfd plant (1,000 MU) or between $117 and 197/kw. Conversion
costs range from 35 to 50c/10^ Btu. Again the cost of coal was not in-
cluded. These estimates would appear to be quite optimistic. Bresler
and Ireland(Q'l) provide "ballpark" cost estimates between about $0.60
380
-------
TABLE Q-2. ESTIMATED COM. GASIFICATION PROCESS ECONOMICS*
Process
Lurgi
Two-Stage
Combustion
CO.-Acceptor
HYGAS
Reference
G2
G3
G3
G3
Product
Gas
Low Btu
Low Btu
High Btu
High Btu
Gener-
ation
1st
3rd
2nd
2nd
Plant S
HW lo'
965
1000
1060
1060
Ite
Btu/day
228
234
250
250
Plant
KM $
46.3
20.3
124.5
209
Cost
$/kW
48
20.3
117
197
Conversion Cost
20 yr. Depre.
28.6
0.44
35.5
50
k* C/XM Btu
5 yr. Depre.
~
3.7
58.5
87
(a) Does not Include cost of fuel.
(b) Depreciation period not known.
-------
to $1.00 per million Btu (not including the cost of coal). Also Battclle
has recently been engaged in a detailed design study of a coal gasifica-
tion plant to be located in the western United States. Conversion costs
in this study averaged about1 $1.00/10 Btu. In any case, it would
appear doubtful whether high Btu gas, as envisioned by processes cur-
rently being developed, will be used for power plant fuel. It will, in
all probability, find its place as a supplier of SNG for home space
heating and industrial application.
References
Q-l. Breslcr, S. A., and Ireland, J. D., "Substitute Natural Gas:
Processes, Equipment, Costs", Chemical Eng., pp. 94-108
(October 16, 1972).
Q-2. Robson, F. L., et al., "Technological and Economic Feasibility
of Advanced Power Cycles and Methods of Producing Nonpolluting
Fuels for Utility Power Stations", Report No. PB-198-392
(December, 1970).
Q-3. Process Research Incorporated, "Evaluation of Fuel Treatment and
Conversion Processes", report prepared for Environmental Protection
Agency, Office of Air Programs, Contracts No. 68-02-0242 and CPA
70-1 (July 7, 1972).
Q-4. Annual Report, Office of Coal Research, 1972.
382
-------
APPENDIX R
GENERATION OF ELECTRICITY
Table of Contents
Page
Environmental Emissions in the Generation of Electricity 384
References .*.... 392
List of Tables
R-l. Energy Sources Used by Electric Utilities 384
R-2. Emission of Sulfur Dioxide from Conventional Fuel-fired
Power Plants 386
R-3. Emission of Nitrogen Oxides from Large Boiler Furnaces. . . 387
R-4. Emission of Particulate Matter from Coal-Fired
Boiler Furnaces 389
383
-------
APPENDIX R
GENERATION OF ELECTRICITY
Environmental Emissions in the Generation of Electricity
A
Energy Sources for Generating Electricity
Presently, generation of electricty in the United States amounts roughly
to 35 x 109 kwhr weekly, with the probable total generation for 3972 ex-
pected to be about 1.7 x 1012 kwhr. Approximately one-fifth of this will
come from hydropouer, with the remainder from fossil-fuel-fired generating •
plants. Of these, steam-generating units predominate, with a rapidly in-
creasing use of gas turbines at percentage levels well beyond their earlier
application as peak-shaving units.
Table R-l shows that coal has been and will continue to be a major source
of energy for conversion into electricity, ba^ed on a generating capabil-
ity in 1970 of 340,000 MW, in 1980 of 665,000 MH, and in 1990 of 1,260 MW,
representing essentially a doubling time of ten years. The estimate for
coal usage in 1990 is probably quite conservative in that the figures which
were forecast for nuclear energy seem highly optimistic in light of develop-
ments which have occurred since the estimate was made.
TABLE R-l. ENERGY SOURCES USED BY ELECTRIC UTILITIES a
(Equivalent tons of coal based on 25 x 10& Btu/ton)
1970
Source
Coal
Gas
Oil
Nuclear
Total
Tons
300.2
150.1
79.3
15.2
544.8
Percent
55.0
27.6
14.6
2.8
100.0
1980
Tons
472.0
162.3
136.4
365.5
1,127.2
Percent
41.9
14.9
12.1
21.6
100.0
1990
Tons
613.6
200.2
145.1
1,176.1
2^135.0
Percent
28.7
9.4
6.8
55.1
100.0
(a) Federal Power Commission
Since 1970, at least along the East Coast, low-sulfur residual fuel oil
has largely displaced coal for central-station power plants, simply be-
cause low-sulfur fuel oil has been made available as needed. One large
midwest utility has been shipping large quantities of low-sulfur coal from
the western states. But, at least, for the time being, the extraordinar-
ily large reserves of coal in North Dakota, Montana, Wyoming, Colorado,
384
-------
and Utah with less than one percent sulfur are considered unavilable to
the major utilities east of the Mississippi River.
Although, as shown in Table R-l, the percentage of electricity generated
from coal is expected by the Federal Power Commission to decrease mark-
edly over the next two decades, the tonnage requirements will increase
about 60 percent between 1970 and 1980, and another 30 percent between
1980 and 1990. If obtained from eastern coal fields, this coal will
contain what is now considered to be excessive amounts of sulfur; on a
weighted basis, judged from past experience, the average "sulfur content
over the next few years can be assumed to be 2.2 percent.
With natural gas, the present critical supply situation casts considerable
doubt on any expanded use of natural gas for generating electricity, either
in conventional steara plants or in gas turbines or combined-cycle plants.
Hence, the estimates of increased use of natural gas shown in Table R-l
are probably unrealistic. Unless some radical change occurs to increase
the availability of natural gas, not foreseen now, it can be assumed that
this sulfur-free source of energy will not play a significant role in the
generation of electricity beyond the next few years. Imported liquified
natural gas, synthetic natural gas from coal, and pipeline gas from the
North Slope of Alaska will be priced at $1 per million Btu or more, making
them unattractive as energy for electricity generation. Fuel now contri-
butes about half the cost of electricity at the station's bus bars, so
that increasing prices for fuel will have a large effect on the price of
electricity.
Nuclear generation is important here only because it may partly replace
the use of fossil-fuels, and hence, decrease the environmental emission
of conventional power plants. As stated earlier, the tremendous growth
of the nuclear industry shown in Table R-l is probably highly optimistic.
Delays in the construction of nuclear power plants, technical problems
such as emergency core cooling, and public concern about siting of nuclear
stations are all contributing to unexpected delays in availability. There-
fore the future use of fossil-fuels, mainly coal and fuel oil, certainly
will be no less than is shown in Table R-l.
Energywise, then, coal will continue to supply the greater part of our
electricity until 1990. Some plants will probably burn low sulfur coal
and other coal-burning plants will employ stack gas cleaning. Natural gas
will be limited for generating electricity, probably being reserved for
residential heating and industrial and commercial uses for which gas is
uniquely suited. Fuel oil, with a sulfur content as low as 0.5 percent,
will be used widely on the Eastern Seaborad within the limits set by im-
port quotas and the construction of desulfurizing plants.
Conventional Power Plants
As operated today, central-station power plants have no control over SC>2
emission other than by selection of fuels. Likewise, NOx is uncontrolled.
Particulate matter alone can be removed from stack gases by well-developed
385
-------
techniques with collection efficiencies up to 99 percent, but the
electrostatic prccipitators required for such good performance fail with
low-sulfur coal because the electrical resistivity of the fly ash then
becomes excessively high. Under such conditions, collection efficiency
may be no higher than 50 percent. Improved collectors will be needed to
meet regulations which are now being promulgated.
Sulfur Djoxide. Essentially, all the sulfur in fuels leaves the stack as
sulfur oxides. In the case of some coals containing appreciable amounts
of limestone or dolomite as mineral matter, as much as 5 percent of the
sulfur may be captured by the ash but, generally, insignificant amounts
of sulfur are retained in the furnace. Sulfur dioxide is the usual form,
with about 1 percent of the total sulfur in the fuel being emitted as
S03.
Table R-2 shows the amount of S02 emitted per day from a 1000-MW ur.it
operating under base-load conditions \iilh fuels of different sulfur con-
tent. Tiraewise, bituminous coal with 2.2 percent sulfur represents
practice today; bituminous coal in some plants and lignite in others with
an average sulfur content of 1.5 percent may occur in 1980; and complete
conversion to lignite with a sulfur content of 0.8 percent or less might
be delayed until 1990. Fuel oil containing only 0.5 percent sulfur is
available in limited quantities today. It is not likely that much oil
with a lower sulfur content will be available in the future, though some
which is 0.3 percent or less is now being burned on the East coast.
TABLE R-2. EMISSION OF SULFUR DIOXIDE FROM CONVENTIONAL
FUEL-FIRED POWER PLANTS
Fuel
Bituminous coal
Sub-Bituminous coal
and lignite
Lignite
Fuel oil
Sulfur,
percent
2.2
1.5
0.8
0.5
Heating Value,
Btu/lb
13000
10000
7000
19500
Emission of S02,
tons/1000 MW day (a)
171
153
117
26
(a) Based on 8500 Btu/kwhr for all fuels.
The most striking point here is that the lower sulfur content of lignite
compared with bituminous coal does indeed decrease the emission of S02,
but the lesser heating value of lignite removes much of the apparent ad-
vantage. Under the conditions assumed here, substituting lignite for
bituminous coal would reduce S02 emission only about one-third. The great
advantage of low-sulfur fuel oil also is strongly evident.
386
-------
It is apparent that the emissions are reduced somewhat by the choice of
solid fuels, but that, short of replacing all forms of coal with low-
sulfur fuel oil—a most unlikely alternative in light of Table R-l—no
very large benefits can be expected. The only other paths open are to
desulfurize flue gases, to devise wholly new methods to remove sulfur
from coal, to convert coals into sulfur-free liquid or gaseous fuels, or
to develop other systems for converting the chemical energy in fuels into
electricity.
Nitrogen Oxides. Nitrogen oxide in flue gas originates from two sources,
the dissociation of. the nitrogen compounds in the fuel and the reaction of
atmospheric nitrogen with oxygen atoms during combustion. Few data are
available as yet on the role played by fuel nitrogen, but there is general
agreement that it cannot be ignored. Combustion-formed NO is more im-
portant. The major factor involved is temperature, the amount of NO
formed increasing rapidly as the temperature rises above about 2400 F.
At temperatures above 3000 F, this fixation reaction proceeds much more
rapidly. A further point is that the rate of dissociation of NO back
into N£ and 02 is much slower than the rate of formation of NO, so that
peak temperature reached is much more important than the cooling rate in
establishing the NO content in stack gas.
Table R-3 summarizes some recently available data on the emission of NO
from large boiler furnaces.
TABLE R-3. EMISSION OF NITROGEN OXIDES FROM LARGE BOILER FURNACES^
Fuel
Coal
Gas
Fuel oil
Average
Boiler Rating,
MW
495
290
257
NO
Full
Load
990
590
360
Emission, ppm
Intermediate
Load
740
420
270
Low
Load
700
280
260
NO
Full
Load
95
31
17
Emission, tons/
1000 MW Day
Intermediate
Load
51
20
10
Low
Load
36
8
6
(a) Bartok, W., Crawford, A. R., and Piegari, G. J., "Systematic Field
Study of NOX Emission Control Methods for Utility Boilers": E.P.A.
Contract CPA 70-90, December 31, 1971, Esso Research and Engineering
Company.
The NO emission data as reported by Esso and calculated as NO are based on
3 percent 02 in dry flue gas. For simplicity, the conversion here from
parts per million to tons NO2 per 1000 MW day assumes 550 ppm as being
equivalent to 1 Ib NO2 per million fitu. Assuming further that the heat
rate is 8500 Btu/kwhr for all three fuels at the three loads listed pro-
387
-------
vides the calculated approximate N02 loadinss in the last three columns
of Table R—3. These simplifying assumptions permit judging the relative
emissions of type of fuel and of load even though the assumptions are an
approximation at best.
Table R-3 shows that the fluid fuels, gas and oil, produce less N02 than
pulverized coal, probably because the combustion of gas or of droplets of
fuel oil results in lower flame temperatures than the burning of solid
particles of coal that go through a devoiatilization step followed by
oxidation of the resultant coke particles. In the boilers surveyed, fuel
oil produced about half as much N02 as natural gas except at low loads
where the two fuels were comparable. The reason for this is not clear.
Emission of N02 drops appreciably as the load in a boiler is less.
Table R-3 shows that at low loads, with all three fuels, the amount of
N02 formed is a half to a fourth as much as at full load for the same
amount of electricity generated. The Esso study shows that the uncontrolled
emission of N0? depends nearly linearly on the gross boiler load expressed
as percentage of full load, regardless of the fuel.
Decreased emission of N02 is obtained mainly by lowering flame tempera-
tures. Combustion modifications, such as using low excess air or staged
combustion have been moderately successful with gas firing, in some cases
decreasing NC>2 emission by 80 percent. However, burner design and spacing,
heat transfer in the furnace, and probably other unidentified factors
influence the effectiveness of combustion changes so that N02 control is
still troublesome even with gas firing.
Although fuel oil leads to lower uncontrolled N02 levels than gas, com-
bustion modifications are less effective. Again, the reasons are not
entirely clear, although flame and furnace temperature undoubtedly are
responsible.
Coal, with its more involved combustion process, poses problems with low
excess air or with staged combustion in unburned carbon in the fly ash.
Hence, the control of its already high N02 levels will be much more diffi-
cult with pulverized coal than with gas or fuel oil, although Esso re-
ported few problems in the boilers it tested.
The impact of N02 emission in the future certainly will be lessened by
the use of combustion modifications, but the exact extent is difficult to
forecast now. With coal providing the energy for generating more than half
the electricity used today, most emphasis must go into combustion modifi-
cations that will still permit reasonably low levels of carbon in fly ash.
Particulate Matter. Emission of particulate matter is a serious problem
with pulverized coal-firc.d boiler furnaces, where a major part of the
mineral matter in the coal is carried out of the furnace with the flue gas.
Dry-bottom furnaces which presently make up the largest part of our steam-
generating facilities usually retain less than a fifth of this mineral
matter in the form of wall slag or bottom deposits; the remainder goes
388
-------
through the heat-recovery systems to be captured by mechanical collectors
or electrostatic precipitators, or passes out of the stack. Slag-tap
furnaces, not being made presently, capture as much as 90 percent of more
of the mineral matter in the coal.
Oil-fired boiler furnaces emit small quantities of particulate matter
because of the inorganic matter in residual fuel oil, but the quantity
is generally less than 1 percent than from coal-fired furnaces. Although
the quantity of particulate matter is low with oil firing, visible plumes
are common because of the size range of the particles.
Gas-fired boiler furnaces emit no particulate matter unless combustion
conditions are so bad that thermal cracking of the hydrocarbons produces
carbon particles. This is an extreme condition essentially never occur-
ring in large central-station power plants.
Mechanical collectors remove only particles larger than about 10 microns,
but electrostatic precipicators now being designed have an over-all
collection efficiency of 99 percent even with submicron particles. As
noted earlier, this efficiency cannot be maintained when the fly ash has
an electrical resistivity greater than 10 ohm centimeters, but increas-
ing the operating temperature to 600 F or higher appears likely to solve
this problem.
Table R-4 lists the emission of particulate matter from coal-fired boiler
furnaces of the three common firing systems assuming that 90 percent of
the mineral matter is captured during combustion by the cyclone furnace,
50 percent by the slag-tap furnace, and 20 percent by the dry-bottom
furnace.
TABLE R-4. EMISSION OF PARTICULATE MATTER FROM
COAL-FIRED BOILER FURNACES
(10-percent-ash coal; 8500 Btu/kHh)
Emission from Stack. tons/1000 MW dav
50 Percent Collection 99 Percent Collection
Type of Firing Efficiency Efficiency
Cyclone
Slag Tap
Dry Bottom
40
200
310
0.8
3.9
6.2
Other Pollut.ints. Small amounts of carbon monoxide are emitted by large
boiler furnaces, but the emission levels seldom exceed 100 ppm under
proper operating conditions. With low excess air and with staged com-
389
-------
bustion to control N02 emission, CO may Increase as the limits of satis-
factory combustion are reached. An upper level higher than 1000 ppm is
unlikely. The emission level at 100 ppm CO would be 9 tons per 1000 MW
day. At 1000 ppm, emission,would be 90 tons per 1000 MW day, based on
0.084 pound CO per million Btu input and a heat rate of 8500 Btu/kwhr.
Unburned hydrocarbons from oil- or gas-fired boiler furnaces are negligi-
ble. Similarly, polynuclear aromatic compounds resulting from combus-
tion usually are insignificant because the high temperatures in the
furnace, usually reaching at least 3000 F, dissociate any PNA that may
be formed early in the combustion process. Benzp (o/) pyrene, a typical
compound, probably does not exceed 1 gram per million Btu input in coal-
fired furnaces, equivalent to about 0.2 ton per 1000 MW day.
Thorma1 Ef fGC t s. Large modern steam-generating power plants presently
have reached a plateau in thermal efficiency, no appreciable gains having
been readied over the past five years. This is due largely to operational
problems limiting the steam temperature to 1000 F. By operating at 3500
psi, well above the: critical pressure, and by using a sophisticated reheat
cycle, the best of today's plants achieve a heat rate of about 8500 Btu/
kwhr, equivalent to 40 percent overall thermal efficiency. The remaining
60 percent of the heating value of the fuel appears as sensible heat in the
flue gas and in the condenser cooling water, with roughly 10 percent in
the flue gas and 50 percent in the coolant.
On this basis, 2 x 10 Btu appears in the flue gas and 1 x 1011 Btu
appears in the condenser water for a 1000 MW day. The sensible heat in
the flue gas is necessary to maintain the gas temperature at about 325 F,
high enough to assure a buoyant plume from the top of the stack and to
be above the dew point to minimize stack corrosion. The sensible heat in
the condenser water is dissipated in rivers or other natural bodies of
water, or as is becoming more conmon today, in natural-draft cooling
towers. Roughly, in such towers, 1 x 10 Btu will evaporate 1 x 10 pounds
of water or 12 million gallons of water per day for baseload operations
of a 1000 MW unit, assuming no radiation or convective heat losses.
The magnitude of the total thermal effect on the environment can be com-
pared with solar radiation, supplying approximately 350 Btu per hour per
square foot. On this basis, assuming 8 hours of sunshine per day, 46
million square feet of surface will receive the same energy normal to the
sun as must be dissipated from a 1000 MW plant over 24 hours. At 40 de-
grees North latitude and at the equinoxes, this becomes 70 million square
feet of actual sunshine-receiving surface, or about 2.5 square miles. It
is evident that, although a dissipation of 1.2 x 10 Btu in 24 hours is a
large amount of energy, its impact is relatively minor compared with solar
radiation.
390
-------
Combined Cycle
There are many possible "combined cycles" being considered for updated
power plants, including combinations of various combustors and heat
recovery systems. Most consideration presently is being given to
pressurized boiler furnaces combined with gas-turbine sets. In a typical
system, the gas turbine provides the energy to compress combustion air
for the furnacn to, perhaps, 100 psi. The furnace, in which the fuel is
burned, converts a part of the thermal energy to steam sent to a steam
turbine, and then expands the hot gases in a gas turbine where additional
electricity is generated. Alternatively, combustion may occur in the
gas turbine, with a waste-heat boiler to extract thermal energy from the
gas turbines exhaust. Other cycles are possible, including the injection
of steam into the gas turbine to increase overall cycle efficiency. The
principle advantage of combined cycles is an appreciably higher thermal
efficiency than is possible with conventional systems. Whereas the usual
system with steam at 1000 F and 3500 psi has an overall heat rate as low
as 8500 Btu/kwhr or 40 percent, a combined cycle may achieve 6800 Btu/kwhr
for an overall efficiency of 50 percent.
The impact of a combined cycle on the environment cannot be assessed until
the cycle details are decided. The effect of pressurized combustion on
emission of NO? is uncertain, but, based on data for gas turbines, N02
emission under most conditions of take-off in aircraft engines does not
exceed about 5 pounds per 1000 pounds of fuel burned(R~l) equivalent to
25 tons of N02 per 1000 MW day. It is probable that this level would not
be exceeded in a combined cycle, where the pressurized furnace essentially
would be replacing the conventional gas-turbine combustion.
Of necessity, a combined cycle will require a conditioned fuel essentially
free of ash and very low in sulfur. Dirty fuels will cause serious oper-
ational problems with the gas turbine, and although it is possible
eventually that the pressurized boiler furnace preceding the gas-turbine
expander might be fired with a "dirty" fuel, and remove ash and sulfur
contaminants before-the hot products of combustion pass to the gas tur-
bine, such a system has not been devised as yet.
Unburned hydrocarbons and CO are present in small quantities in gas-tur-
bine exhaust, but their impact will be small in a combined cycle. Assum-
ing again that the pressurized boiler furnace simply replaces the conven-
tional gas-turbine combustor "can", and based on cruise conditions in
aircraft where the emission of HC is only 6 pounds per 100,000 pounds of
fuel, the emission of HC from a combined cycle might be no more than 600
pounds per 1000 MW day. Carbon monoxide emission during cruise is about
1 pound per 1000 pounds of fuel, equivalent here to 5 tons of CO per 1000
MW day.
391
-------
R-l. Combustion Planning Study, 1971, p VI-5.
392
-------
APPENDIX S
STACK GAS CLEANING
Table of Contents
Page
Summary 394
Technology 394
Environmental Emissions 397
Pollution Controls 407
Areas of Uncertainty 409
References 410
List of Tables
S-l. Estimated Emissions from Stack Gas Cleaning Processes. . . 404
S-2. Operating Cost-Sensitivity Analysis for Wet Limestone
Scrubbing 408
List of Figures
S-l. Technologies for the Removal of S02 from Stack Gas .... 395
S-2. Wet Limestone Scrubbing ' 398
S-3. MgO Scrubbing with l^SO^ Recovery 399
S-4. Ammonia Scrubbing with Sulfur Recovery 400
393
-------
APPENDIX S
STACK GAS CLEANING
_Sii'imary.
Well over 50 individual processes for removing S02 from stack gas have
been identified, A number of processes have been applied successfully
to control smaller industrial sources including oil fired boilers. Tech"
nology which has been developed through the joint efforts of industry
and EPA over the past fcv; years is now being reduced to sound engineering
practice. Typical of the throvava> processes is wet limestone scrubbing
and typical at the recovery processes are ligO scrubbing with l^SO^ pro-
duction and alkali scrubbing (sodium or ammonium salts) with sulfur
production. The removal efficiencies for SC-2, NOX, and fly ash are
assumed to be linear functions of time during the period 1975 to 1990
with a range of 75 to 90 percent for SC>2, 0 to 20 percent for NOX, and
99 to 99.5 percent for fly ash. Air, water, and solid waste emissions
for the typical processes have been estimated by means of material bal-
ances and a knowledge of the process flowsheets with the aid of judicious
assumptions when necessary. Emissions were estimated for a typical
eastern coal, a typical western coal, and a typical fuel oil for 1975 and
1990. Stack gas cleaning processes for power plant application are esti-
mated to cost an average of 2.4 mills/kwhr (24.6 cents/10^ Btu, for heat
to electricity efficiency of 35 percent) with a range of 1.1 to 7.7 mills/
kwhr (11.3 to 79.0 cents/10" Btu) depending upon the specific case under
consideration. Stack gas cleaning will provide the only means for re-
ducing emission from the 30 to 50 percent of the existing coal and oil
fired plants where low sulfur fuels will net be available. This discus-
sion is predicated on many assumptions and, therefore, must be considered
as a "rough cut" at the problem rather than a definitive analysis.
Technology
The various technologies being developed for S02 removal from stack gas are
summarized in Figure S-l. This figure was developed from information pre-
sented by Slack,(S~l) One of the major divisions in the technologies is
between recovery of the S02 in useful form and formation of a product
intended for discard as a solid waste; both the recovery and throwaway
methods can be carried out in either wet or dry systems. The throwaway
methods convert an air pollution problem to a solid waste while the
recovery methods would require an electric utility or some selected agent
to market a chemical product.
394
-------
INAHCOUTC]
I imtenaiil
uiMtcrt I l«iy
_L
\tssaivra» muwas]
ljOSQ.1
AU'CNIAl I SCDIUU I iMIUSVi
ICOMWUI.G:
[ALMUNC CMTM)
I *C50"!KKT» I
VO
Ul
M I |VCML|
0>IOCS| | »OLB5|
I
bCCCNCUTKMl |°CCCI.rRAncJ hcjC
I »r nt«TiNO | | at wjSHiHS I IBTH
""
|nuptR«runi|
FIGURE S-l. TECHNOLOGIES TOR THE REMOVAL OF 502 FROM STACK GAS
-------
The various technologies for SOn removal outlined in Figure S-l can be
subdivided into more than 50 in individual processes. However, processes
which are most likely to be commercially applied in the near future must
meet the following criteria:
1. Technical feasibility
2. Advanced stale of development
3. Utility company acceptance
A. Marketable end product (recovery processes)
5. Possibility of solving process problems.
The list of veil-developed processes that have gained some degree of utility
company acceptance in the United States is as follows:
1. Wet lime/limestone scrubbing
2. Double alkali scrubbing
3. WeiIman-Lord process
4. Stone & Webster/Ionics process
5. MgO scrubbing
6. Monsanto Cat-Ox process.
All of the processes have evolved from joint efforts by government and
industry. EPA has provided some support for all of the process, mainly
in the demonstration stage. The EPA has given financial assistance to
full-scale demonstration plants of the Wellman-Lord process at Northern
Indiana Public Service Company's Mitchell station, the Stone & Webster/
Ionics process at a Wisconsin Electric Paver Company station in Milwaukee,
the Chemico-Basic MgO scrubbing process at Boston Edison's Mystic station,
the Monsanto Cet-Ox process at Illinois Power's Wood River station, and
wet limestone scrubbing for the City of Key West. The latter three plants
ate currently in operation. In addition, the EPA is funding an extensive
pilot-plant study of a wet/Limestone scrub unit at TVA's Shnwnee sta-
tion where it had funded an earlier study on dry limestone injection.
It has recently been announced that the EPA is going to fund a pilot-
plant study of the double alkali process at Nevada Power Company's pilot
plant.
Ammonia scrubbing should be added to the list because of its interchange-
ability with sodium compounds in wet scrubbing and because of favorable
scrubbing experience in other countries. Ammonia scrubbing is similar to
the Wellman-Lord process except that the cation in the scrubbing liquor
is NH4+ rather than Na+. In order to narrow the scope of this study to
396
-------
manageable proportions, the list of seven stack gas cleaning processes
has been divided into three categories and one typical process has been
chosen to represent each category for further analysis. These categories
and processes are as follows;
1. Throwaway-wet limestone scrubbing
2. Recovery of I^SO^ - MgO scrubbing
3. Recovery of sulfur-ammonia scrubbing.
The throwaway processes are likely to be applied before the recovery
processes because of the reluctance of the utility industry to enter the
chemical business. The most advanced throwaway process, wet limestone
scrubbing, has an S02 removal efficiency of about 75 percent(S-2)} v;hile
the mast advanced recovery process. KgO scrubbing, has an S02 removal
efficiency of about 90 percent(s~3). Therefore, it seems reasonable to
assume an efficiency of 75 percent for S02 removal in 1975 and 90 percent
in 1990 with a linear increase in removal efficiency with time. None of
the well-developed stack gas cleaning processes have given any indication
of removing NOv from stack gas; however, it is conceivable that some NOX
removal in 1975 and 20 percent in 1990 with a linear increase in removal
efficiency with time. However, it must be recognized that more signifi-
cant reductions in NOX emissions will probably be attained through combus-
tion modifications. The proposed state regulations on fly ash removal
coupled with existing technology dictate an efficiency of 99.0 percent
for fly a«sh removal in 1975 and 99.5 percent in 1990 with a linear in-
crease in removal efficiency with time.
Environmental Emissions
Process Flowsheets
The best method for assessing the environmental emissions of stack gas
cleaning processes is to determine the emissions by means of a material
balance. Typical flowsheets for the three processes under consideration
were adapted from the work of the M. W. Kellog Company^8"7), from the TVA
report on wet limestone scrubbing^"'), and from a recent EPA report(S-8)f
and are shown in Figures S-2, S-3, and S-4. In addition to the flow-
sheets--a knowledge of the process chemistry is needed to perform a
material balance.
Process Chemistry for Vet Limestone Scrubbing
Very little in the way of chemical and kinetic data has been reported on
the limestone-wet scrubbing system. However, work in the area has re-
cently been accelerated under EPA contracts. Data are available in the
literature on the system CaO-S02~H20 but these are not considered
applicable because of the absence of carbon dioxide. One of the major
questions is the nature of the calcium compound that actually reacts
397
-------
09
Camper > v (tamper
y~V Pump Pump Pump Pump
FIGURE S-2.
LIMESTONE SCRUBBING
-------
*
SotWOtOr
B
Spicy
io»er
C
Twuferl
Settling pond
Tronifer
pump
Slock
reneo'er
FF
-/"~\
A___
pump i
.Pro:
1 wott
1
tbil 40* Hzs°4
p'onl
EE
Transfer
pump
Trcnsftr
pump
FIGURE S-3.
MgO SCRUBBING WITH
RECOVERY
-------
o
o
FIGURE S-A. AKHOSIA SCRU33IKG WITH SULFUR RECOVERY
-------
with the S02, which obviously is important in regard to rcactant utili-
zation and process equipment requirements. Pearson et al(S~°) state that
the effective reactant is calcium bicarbonate formed by reaction of
calcium carbonate with dissolved carbon dioxide and postulate the
following reactions:
CaC03 + C02 + 112° •*• Ca(HC03)2 (S-l)
Ca(HC03)2 + S02 + H20 -*• CaS03'2H20* + 2C02t .(S-2)
CaS03-2H20 + 1/2 02 -»• CaS04 2H20* (S-3)
Oxidation of sulfite is another phase of the process chemistry that also
is not well understood. It has been generally considered that oxidation
is desirable because if the sulfite is allowed to escape into watercourses
it will gradually oxidize there and reduce the oxygen content of the water.
Moreover, there is some evidence that oxidation to sulfate is desirable
for the prevention of scaling. However, the effect of oxidation on
scrubbing efficiency is not known. Several investigators have found the
scrubber effluent to contain equal amounts of sulfite and sulfate.
Assuming 50 percent oxidation, the overall scrubber reaction per mole of
S02 is then the sum of Equations S-l and S-2 plus 50 percent of Equation
S-3, or
CaC03 + 2H20 + S02 + 1/4 02 -»• 1/2
+ 1/2 CaS0'2HOI + C0* (S-4)
Process Chemistry for MgO Scrubbing
with H?SOA Recovery
Slaked MgO reacts with S02 in the scrubber to form bisulfite and sulfite.
The scrubber is operated at a high enough pH so that all the bisulfite is
converted to sulfite. Part of the sulfite is oxidized to sulfate.
Assuming 20 percent oxidation of the sulfite, the overall scrubbing re-
action is:
, MgO + S02 + 0.1 02 + 6.2 H20 -*- 0.8 MgS03«6H20+
+0.2 MgS04-7H20* ' (S-5)
The presence of sulfate in the recovery system is undesirable since an
additional treatment is required to reduce the sulfate to sulfite.
The calcination process converts dehydrated magnesium sulfite to sulfur
dioxide gas and makes active magnesium oxide for recycle. The dehydrated
solids fed to the calciner contain magnesium sulfate which is reduced with
coke to sulfite. The overall calcinator reaction is:
401
-------
0.8 MgS03 +0.2 MgS04 + 0.1 C •*• MgO + S02+ + 0.1 C02t (S.6)
In the contact sulfuric acid plant, S02 is oxidized to 803 over a catalyst
and the S03 is absorbed in water:
S02 + 1/2 02 - ; - > SO, (S-7)
* * catalyst J
S03 + H20 -f H2S04 (S-8)
The overall process reaction can be determined by adding Equations S-5
through S-8 to yield
S02 + 0.6 02 + 0.1 C + H20 + H2S04 + 0.1 C02t (S-9)
Process Chemistry for Ammonia Scrubbing with Sulfur Recovery
The reactions that occur in the scrubber are very similar to those that
occur in MgO scrubbing. Assuming that 75 percent of the bisulfite reacts
to form sulfite and that 20 percent of the sulfite oxidizes to form sul-
fate, the overall scrubber reaction is:
1.75 NH3 + S02 + H20 + 0.075 02 -»• 0.25 N
•f 0.6 (NH4)2S03 + 0.15 (NH4)2S04 (S-10)
The formation of sulfate in the scrubber is undesirable since it must be
purged from the recovery system in a way that leads to a loss of product.
The combined acidifier-stripper reaction is:
0.6 (NHA)2S03 +0.25 NH4HS03 + 1.45 NH4HS04 -»•
1.45 (NK4)2S04 +0.85 S02t +0.85 H20t (S-ll)
The decomposition reaction which takes place in the electric furnace is:
1.45 (NH4)2S04 j^> 1.45 NH3 + 1.45 NH4HS04 (S-12)
The following reaction takes place in the sulfate reactor:
0.15 (NH4)2S04 + 0.15 CaC03 + 0.15 H20 -»• 0.15 CaS04 2H20+
0.15 C02t + 0.30 NH3t (S-13)
In the modified Glaus plant, S02 is catalytically reduced to sulfur by
natural gas (methane):
2S02 1- CH4 -i- 2H20 + C02 + 2S
402
-------
Side products of the reduction process are carbonyl sulfide and hydrogen
sulfide which are made to catalytically react v;ith 802 to Produce sulfur:
2COS + S02 •*• 2C02 + 3S (S-15)
- •
2H2S + S02 •» 2H20 + 3S (
The overall process reaction can be determined by adding Equations S-10
through S-14, after multiplying Equation S-14 by 0.425, to yield
S02 + 0.075 02 + 0.15 CaC03 + 0.425 CH^ •»• 0.85 S
. +0.15 CaS04'2H20+ + 0.575 C02t +0.55 H20 C
Emissions on a Unit Basis
In order to determine the process emissions on a unit basis, arbitrarily
chosen as 10 Btu of input to the boiler, it is necessary to define the
type of fuel burned and to make certain assumptions regarding the process.
Emissions were tabulated for two types of coal, eastern and western, and
one type of fuel oil with the following typical characteristics:
Eastern Coal Western Coal Fuel Oil
Heating value, Btu/lb 12,000 9,235 18,000
Sulfur content, percent 3.0 0.8 2.9
Ash content, percent 14.4 8.4 0.1
The ash content of the fuel was assumed to end up as 80 percent fly ash
and 20 percent bottom ash, and each process was assumed to operate in the
closed-loop mode with a 1 percent blowdown rate. The recovery processes
were assumed to have a 5 percent loss of regenerated reactants, and in
the reduction of S02 to form sulfur, each of the side products was assumed
to be emitted on the basis of 1 mole percent of the S02 entering the
modified Claus plant.
The air, water, and solid waste or by-product discharges are summarized for
the three stack gas cleaning processes under consideration in Table S-l.
This table includes emissions for the years 1975 and 1990 for plants
burning eastern coal, western coal, or fuel oil. NOX discharge and total
organic discharges were estimated on the basis of generalized emission fac-
tors for pulverized coal and oil-fired boilers compiled by the EPA^8"^)
The remaining air emissions, as well as the solid waste and by-product
emissions, were estimated from a material balance and the chemical stoichi-
oraetry of each process. The water emissions were estimated from solubility
data and a knowledge of the process flowsheets assuming closed loop oper-
ation with a 1 percent blowdown rate and typical impurity levels in the
process reactants.
403
-------
TABLE S-l. ESTIMATED £MISSIONS,FROM STACK GAS CLEANING PROCESSES
-------
TABIE S-l. (CONTINUED)
M?,0 Scrubbing with H^SO/. Recovery
Eastern Coal
Emission
Air Discharges
Fly ash'8'
SO * '
KO (O
ToEal Organic Material
CO (0
9
KM,
COS
H2S
Water Discharges
soj-
Dissolved solids
Suspended solids
COD , ppra
P»
Solid Waste and By-Products
Ash (flyash and bottom ash)
CaSO. sludge
V.gO tailings
11, SO,.
1975
0.0964
1.25
0.753
0.0128
0.259
-
-
•
minimal .
1.84 x 10 *
5.06 x 10~4
minimal
minimal
6-9(O
11.9
-
0.117
5i87
1990
0.0482
0.500
0.601
0.0128
0.311
-
-
-
minimal «
2.21 x 10
6.07 x 10"4'
minimal
minimal
6-9(0
11.9
-
0.141
7.04
Western Coal
1975
0.0730
0.436
0.980
0.0166
0.0891
-
-
•
minimal -
6.33 x 10"*
1.74 x 10"4
minimal
minlnal
6-9?O
9.. 03
-
0.0404
2.03
1990
0.0365
0.174
0.784
0.0166
0.107
-
-
•
minimal -
7.64 x 10**
2.09 x 10"4
minimal
mirtliral
6-9(O
9.03
-
0.0487
2.42
Fuel
1975
_A
4.46 x 10 *
0.810
0.734
0.0419
0.167
-
-
•
minimal •.
. 1.19 x 10
3.27 x 10"4 .
minimal
minimal
6-9(0
0.0559
-
0.0756
3.79
Oil
1990
2.23 x 10"4
0.324
0.586
0.0419
0.201
-
-
~
minimal .
1.43 x 10**
3.92 x 10"4
minimal
minimal
0.0561
- .
0.0913
4.55
Sulfur
-------
TABLE S-l» (CONTINUED)
*>
o
Aimonia Scrubbing with Sulfur Recovery
Emission
Air Discharges
Flyash
SO <°<
K02
To^a I organic material
Ml-
COS
v
Water Discharges
Dissolved solids
Suspended solids
COD, ppm
pit
Solid Waste and By-Products
Ash (flyash and bottom ash)
CaSO, sludge
MgO tailings
Sulfur
1975
0.0964
1.25
0.753
0.0128
1.49
0.0875
0.0353
0.0200.
1.38 x 10
6.44 x 10
4.60 x 10
1.10 x 10
low
500
6-9
11.9
1.62
-
1.60
(a) Fly ash removal efficiencies are 99
(b) SO. removal efficiencies
(c) NO removal efficiencies
Eastern Coal
1990
0.0482
0.500
0.601
0.0128
1.79
0.105
0.0424
0.0240
"A 1.66 x 10
~i 7.73 x 10
", 5.52 x 10
"•* 1.32 x 10
low
500
6-9
11.9
1.94
~
1.92
.07. in 1975 and
Western Co.il
1975
0.0730
0.436
0.9SO
0.0166
0.512
0.0301
0.0122
0.00690
"J 4.78 x 10"*
i! 2.23 x 10 ,1
If 1.53 x I0~_l
J 3.80 x 10
low
500
6-9
9.03
0.559
-
0.550
99.5* in 1990.
1990
0.0365
0.174
0.784
0.0166
0.615
0.0361
0.0147
0.00331
5.71 x 10"?
2.66 x 10 5
1.91 x I0"f
4.56 x 10"*
low
500
6-9
9.03
0.670
-
.0.661
Fuel Oil
1975
4.46 x 10
0.810
0.734
0.0419
0.960
0.0564
0.0227
0.0129
8.94 x 10"?
4.16 x 10"?
2.97 x 10"?
7.12 x 10
low
500
6-9
0.0559
1.04
-
1.03
»
1990
2.23 x 10"4
0.324
0.586
0.0419
1.15
0.0675
0.0273
0.0155
1.07 x lO"*
4.99 x 10 ,!
3.56 x 10"?
8.55 x 10
low
500
6-9
0.0561
1.25
-
1.24
are 757. in 1975 and 907. In 1990.
are 07. in
(d) CO*, emitted only as a result of the
1975 and 20% in
1990, not Including
scrubbing process chemistry, which
reductions
is a small
from combustion
fraction of the
modifications.
CO, emitted
from the combustion process.
(e) Some discharge of acid could occur from operation of the acid plant.
-------
Pollution Controls
Methods
To date, full-scale operating experience on stack gas cleaning processes
for coal fired power plants has been rather limited. Union Electric and'
Combustion Engineering have spent over $3,000,000 on a limestone in-
jection-wet scrubbing system for Meramec Unit 2 but have had to abandon
the project because of plugging in the boiler,(^-11) Kansas Power and
Light has installed similar systems on Lawrence Units 4 ahd 5 and, after
making very extensive modifications, has just reached the point where
they are hopeful of successful operation.(S-12) Commonwealth Edison
has installed a limestone wet scrubber on Will County Unit 1 where the
limestone is injected into the scrubber circuit rather than the boiler.(S-5)
Startup occurred in February 1972, and up to September 11, 1972, Scrubber
A had an availability of 32.6 percent' and Scrubber B had an availability
6f 26\6 percent. Scrubbers A and B had a simultaneous availability of
only 8.1 percent. However, when the scrubbers were operating under normal
design conditions, they removed up to 90 percent of the SC^.
Other full-scale stack gas cleaning systems that are presently on line at
utility company boilers are MgO scrubbing at Boston Edison's Mystic
Station Unit 6* ' and the Cat-Ox process at Illinois Power Company's
Wood River Unit 4.(s"1^) The Mystic Station unit has had problems with
materials handling and has been limited to no more than 500 to 600 hours
of operation in the six months since startup, which occurred in April,
1972. The Wood River unit was placed in operation on September 4, 1972,
and information on operating experience is not as yet available.
Cost
The EPA has determined that the gross annualized costs of wet scrubbing
processes for stack gas cleaning vary little with process type and range
from 2.22 to 2.46 mills/kwhr for the base case described by the second
column of Table S-2. These costs do not include credit for the sale of
by-product l^SO^ or sulfur nor debit for the disposal of these materials.
However, the market for these by-products is full of uncertainties and
each case 'has to be examined individually. It is extremely doubtful that
a utility would undertake MgO scrubbing without a guaranteed market for
the by-product acid.
The EPA has performed a sensitivity analysis of wet limestone scrubbing
operating costs which is summarized in Table S-2.'S'14) ^jje most
important factor appears to be the sulfur content of the fuel and the
least important factor appears to be the option of particulate scrubbing;
however, single factors do not reveal the total cost variations. The
combination of all factors at the low level and of all factors at the
high level gives an operating cost variation from 1.1 to 7.7 mills/hwhr.
The costs listed in Table S-2 were calculated from simple capital and
annualized cost equations developed by the EPA.(S~1^) The cost range for
407
-------
TABLE S-2. OPERATING COST-SENSITIVITY.ANALYSIS FOR
WET LIMESTONE SCRUBBINGt5'
o
00
Parameter
Sulfur content
Plant size
Load factor
Indirect costs
Waste disposal
Retrofit factor
Particulate
Base
3.5%
500 MW
60%
70%
$3/ton
1.25
Scrubbing
Cost Range Percentage Variation^
Parameter Range (mills/ Icvhr) Relative to Base Cost
0.7 - 7.0%
1000-100
80 - 40
70% -,140%
1 - 5
1.0 - 1.5
No - Yes
Total variation, combined effect
of low cost levels and high cost levels
1.80
2.20
2.14
2.46
2.16
2.20
2.16
1.08
- 3.19
- 3.44
- 2.97
- 3.08
- 2.76
- 2.72
- 2.46
- 7.66
57
50
34-
25
24
21
12
267
(a) All other parameters are held at base conditions while the parameter^ in question
is varied over its range.
(b) Cost at base case is 2.46 mills/kwhr.
-------
a given parameter was determined by holding all other parameters at base
conditions while the parameter in question was varied over its range.
The appropriate values for each parameter were than used in the EPA cost
equations to determine an operating cost in mills/kwhr for each case.
The sensitivity analysis permits an estimate to be made of the cost of
wet limestone scrubbing on an oil-fired boiler. For this case, the
sulfur content of the fuel is 2.9 percent and there is no need for par-
ticulate scrubbing, with all other factors remaining the -same as the
base case. The result is 2.0 raills/kwhr for an oil-fired boiler as
compared to 2.4 mills/kwhr for an eastern-coal-fired boiler and 1.8 mills/
kwhr for a western-coal-fired boiler. For comparison purposes, the
estimated operative cost for wet limestone scrubbing at Will County is
4.5 mills/kwhr. (S-5) The operating parameters for Will County are a 170
MM unit with particulate scrubbing burning 4 percent sulfur coal at a
capacity factor of 70 percent and a sludge disposal cost of $7 per ton.
Recent statements regarding capital cost illustrate the need to define
the basis for the estimate to avoid confusion. Capital cost for the
limestone scrubbing system at Will County has been estimated to be $96/
lew. Part of this high cost is attributable to difficulties associated
with a difficult retrofit job and overtime paid to meet regulatory
deadlines. Also part is attributable to the cost of a relatively expen-
sive sludge disposal system. The capital cost for the scrubber installa-
tion at Mystic Station (MgO scrubbing) is estimated at $24/kw not including
indirect overhead charges and escalations.(S~4) Also, the scrubber
installation at Mystic Station does not include the cost of a sulfuric
acid plant and associated equipment. Capital cost for the Cat-Ox
process at Wood River is estimated to be $73/kw.(S-13) TVA estimates
indicate a cost of $54 to $63/kw for a proposed wet limestone scrubber at
Widow's Creek which compares with a cost of $49/kw for the same plant
calculated using the EPA capital cost equation.(S-14)
The EPA^S~15' has estimated that the expected application of stack gas
cleaning on the basis of clean fuel availability is 30 to 50 percent of
existing coal and oil-fired capacity. Up to 80 to 90 of the power plants
in the Northeastern United States could install stack gas desulfurization
processes with a cost at or below the premium for the clean fuels if
projected clean fuel costs materialized.
Areas of Uncertainty
The above discussion is predicted on many assumptions and, therefore, must
be considered as a "rough cut" at the problem rather than a definitive
analysis. It may be helpful, at this time, to recapitulate the major
assumptions as follows:
1. Vet limestone, MgO, and ammonia or alkali scrubbing are typical of
stack gas cleaning processes to be applied during 1975 to 1990.
409
-------
2. The removal efficiencies for S02» NO , and fly ash will be linear
functions of time with S02 ranging from 75 to 90 percent removal,
HOX from 0 to 20 percent removal, and fly ash from 99 to 99.5 per-
cent removal, all within the 1972 to 1990 time period.
•
3. The ash content of the fuel ends up as 80 percent fly ash and 20
percent bottom ash.
4. The scrubbing processes will be operated in a closed-loop mode with
a 1 percent blowdown rate.
5. The recovery processes will have a 5 percent loss of regenerated
reactants.
6. Each of the side products in the reduction of 862 to form sulfur will
be emitted at the rate of 1 mole percent of the S02 entering the
sulfur plant.
7. The EPA cost data are reasonably correct.
.- .References
S-l. Slack, A.V., Sulfur Dioxide Removal from Waste Gases. Noyes Data
Corporation, Park Ridge, New Jersey (1971).
S-2. Ar.dc, J., "Hccent Developments in Desulfurization of Fuel Oil and
Waste Gas in Japan", Contract No. CPA 70-1 (1972).
S-3. Cortelyou, C.G., Chem. Eng. Prog. 65., 69 (August 1969).
S-4. Anonymous, "Sulfur Oxide Removal from Power Plant Stack Gas-
Sorption by Limestone or Lime Dry Process", Conceptual Design
and Cost Study No. 1, Tennessee Valley Authority, PB 178 972
(1968).
S-5. Gifford, D.C., "17111 County Unit 1 Limestone Wet Scrubber", pre-
sented at Electric World Technical Conference on Sulfur in Utility
Fuels: The Growing Dilemma, Chicago (October 25-26, 1972).
S-6. Quigley, C. P., "Project Report on MgO Scrubbing at Mystic
Station", presented at Electric World Technical Conference on
Sulfur in Utility Fuels: The Growing Dilemma, Chicago (October
25-26, 1972).
S-7. Sherwood, F. K., and Pigford, R. L., Absorption and Extraction.
McGraw-Hill Book Co., New York (1952), p 368.
S-8. Schroeter, L. q., Sulfur Dioxide. Pergamon Press, New York (1966),
p 86.
410
-------
S-9. Anonymous, "Evaluation of S(>2 Control Process-Task #5 Final
Report", prepared for the Environmental Protection Agency by
the M. W." Kellogg Co., Contract No. CPA 70-68 (October 15,
1971).
S-10. Anonymous, "Sulfur Oxide Removal from Power Plant Stack Gas-Use
of Limestone in Wet Scrubbing Process", Conceptual Cost and De-
sign Study No. 2., Contract No. TV-29233A (1969).
S-ll. Pearson, J. L., Nonhebel, G., and Ulander, P. H. N., J. Inst.
Fuel, VIII (39), 119 (February 1935).
S-12. McGraw, M. J., and Duprey, R. L., "Compilation of Air Polluted
Emission Factors", Preliminary Document, Environmental Protection
Agency, Research Triangle Park, N.C. (April 1971).
S-13. Burchard, J., "Stack Gas Cleaning Systems", presented at Electric
World Technical Conference on Sulfur in Utility Fuels: The
Growing Dilemma, Chicago (October 25-26, 1972).
S-14. Shultz, E. A., "The Cat-Ox Project at Illinois Power", presented
at Electrical World Technical Conference on Sulfur in Utility
Fuels: The Growing Dilemma, Chicago (October 25-26, 1972).
S-15. Burchard, J., "Stack Gas Cleaning Systems", presented at Electric
World Technical Conference on Sulfur in Utility Fuels: The
Growing Dilemma, Chicago (October 25-26, 1972).
-------
APPENDIX T
FLUIDIZED-BED COMBUSTION OF COAL AND OIL
Table of Contents
Introduction 404
Pressurized Fluidized-Bed Combustion 415
Atmospheric Pressure Fluidized-Bed Oil Gasification 417
Environmental Emissions 425
References. .- 425
List of Tables
T-l. Assessment of Fluidized-Bed Oil Gasification/
Desulfurization 423
List of Figures
T-l. Schematic Diagram, Plant Power Cycle 418
T-2. Plot Plan, Steam Generators and Accessory Equipment for
a 300-MW Combined-Cycle Plant 419
T-3. Site Plot Plan, 300-MW Combined-Cycle Plant 42i
T-4. Modes of Operation 424
A13
-------
APPENDIX T
FLUIDIZED-BED COMBUSTION OF COAL AND OIL
Introduction
Fossil fuel consumption is expected to triple in the next 20 years.
Supplies of low sulfur fuel will be inadequate to meet projected demand
so that some other method for controlling sulfur emissions will be needed.
Flue gas cleaning systems will provide part of the pollution control which
will be needed in the years immediately ahead but gas cleaning will be
costly and will add significantly to the cost of power production. In the
1990 to 2000 period, gasification systems which produce cleaned low Btu
gas from coal may find significant amounts of application but it will be
necessary to solve serious technical and economic problems before this can
come to pass. Even if all problems are solved with reasonable success,
neither flue gas cleaning, coal gasification nor any combination of the
two is likely to provide a totally satisfactory means for timely preven-
tion of emissions of all three pollutants (sulfur oxides, nitrogen oxides,
and fly ash) normally associated with fossil fuel combustion. Modified
combustion systems which prevent emissions of these pollutants would
eliminate the need for add-on gas cleaning systems and could in some in-
stances find application in the period when the longer term solutions
such as coal gasification are being perfected. Fluidized-bed combustors
have demonstrated potential for development as systems which could make
this kind of unique contribution to control of pollution in the next 20
years. Because of the attractive antipollution characteristics of
fluidized-bed combustors, what is now the Division of Control Systems (DCS),
Office of Research and Monitoring of the Environmental Protection Agency,
since 1968 has supported work to develop fluidized-bed combustion systems
which would burn coal or residual oil with minimum pollution from sulfur
oxides, nitrogen oxides, and particulates. The DCS program has been con-
ducted by Federal and Nonfederal contractors in the United States and United
Kingdom and work has been in cooperation with workers in other countries.
Results to date have confirmed the potential usefulness of systems which
burn high sulfur fossil fuels in fluidized beds of limestone or dolomite.
Numerous process variations have been studied for both oil and coal com-
bustion and two have been demonstrated to be especially attractive. In
one, coal would be burned in a pressurized boiler in a combined gas-steam
turbine cycle. In the other, residual oil would be burned at atmospheric
pressure in a system which would be retrofitted to existing boilers.
These two variations have been considered in the present study and are
discussed below and in the main body of the report.
414
-------
Pressurized Fluidizcd-Red Combustion
JJatKp, round
present concept of pressurized flui'dizcd-bed combustion of coal has
evnlved from work supported by EPA- DCS and carried out by a number of
oi'Umiir.ations in the United States and England. Westinghouse has used
th° data generated by bench-scale and pilot-plant studies to do design
which indicate that a fluidized-bed system operated at 10 atmos-
in a combined cycle where both gas and steam turbines are used
would offer many significant advantages both as an air pollution control
and as an improved combustion-boiler system. From the standpoint
nu air pollution control system the process offers the following
(a) A high level of S02 control (95 percent) due to:
1. A good limes tone-S02 reaction temperature, sufficiently
low that dead-burning of the sorbent is not such a serious
problem as it sometimes can be in conventional boilers.
2. Good contacting between the sorbent particles and the
combustion gases.
3. longer residence time of the sorbent in the combustion zone
particularly in the case of lime-bed systems.
O1) Reduced NO., emissions (80 percent) because of:
A
1. The relatively low operating temperatures, reducing the
fixation of atmospheric nitrogen.
2. In pressurized systems particularly, the reduction of
NOX in the presence of S0£ and of CO to 50-140 ppm (as
demonstrated by the British Coal Utilization Research
Association).
(c) Potential for reduced particulate emissions (99 percent) especially
fine particulates.
the standpoint of a combustion system, this process offers:
(a) High bed- to- tube heat transfer coefficients within the
bed (50 Btu/hr ft^ F° in a conventional boiler).
(b) High volumetric heat release rates (500,000 Btu/hr per
ft3 of furnace volume, or possibly even higher, compared
to 20,000 Btu/hr/ft3).
(c) Consequently, a smaller boiler with less tube surface (some
415
-------
estimates indicate that a 600 MW atmospheric pressure
fluidized-bed boiler might be 1/2 to 2/3 the size of a
conventional unit). Pressurized operation offers even
further size reductions.
(d) Lower capital costs (10 to 20 percent lower than conven-
tional boilers) and lower power costs (5 to 15 percent
lower).
(e) Possibly higher supercritical steam conditions in utility
fluidized-bed boilers (to perhaps 1200 F, 4000 psig).
(f) Ability to burn poorer grades of fuel more readily than
can conventional boilers.
(g) Reduced ash fouling and high-temperature corrosion as a
result of the lower operating temperatures.
Cost/Benefit
Some preliminary estimates indicate that fluidized-bed power stations will
cost $20 to $50 per kilowatt less than conventional power plants with stack
gas cleaning equipment. The timely development of such plants can produce
savings in new power plant investments of $600,000,000 to $1,500,000,000
per year in 1985 and beyond. The total development cost of the fluidized-
bed combustion system will be approximately $75,000,000. By using
$1,000,000,000 per year as a reasonable estimate of the annual savings in
capital investment resulting from application of the system, the cost/
benefit for the program for the period 1985 to 2000 is calculated to be:
/„ r- $15 billion
Cost/Benefit = -I ft-,c'i -Vi':—
$.075 billion
Fluidized-bed power plants offer other potential benefits. Initially,
their overall efficiency will equal that of conventional plants, about
38 percent; however, with further development of gas and steam turbine
technology, an efficiency up to 50 percent can be achieved. Overall
reductions in power costs from 10-30 percent along with air pollution
abatement will result from the successful development of pressurized
fluidized-bed combustion. As an added benefit, thermal discharge of
power plants to water courses will be reduced by 10 to 60 percent.
Development: Program
Fast work on bench and pilot-scale equipment is to be continued and ex-
panded to include the operation of an integrated (combustion system plus
limestone regeneration) 0.63 MW pilot plant which is to be put on stream
early in 1973. This unit will be designed by ESSO R&E and will have
flexibility to permit continuous operation over a wide range of variables.
Data from this unit and other on-going projects will be used for design
416
-------
of a 10 Co 20 MW plant. It is expected that the commercial capabilities
of the process will be demonstrated in the 1974-1977 period and that de-
sign work on the 200 MW demonstration plant will begin in 1975. The
project will end with a completed demonstration study by 1981.
Description of Process
The process as it is presently conceived is described in detail in
Reference(T'l) which reports the results of design studies done by
Westinghouse for the EPA, In this study, plant sizes of 300 MW and
600 MW were considered. Figure T-l shows a schematic diagram of the
plant power 'cycle. Figure T-2 is a plot plan of steam generators and
accessory equipment, and Figure T-3 shows the 300 MW combined-cycle
plant-site plot plan.
Atmospheric Pressure Fluidized-Bcd Oil Gasification
Background
Pilot-scale experimental work on combustion of residual oil in fluidized
beds of limestone has been conducted by Esso Ltd. (U.K.) under Contract
with the EPA-DCS. Design data have been supplied by Esso to Westinghouse
(also under Contract with EPA) who has done conceptual design studies and
evaluation of commercial prospects. The most promising concept to date
Involves application of the system to production, on-site, of a low sulfur
fuel gas suitable for combustion in conventional boiler systems. A system
of this type appears to be acceptable either with or without regeneration
of limestone. The pollution control advantages offered by such a system
are as follows:
(a) Sulfur removal efficiencies up to 95 percent are possible for the
reasons cited in the discussion of the pressurized coal combustion
system.
(b) Nitrogen oxide emissions can be limited to 150 ppm for the reasons
cited in the discussion of pressurized coal combustion.
(c) Particulate emissions will be higher than those from oil or gas
fired systems but will be controllable using high efficiency dust
collectors. Also there is evidence to suggest that some of the
most offensive participates (such as sodium and vanadium) will be
removed in the fluidized bed so that the particulates which do
escape will be less objectionable than those from conventional
oil fired systems.
Advantages over conventional boilers with flue gas cleaning, the only
alternative where low sulfur fuels are not available, are as follows:
417
-------
CtftPRUSOIt
TVRDINE
Ml
X-
M
00
^JiV-tl-;,—,
FIGURE T-l. SCHEMATIC DIAGRAM. PLANT POWER CYCLE
-------
26* • 0"
76* - 4" •
22'-0"-
28' ' «"
1*"— *.« w " I &c. M i *
L.ai.Q"_j,—I?1-o"—!— ir -o"—4~ ir-o"-4-—is1-9"—4*-u •/"—j
' I 'I " I
j I ! ! ! •
i^^teF^^i I * I f
PTGURE T-2 PLOT PLAN, STEAM GENERATORS AND ACCESSORY EQUIPMENT FOR A
* 3QO-MW COMBINED-CYCLE PL.VNT (SHEET 1 of 2)
A19
-------
C.B.C. CAS
1
GAS OUTLET
10 i
TURBINE
FIRST STAGE
CYCLONE
I FLUE GAS
I FROM
PRIMARY BED
t_\£_ r-i ,.
EL. 73'-6"
STEAM
GENERATOR
EL.10r-6"
EL.EO'-S"
SECTION
T-2 PLOT PLAN, STEAM GENERATORS AND ACCESSORY EQUIPMEKT FOR A
-c. pLANT (SHEET 2 of 2)
420
-------
'•1 .
a HEATCR BAT
4 STORAGE SIMS
8 ADMINISTRATION ttOO.
« PARTICULATE KWOVAt IdUrPT.
7 CAS TUilaif.'g-GEUEftATOftS
0 STACK GAS COOLERS
> STACK
10 SURGE BIN
11 RECEIVING HOPPER
12 RECLAIM HOPPER
13 SILO (12,000 'on»|
14 DRVER
15 OtAO STORAGE (50.000 ««n«)
18 KAItn TRCAT.Vllvr
17 OltSCL-GCNCIIATOR ROOM
18 COUTftOL ROOM
19 MACHINE SHOP
20
a eoj AsjonetM
21 RECtNERATORS
24 DEAERA10*
JS ASH SILO
28 »AT[« STORAGE TANKS
77 LIGHT OIL TANK
2» LIGHT OIL UNLOADINGFVKP
21 ClflCul AUNG WATER INTAU PIFB
31 CAS1S ISIORAGE)
32 f miKlO J. M1E SEHVICI WATER TAWl
33 SERVICE WA'ER FUMP HOUSf
34 CIKCULATIIJG KATCR INTAKE STRUCTVKC
3$ CMLOKirjATlON COUIPMErjt
38 VARIABLE r.lIKi
37 SWITCH TARO
38 CO.'JVErORS
3$ StO.'/E STORAGE
SCALE
FIGURE T-3. • SITE PLOT PLAN, 300-KW COMBINED-CYCLE PLANT
-------
(a) The levels of control of Che three pollutants discussed above are
higher than can be attained with conventional systems.
(b) The capital cost of a'retrofit, once-through gasification system,
is expected to be 50 to 70 percent less than for a retrofit vet-
scrubbing system,
(c) Corrosion and fouling problems in boiler and collection system
are less as SCL, is collected in the fluidized bed,
X,
(d) The system is more compact; it uses crushed limestone eliminating
the need for pulverizers which are required for wet limestone
scrubbing. Also no flue gas preheat is needed and the dry solids
disposal problem is easier to handle than the sludge disposal
required by wet limestone scrubbing system.
Cost/Market
The retrofit process capital cost is expected to be 50 to 70 percent less
than for a retrofit wet scrubbing system and fuel added-cost for a retro-
fit system is expected to be 30 to 50 percent less than that for retrofit
wet scrubbing, low-sulfur oil, or desulfurized oil. The process appears
to be the most attractive near-term possibility for boilers less than
600 MW where residual oils are available. Initial markets would be the
East and West coast and in parts of the Southwest where gas is limited.
The comparative values for cost and emissions for conventional boilers
with low sulfur fuel and oil gasification systems are shown in Table T-l.
The total cost for the development program, including a demonstration
plant, is about $4.7 million. A cost-benefit analysis is now under way
but has not been completed.
Development Program
The present conceptual designs are based on bench and pilot-scale testing
on a 750 kw development plant. A demonstration plant program is now
planned. It would be concluded with collection of data from a demonstra-
tion plant of about 100 MW. Preliminary design of the demonstration unit
was completed in 1972. Construction is expected to start about September,
1973, with start of operation to begin in September, 1974. Complete
evaluation of the demonstration plant will be completed by mid-1976.
Process Description
Two modes of operation are possible for atmospheric pressure fluidized-
bed oil gasification; regenerable and once-through. The preferred
mode will depend on local factors such as cost of limestone, etc. A
complete process description including the assumed design conditions
is presented in Reference T-2. A schematic flowsheet for the two basic
modes of operation is given in Figure T-4.
422
-------
N>
u>
TABLE T-l. ASSESSMENT OF FLUIDIZED-BED OIL GASIFICATION/DESULFURIZATION
Baals: 3% Sulfur, 90Z Sulfur Removal, 600 MM Capacity, BOZ Load Factor
COST
Capital. $/kW.
Kew
Retrofit
Fuel Adder, c/106 Btu
New
Retrofit
EFFICIENCY (THERMAL)
ENVIRONMENTAL FACTORS.
S02, (lb/106 Btu)
NOX, (Ib N02/106 Btu)
Fartlculates, (lb/10$ Btu)
Solid Waste. ft^/MW-day
S REMOVAL
Stone
Ca/S
Make-up Ca/S
Low-Sulfur
Oil
...
(a)
25-35
25-35 <«>
0.35
0.40
0.06
NA
NA
NA
Stack Gas
Cleaning
25-40
40-75
11-14
14-20'
0.95-0.98
0.45
0.8
0.05
25
Oil Casl
Regenerative
Operation •
12-15
22-27
9.5-16.0
11-18
0.89-0. 96
0.35
0.16
0.02-0.2(0
15
Limestone
•v 15W>
1.0
flcation
Once-Through
Operation
8-10
18-22
9-10.5
10.5-12.5
0.96-0.9700
0.35
0.16
0.02-0.2
-------
N>
Combustion Air
T
limestonei — • — *
Make-Up
-u-. .•. y. N 0?$ifier
FIIP! ni|
.; y£\
Sulfided .:] i3
Lime [1 |R
— *• Regenerator
To
4 Stack
i
i
Boiler
___ j
Clean Fuel Gas
"^N, Temperature
^ v. Control
egenerated^stream
Lime
To^Ric
Cfp>/\^«-M
< Jii cam
: Sulfated
1 Lime
'* Disposal
Regenerative Mode
^ Sulfur
i Recovery
L;_ • . ^ . ^
Combustion Air
r ' cie
! T'
1 1
1 , r -r
| Fuel Odiirie
i Oil
j_ j
1 |
Su!fat£
•** General
1 S
D
Gas "*"
Liquid Once-Thn
Solid Feed
Solid Circulation
^ "TO
1 Stack
j
an Fuel Gas „ .,
»• Boiler
„ Limestone Feed
Temperature Control
^~ *-w l Cf«*A-«*««
-• — • otream
V
1
or
ulfaled
Lime
isposat
Dugh Mode
FIGURE T-4. MODES OF OPERATION
-------
Environmental Emissions
The environmental emissions to be expected from the pressurized fluidized-
bed combustion of coal and the atmospheric pressure fluidized-bed gasifi-
cation and combustion of oil have been calculated and summarized in the
module data sheets in Appendix A.
References
T-l. Examination of the Fluidized-Bed Combustion Process, Westinghouse,
to Environmental Protection Agency, Division of Control Systems,
Contract No. CPA-70-9.
T-2. Fluidized-Bed Oil Gasification for Clean Power Generation - Atmos-
pheric and Pressurized Operation. Newby, et al, presented at the
Third International Conference on Fluidized-Bed Combustion,
Hueston Woods, October 29 - November 1, 1972.
425
-------
APPENDIX U
SOLID WASTE .UTILIZATION
Table of Contents
Background 428
Municipal Refuse for Steam Generation -. . . 431
Municipal Refuse as a Power-Plant Fuel 431
Other Forms of Municipal Refuse Utilization 432
Environmental Burden '. 433
Research Costs - Refuse 434
Utilization of Organic Portion of Solid Wastes 434
References 435
List of Tables
U-l. Annual Generation of Solid Waste 428
U-2. Physical and Chemical Characteristics of Incinerator
Solid Waste 429
427
-------
APPENDIX U
SOLID WASTE UTILIZATION
The United States produces large quantities of solid wastes which contain
combustible material. These solid wastes create a disposal problem in
terms of cost and environment factors, yet they represent a potential
fuel reserve. Widespread use of solid waste as a fuel could have the
dual advantage of conserving other fuels and accomplishing disposal of
the wastes. Background information relating to the utilization of solid
waste has been compiled in a recent EPA report£U-l) The following
section is quoted from that report.
Background
Potential Energy of U.S.- Solid Wastes
In 1968, the USPHS, Solid Waste Program, made a national survey of solid
waste practices. It was conservatively estimated that the United States
was producing over 3.5 billion tons of solid wastes every year and in the
household, municipal and commercial sectors alone, collection and disposal
were costing $3.5 billion annually, while industry was spending about
$1 billion each year. Both increasing population and increased per capita
generation were predicted.
Table U-l, taken from the National Survey, shows the estimated annual
quantities of solid wastes generated in 1967.
TABLE U-l. ANNUAL GENERATION OF SOLID WASTE (1967)
Household, commercial and municipal 250 million tons
Industrial solid wastes 110 " "
Agricultural wastes and crop residues 550 " "
Animal wastes (manure) 1500 " "
Mining wastes 1100 " "
The potential of solid wastes as an energy source (exclusive of radio-
active materials) is dependent on its heating value, thus in determining
available energy, moisture and noncombustibles must be taken into
consideration. Extreme variation in both moisture content and noncombus-
428
-------
tible fraction occurs within waste types and even greater variation is
noted between solid waste types.
Community Solid Wastes. Table U-2 shows the typical range in composition
of residential-commercial (community) solid wastes based on published
reports'^-?) and discussions with incinerator designers.
TABLE U-2. PHYSICAL AND CHEMICAL CHARACTERISTICS
OF INCINERATOR SOLID WASTE
Constituents . % by weight (as received)
Proximate analysis:
Moisture 15-35
Volatile matter 50-65
Fixed Carbon 3- 9
Noncombustibles 15-25
Ultimate analysis:
Moisture 15-35
Carbon 15-30
Oxygen 12-24
Hydrogen 2- 5
Nitrogen 0.2-1.0
Sulfur 0.02-0.1
Noncombustibles 15-25
Higher heating value Btu per Ib (as received)
3,000-6,000
(a) Principally residential-commercial waste excluding bulky waste.
While the table shows a Btu range of 3000 to 6000, the "as received"
refuse most often has a high heat value between 4000 and 4500 Btu per Ib.
It is significant to note that the heat value of community solid waste is
expected to increase. With increased use of plastics and paper, the value
could increase by 500 Btu per Ib by 1980.
If all community solid wastes were collected, the potential heat energy in
the United States would be 2,100 trillion Btu per year. This is based on
current generation of 250 million tons per year and an average high heat
value of 4200 Btu per Ib.
Industrial Solid Wastes. In determining the potential heat value of
industrial solid wastes, estimated in 1967 at 110 millions tons per year,
it is necessary again to recognize that published information on the
chemical characteristics of industrial waste is practically non-existent.
429
-------
Based on discussions with EPA personnel who have conducted limited surveys,
it can be expected that this waste would have substantially higher value
than community refuse due to increased content of wood, paper and plastics
plus absorbed oils and greases—thus an average value of 5200 Btu per Ib
is considered conservative. On this basis, if all industrial solid wastes
were collected, the potential annual heat value of the fuel would be
1,144 trillion Btu per year.
Manures. Crop and Forest Residues. The 1968 National Survey of Solid Waste
Practices estimated agricultural wastes, animal manure,*and forest waste
production at 2,050 million tons annually. These wastes generally have
high moisture contents and much of the waste is left uncollected. The 1970
production of animal manures, forest residues and fruit tree prunings on
a dry weight basis has a heat content of 3,506 trillion Btu(^-3)>
The total energy theoretically available annually from United States solid
wastes, based on 1967 and 1970 production, is summarized below.
Waste Source
Average
Production, Heat Value,
Household, commercial, and
municipal (community)
Industrial solid wastes
Manures, crop and forest
residues
million tons
250
110
232
Btu
4200
-------
All industrial solid wastes, manures, crop wastes and forest residues
are equivalent to 4,650 trillion Btu and would theoretically have the
potential to supply 17 percent of the current United States power needs.
Thus all United States solid wastes would theoretically provide the
fuel to meet 25 percent of the nation's .current power requirements.
Municipal Refuse for Steam Generation *
Combustion of municipal refuse for power and steam generation has evolved
to a well-developed art in Europe over the past 40 years. About 50 per-
cent of refuse is cellulosic, thus forming an easily combustible though
heterogeneous fuel. Two German plants have now been built in the United
States: Chicago-Northwest- 1600 tons/day, 150,000 Ib steam/hour, 22 MW
electrical equivalent^0'5), and Harrisburg Pennsylvania; 720 tons/day,
70,000 Ib steam/hour, 10 MW equivalent^"5'. Both of these plants
produce only steam, not electrical power. The refuse is burned on moving
grates in furnaces lined with vertical steam generator tubes similar to
conventional coal-fired power plants. High-efficiency electrostatic
precipitators clean the exhaust. This trend will continue and accelerate
in the United States. Although these are large incinerators, their
potential electrical output is small.
If all the waste collected in our large cities could be used as fuel and
if the heat produced could be used for district heating and cooling,
'most" of these energy loads in the central business district of these
cities could be satisfied. These are very big if's. Investment costs
for clean steam plants and for underground steam or hot water mains are
awesome. Nevertheless, this new United States trend to follow the
European lead will continue.
Municipal Refuse As A Power-Plant Fuel
Much consideration has been given to recovery of heating values in refuse.
About 10 percent of the energy required for a typical city could be
recovered from its refuse. One approach to recovery of heat from refuse
has been to build expensive incinerators which burn the heterogeneous
refuse with little or no pretreatment. -This approach has certain dis-
advantages. The equipment is costly, and relatively complicated.
Corrosion and air pollution are difficult to control. Skilled operators,
often unavailable to municipal organizations, are required.
An alternative approach which has been considered in recent years is to
process the refuse to remove noncombustibles, and shred and promote homo-
geneity so that the material is suitable for firing in combination with
fossil fuels in power boilers. This approach has many patent advantages,
namely:
431
-------
(1) The cost: of preparation equipment is small compared to modern
incinerators. A complete preparation plant designed for recovery of a
fuel and ferrous metals would probably cost about $5/ton of capacity as
compared to $10 or more per ton for an incinerator.
(2) The net cost of operation for a plant producing fuel for burning
in an existing boiler has been estimated at $5 to $6 per ton without the
credit for recovered heat. With refuse disposal costs now running around
$10 and more per ton in many cities, this would give a savings of about
$4 to $5 per ton over alternative methods. This represents an annual
savings of $1.5 to $2.0 million dollars per year for a city of 500,000
producing 1000 ton/day of refuse.
(3) The fuel values which can be recovered are significant. At 40(5
per million Btu's, an annual return of over $1.0 million per year would
be realized from a 1000 ton/day plant. This would reduce the processing
cost to $1 to $2 per ton.
(4) All equipment required for effective refuse processing systems is
commercially available so that no development work would be required for
a preparation plant.
(5) In most municipalities the demand for energy substantially exceeds
the availability of energy in the refuse produced. This situation favors
the possibility of combined firing of coal and refuse. A city of 500,000
would produce about 1000 ton/day of refuse. At 4200 Btu/lb this would
provide about 10 percent of the fuel for a 500 MW boiler.
(6) The combined firing scheme which is favored by logistics tends to
minimize the potential problems associated with feeding and firing of the
refuse in a boiler. Studies have indicated chat firing refuse in
quantities up to 10 to 20 percent of the total Btu input should not
seriously interfere with boiler operation. Potential objectionable com-
ponents do not appear to be present in quantities which will impact
seriously on the normal mode of operation for the boiler.
The City of St. Louis, in a cooperative effort with the EFA, initiated
a program based on this approach in May of 1972(^-7, U-8), xhe trash is
shredded and magnetically separated and fed into a pulverized coal steam
boiler plant. About 300 tons of refuse per day are consumed in this way
and this accounts for 10 percent of the energy supplied to the boiler.
Other Forms of Municipal Refuse Utilization
Current schemes to produce gas or oil by pyrolysis of refuse are too
embryonic to gage their promise. Even if successful they will not alter
significantly the energy produced nor the environmental emission of energy
recoveryCu~9).
432
-------
Environmental Burden
To produce 1000 MW electricity will require a plant burning about 73,000
tons of refuse per day. The refuse shredder and magnetic separator could
salvage roughly 3,000 tons per day of steel scrap (assuming about 4 or 5
percent of the refuse is recoverable).
Emissions to the air from water-walled units will be:
Parriculate
Sulfur Dioxide
Nitrogen Oxides
(U-5)
0.1 Ib/million Btu input 0.18 is allowed by EPA
0.9 Ib/million Btu input No limit for incinerators.
For coal boilers limit is
0.5 Ib/million Btu input
(Estimate)
No limit for incinerators.
For coal boilers limit is
0.7
Chlorides (as HC1) 500 ppm (0.06/million Btu) No limits have been set
(U-11)
A major problem will be protecting the boiler tubes from corrosion by
increasing amounts of chlorides created by incineration of chlorinated
plastics*0'12).
Water pollutants discharged:
None, assuming appropriate processing
because the effluent is small in volume and
can be thoroughly treated.
Solid residue from combustion (including fly ash) to.be deposited in
sanitary 7300 tons/day (assuming 90 percent
weight reduction). 15,000 cu yd/day
(assuming 95 percent volume reduction).
The atmospheric and liquid waste emissions will be minimal, less than
the important current standards. Particulate emission will be only
about 1/10 that of current municipal incinerators. Land use for solid
residue disposal will be about 1/20 that now required for sanitary land-
fill of "raw" refuse. Surface water leaching from burned residues is at.
present an ill-defined concern.
The environmental emission of producing power from solid waste should be
considered in light of other waste disposal alternatives.
(1) Straight incineration would probably produce equivalent emissions,
if controlled. However, power production will probably occur in large,
efficient, easier to control boilers with auxiliary coal firing. There-
fore, net pollution potential is less than with incineration.
433
-------
(2) Landfill would require 10 to 20 times more solid waste disposal
volume than incineration with power production. Of course, there are
few significant air emissions from landfill.
Therefore, the net environmental emission of power production from
solid wastes is negligible, considering alternative disposal methods.
Research Costs - Refuse
Considerable research will be required for development of assured power
boiler designs to combat corrosion. Zinc and lead in refuse are
important corrosive agents when tied in with the chlorides(^-9).
Confining the operation to low-temperature steam production appears to
eliminate corrosion. To generate power efficiently higher temperatures
are required; hence, ways should be found to protect high-temperature
boiler tubes.
This corrosion research will require of the order of $1 to $5 million
per year, accelerating as the technology develops. Total estimated
boiler corrosion research cost: $20 million in 10 years.
Current research on the surface water polluting potential of leaching of
incinerator residue should be continued. Estimated research cost on
water pollution potential of incinerator residues: $5 million total
over 10 years.
Utilization of Organic Portion of Solid Wastes
The amount of animal wastes produced in the United States exceeds total
municipal solid waste by a factor of two; hence, it is potentially a
large energy source if burned or somehow converted to fuel. However,
the environmental hazard of thus destroying this potential source of
humus in the soil instead of realizing its soil benefication potential
should also be carefully evaluated. Assuming that our total organic
waste output is appropriate to consider as an energy source, even some
of this is infeasible for conversion because of its remoteness from the
centers of energy demand.
Assuming that one-half of this total organic waste is available for
conversion by some process to a clean fuel, the potential fuel value as
oil would be about 90 million barrels^" *3). This would be about 1.5 per-
cent of the United States 1971 crude oil demand. The reference just
quoted also states "The economic feasibility of converting organic wastes
to oil or gas has not as yet been proven". Although the potential addi-
tion to our total energy supply is small, the opportunity to reduce also
our landfill disposal problem makes this potential attractive enough to
justify detailed analysis and small-scale pilot investigation.
434
-------
The potential for saving of space required for sanitary landfill can be
a significant beneficial impact of pyrolysis, gasification, or inciner-
ation. In metropolitan areas this already is a critical factor because
nearby sites are used up and neighboring communities frown on "importing
environmental impaccs from others". A -rule of thumb states that land
requirement of 3/4 tc 1-1/2 acres per year per 10,000 population is
required if the average depth of the compacted refuse is seven feet^
Using an average of one acre per year, if all of our population were
served by sanitary landfills, the area required would be ,20,000 acres
per year. Potentially, pyrolysis, incineration, or gasification to
produce useful fuels or heat or electrical energy could cut that landfill
requirement to well under 10,000 acres per year, depending on the degree
of resource recovery applied during shredding or other preparation of the
waste before processing.
Many small-scale attempts have been made to show that useful gas and
combustible liquids can be derived economically from solid wastes'^'^).
None of these has been successful where tried in large scale. Two major
new efforts in this direction were announced in September, 1972, whan
EPA announced $6-million for partial support of a 1000-ton per day,
$14-million pyrolysis demonstration plant for the city of Baltimore
producing gas for steam generation, using a process developed by Monsanto-
Eniro-Chem. Operation is to start June, 1974; hence, it will be at least
1977 before feasibility is fully evaluated.
At the same time, September, 1972, EPA announced a $2.9-million demon-
stration grant to San Diego County for a $4-million plant to pyrolyzc
200 tons of solid waste per day to produce fuel oil and to reclaim glass
and metal. The system was developed by Garrett Research and Development
Company. This plant is scheduled to operate in December, 1974.
Thus, if recovery as gas or oil from the organic portion of municipal
waste is feasible at full scale, we are now nearer to knowing that than
ever before. It will require several years to determine the outcome.
References
U-l. Keller, D. J., "Utilization of Solid Wastes as Fuel", Appendix
to OR&M Technology Division's "Federal Energy Study" draft 1972.
U-2. Kaiser, E. R. Chemical analyses of refuse components. In Proceed-
ings; 1966 National Incinerator Conference, New York, May 1-4,
1966. American Society of Mechanical Engineers, p. 84-88.
U-3. International Research and Technology Corp., Draft final report,
"Problems and Opportunities in Management of Combustible Solid
Wastes," Oct. 1972-EPA Contract 68-03-0060.
435
-------
U-4. Paper by J. P. Barnhart, Division of Process Control Engineering,
NAPCA, project values from Fig. 1,"Basis for Project Air Pollution
from Combustion of Fossil Fuels in the U.S."
U-5. Stabenow, G., "Results of the Stack Emissions Tests at the New
Chicago Northwest Incinerator", IBW-Martin Incinerator Group,
for presentation at 1972 ASME Winter Annual Meeting.
U-6. Rogus, C. A., "Harrisburgh Incinerator - Highlights of Design",
presented at ASME-Incinerator Division Meeting, May 14, 1969.
U-7. , "City of St. Louis Has Power-Full Trash", Inside EPA,
October, 1972.
U-8. Wisely, F. E., Sutterfield, G. W., Klurab, D. L., '.'St. Louis Power
Plant to Burn City Refuse", Civil Engineering, January, 1971.
U-9. Drobny, N. L., Hull, H. E., and Testin, R. F., "Recovery and
Utilization of Municipal Solid Wastes", prepared for Solid Waste
Management Office under Contract No. PH 86-67-265.
U-10. Roberts, R. M., and Wilson, E. M.,"Systems Evaluation of Refuse as
Low Sulfur Fuel: Part I - The Value of Refuse Energy and the Cost
of Its Recovery", presented at ASME Winter Annual Meeting,
November 28-December 2, 1971.
0-11. Miller, P., and Krause, H., "Fireside Metal Wastage in Municipal
Incinerators", presented at 1970 ASME Winter Annual Meeting.
0-12. Engdahl, R. B., Krause, H. H., and Miller, P. D., "Effluents from
the Municipal Incineration of Plastics", presented at the ACS
Symposium on Polymers and Ecological Problems, August 29, 1972.
U-13. Energy Potential from Organic Wastes, U.S. Bureau of Mines
Information Circular, I.C. 8549, pg. 14, 1972.
U-14. Municipal Refuse Disposal, APWA, pg. 92, 1966.
436
-------
APPENDIX V
NUCLEAR FISSION SYSTEMS
•
Table of Contents
Page
Introduction 440
Technical Approach 441
Summary 444
Nuclear Energy Demand and Nuclear Fuel Requirements 450
Uranium Mining 455
Uranium Milling 461
Thorium Mining and Milling .- 467
Uranium Conversion 473
Uranium Enrichment 477
Fuel Fabrication 480
Power Reactor Operation 493
Fuel Reprocessing '.. 504
Radioactive Waste Disposal 512
Transportation in the Nuclear Industry • 515
References 518
List of Tables
V-l. Summary of Emissions—Air Receptors 446
V-2. Summary of Emissions—Water Receptors 447
V-3. Summary of Emissions—Land '. 448
V-4. Energy Demand 451
V-5. Calculated Material Flows 454
V-6. Estimated Distribution of Uranium Extraction 456
V-7. Summary of Uranium Mining Throughputs 456
V-8. Potential Environmental Impact of Uranium Mining 459
V-9. Summary of Uranium Mining Impacts •.' 460
V-10. Summary of Incremental Land Usage for Uranium Mining. . .'. 459
V-ll. Summary of Uranium Milling Throughputs 462
V-12. Distribution of Radioisotopes in Uranium Milling
Processes for Producing One Kiloton of U30g For
All Years 464
V-13. Summary of Uranium Milling Emissions 466
V-14. Suwmary of ThC>2 Milling Throughputs . 469
V-15. Distribution of Radioisotopes in the Production of
One Ton of Th02 470
V-16. Summary of Thorium Milling Emissions 472
V-l7. Summary of Uranium Conversion Throughputs 474
V-18. Distribution of Radioisotopes in the Conversion of One
Kiloton of Uranium 474
V-19. Summary of Uranium Conversion Impacts 476
V-20. Summary of Uranium Enrichment Throughputs 478
437
-------
.List of Tables (continued)
Page
V-21. Summary of Uranium Enrichment Impacts 481
V-22. Fuel Fabrication Requirements 482
V-23. Internal Recycle Rates 484
V-24. Amount of UO, Released in Fabricating One Metric
Ton of Fuel 484
V-25. Summary of Total Radionuclide Release in Fabricating
U02 Fuel t . . . . 485
V-26. Release Rates in Fabrication of U02-Pu02 Fuel 488
V-27. Summary of Total Radionuclide Release in Fabricating
U02-Pu02 Fuel 488
V-28. Isotopic Contributions to KTGR Fuel Releases in
Curies per Ton of Material Released 490
V-29. Summary of Total Radionuclide Release from HTGR
Fuel Faorication 492
V-30. Summary of Releases from Fuel Fabrication Plants .... 492
V-31. Estimated Costs to Control Radioactive Releases
from Fuel Fabrication Plants 494
V-32. Comparison of Projected Heat Released from Thermal
Power Plants Built Between 1965-1980 with the
Heat Sink Capability of the Streams 500
V-33. Receptor Loadings for Heat Dissipated from Nuclear
Power Reactors 501
V-34. Potential Environmental Impact of Power Operation. . . . 502
V-35. Power Reactor Operation-Radionuclide Releases to
the Environment 502
V-36. Reprocessing Plant Throughputs 507
V-37. Environmental Effects of Fuel Reprocessing on Air. . . . 509
V-38. Environmental Effects of Fuel Reprocessing on Water. . . 510
V-39. Curies and Volumes of High-Level Waste Sent to a
Government Repository for Perpetual Storage 511
V-40. Curies and Volumes of Low Level Waste Packaged and
Sent to a Licensed Repository from the Reprocessing
Plants 511
V-41. Summary of Radioactive Waste 514
V-42. Nuclear Material Shipments 517
List of Figures
V-l. Material Flow in Nuclear (Fission) Fuel Cycle 442
V-2. Electrical Energy Demand (Production) 452
V-3. Uranium Mining 457
V-4. Uranium Milling 463
V-5. Thorium Milling 471
V-6. Uranium Conversion 475
V-7. Uranium Enrichment 479
V-8. U02 Fuel Fabrication 483
438
-------
List of Figures (continued)
V-9. Mixed Oxide Fuel Fabrication 487
V-10. HTGR Fuel Fabrication I 491
V-ll. Power Reactor Operation 496
V-12. Regional Divisions 499
V-13. Nuclear Fuels Reprocessing . . . . 508
V-14. Radioactive Waste Disposal *..... 513
V-15. Nuclear (Fission) Fuel Cycle Process Flowsheet 516
439
-------
APPENDIX V
NUCLEAR FISSION SYSTEMS
Introduction
Battelie Pacific Northwest Laboratories participated with Battelle-
Columbus Laboratories in a study conducted for the Environmental
Protection Agency, Office of Research and Monitoring. The purpose of
the study was to assess the comparative emissions in the United States
from the various fuel sources and energy cycles through 1990. These
data are needed to provide the bases for setting policy regarding
Federal actions required to meet future demands for energy.
The alternate energy supplies considered commercially viable in the 1975
to 1990 time period are: (1) coal, (2) oil, (3) natural gas, and (4)
fission. There are currently five fission power plant concepts being
developed. These are
• Light Water Reactor (LWR)
• High-Temperature Gas-Cooled Reactor (HTGR)
• Liquid Metal Fast Breeder Reactor (LMFBR)
• Gas-Cooled Breeder Reactor (GCBR)
• Molten-Salt Breeder Reactor (MSBR)
The LWR and the HTGR are commercially viable, in that they are commer-
cially available to the electric power industry. With the national
commitment to developing the LMFBR, it is expected that this type of
power plant will be commercially applied in the latter part of this time
period. The GCBR and the MSBR are being developed as backup technolo-
gies for the nuclear power industry and are not expected to reach commer-
cial application in the 1975 to 1990 time period. Therefore, these two
concepts are not included in this assessment, rather they are treated
with the analyses of advanced energy technologies and are reported in
Appendix W of this report.
All forecasts made to date show continued increases in the amount of
electricity consumed in the United States over this time period and in
the number of nuclear power plants built to supply that electricity.
If these forecasts hold true, then there will be a corresponding increase
in the amount of radionuclides generated in meeting this electrical de-
mand. The amount of radionuclides released to the environment also is
expected to increase even though improved radwaste systems are adopted
which would reduce the release rates. This study forecasts the quantity
of radionuclides released during 1975, 1980, 1985, and 1990.
The quantities of radionuclide wastes from the LWR power reactor industry
440
-------
for 1967. 1970, 1975, and 1980 were previously forecast in Phase I of
a study^"1' conducted for the U.S. Atomic Energy Commission. The fore-
cast of this document is based on the same general assumptions with
some modifications of input data and can be considered a continuation
of that forecast.
Technical Approach
A combination of forecast data for the electrical power industry and
general material balances for the nuclear segment of that industry are
used to estimate the quantities of waste for 1975, 1980, 1985, and 1990.
The relevant material flows in and out of the nuclear power industry are
identified and quantified by type and location, with emphasis placed on
determining the final disposition of waste materials.
The general flow of radioactive materials through the power reactor
system was divided into nine steps for the uranium cycle and eight
steps for the thorium cycle. These 17 steps are presented schematic-
ally in Figure V-l. For each step, a material balance was made to de-
termine relevant inputs and outputs, including the quantities, physical
forms, and disposal system. The material balances for each process are
presented in flowcharts and tables. Five of the steps involved two
distinctly different processes having different effluents and, thus,
two sets of data were prepared. (As an example, separate tables were
prepared for the acid leach and carbonate leach uranium mills activities.)
The waste burial steps for the uranium and thorium cycles were combined.
Each of the resultant steps is described as a separate industry and the
data for each are presented in subsequent sections.
The waste produced by each process was assumed to be directly propor-
tional to the activity level throughputs for 1967 and 1970 and are
taken from AEC records and Nuclear Industry. 1970. Projections were
made using the Linear Programming Model of the U.S. Power Economy(v~2)
which has been used in previous studies for the USAEC,(V-3) and the
ISOPRO computer code(V-4) which calculate throughputs based on installed
capacity.
Assumptions Made in This Study
Because this was a preliminary study, several simplifying assumptions
were made which are listed here.
• The AEC is now providing numerical guidelines on design objectives
for light water cooled reactors which would carry out its policy of
keeping radioactivity in effluents to levels which are as low as prac-
ticable. The cited projected levels for reactors built after I960 re-
flect anticipated technological improvements in radwaste treatments.
• It is anticipated that numerical guidelines also wi'll be forthcoming .
-------
ffiMim Ittytlt
Hint
Bin
M«o
1
tenetntritt
C«KCAtri(«d Kannltc
FIGURE V-l. MATERIAL FLOW IN NUCLEAR (FISSION) FUEL CYCLE
442
-------
on design objectives for fuel reprocessing plants to keep their radi-
ation releases and resultant radiation exposure as low as practicable.
The projected levels reflect some anticipated technological improve-
ments in waste treatment systems for power and reprocessing plants.
• The quantities quoted for radiological emissions in this report are
given as total activity (curies) released. The effects of these releases,
which depend on the particular nuclides involved, are excluded in this
study. Similarly, the occupational hazards are excluded.A
o No attempt was made to anticipate any changes in the standards or
estimate any costs that might be involved in meeting them.
e The primary assumptions applying to two or more processes are:
1. The study covers only the commercial nuclear power industry, includ-
ing all related portions of the fuel cycle.
2. Only LWR's, HTGR's, and LMFBR's were included in the study.
3. LWR's and LMFBR's operate only in the uranium fuel cycle. Plutonium
recycle was included. KTGR's operate only on the thorium cycle. Oxide
fuels are used for all reactors.
4. Only gaseous diffusion enrichment facilities are used assuming a
tails assay of 0.2 percent Ij235 m
5. No target irradiations were considered, or the recovery of special
products (i.e., Np237, c£137).
6. The physical limits of the power reactor system for each type of
waste and product are as follows:
Type of Waste or Product System Physical Limit
Airborne Physical boundary of plants
Waterborne Physical boundary of plants
S.urface-stored wastes Physical boundary of plants
Burial wastes Burial ground
Production Shipping facilities
7. The radwaste treatment systems used in this study reflect anticipated
technological improvements in power reactor radwaste systems.
8. Activation of permanent reactor equipment was not determined. No
waste disposal due to decommissioning of reactors and reprocessing
plants is included.
9. Possible accidental releases of radioisotopes during shipments were
not included.
443
-------
10. Solidified high-level wastes are to be shipped to permanent
storage five years after reprocessing.
11. The use and disposal of radioisotopes for research and medical
applications were not included.
12. Available economic and technical data were used. Special analyses
were not made to develop new data. 1970 costs were used for operating
and capital costs.
13. No throughput for foreign use is included.
Because information was not readily available in the short time per-
mitted for this report, capital and operating costs were not developed
for many of the waste treatment systems used in the nuclear industry.
General systems for which no cost data were developed were: sanitary
wastes, nonradioactive solid wastes, and nonradioactive chemicals dis-
charged to the air, land, and water. The reason is that the costs for
such systems are small in relation to the total costs of waste treat-
ment systems. The components of the nuclear industry for which no costs
were developed are as follows:
Industry Component Waste System
U Mining Mine Ventilation Systems
Low-Grade Ore Disposal
U Milling . Ventilation Systems
Tailings Disposal
Th Milling Solid and Liquid Wastes
Enrichment Airborne Wastes
Liquid-Borne Wastes
Surface Burial Capital Costs
The radiological releases at these stages of the nuclear fuel cycle are
small in comparison to those at the fabrication, reactor operation, and
reprocessing stages.
Summary
Estimates have been made of the quantity of effluent expected from the
projected utilization of nuclear power reactor plants to meet the elec-
trical energy demand during the period 1975 to 1990. These estimates
are made assuming normal plant operating conditions. On the basis of
the time allotted for completing the study, the emphasis was placed up-
on identifying and quantifying the release of radiological effluents
in the nuclear fuel cycle. A very preliminary study was made of some
444
-------
I '
of the other effluents which impact the environs and these are also
reported.
Nuclear Demand and Fuel Requirements
Using historical data from 1965 to the present, a constant growth rate
of 7.18 percent was used for projecting electrical demand up to 1980.
Using a mix of other data and other energy projections, growth rates of
6.6 percent per year and 5.6 percent per year were used for the decades
1980 to 1990 and 1990 to 2000, respectively. To project the nuclear
requirements, it was assumed that the nuclear plants would be base
load plants with fossil plants built after 1980 being used for load
following. Further, it was assumed that no fossil plants would be
built after 1990. Eased upon these assumptions, nuclear plants will
produce roughly 19/29/41/54 percent of the total installed capacity for
the years 1975/1980/1985/1990. If construction schedules for nuclear
plants continue to slip and/or no major new markets for electricity
appear in this time period, these demand values may be considered upper
estimates. These estimates of nuclear power requirements were used to
define the nuclear fuel requirements and the throughputs for each stage
of the nuclear fuel cycle.
Emissions
Estimates of the quantity of radioisotopes released to air, water, and
land receptors were made, using the calculated throughputs required to
meet the demand schedule for each stage of the nuclear fuel cycle.
These are summarized in Tables V-l, V-2, and V-3 for air, water, and
land receptors, respectively. Also shown in the tables are the other
emissions which must be studied to determine the total emissions. Where
data on these nonradiological emissions were immediately available,
they are included in Tables V-l to V-3.
Throughout this report the amounts of radioactive wastes are reported
as curies of radioactivity. However, the total number of curies should
not be interpreted as a measure of the radiation hazard presented by
the.various waste streams. Radiation hazard estimates require knowing
the quantity, chemical, and physical form for each nuclide released to
the environment.
Control Mechanisms and Costs
A great deal of attention is being and has been given to controlling the
dispersal of wastes from the nuclear industry to minimize the risks to
people and environs.
From considerations of the radiological emissions given in Tables V-l
through V-3, it is evident that the major amounts of radioactive efflu-
ent release occur at the reprocessing plant, the power reactor plant,
and the fuel fabrication plant. Therefore, the study has been concen-
trated on investigation of control mechanisms and associated costs for
these three stages of the nuclear fuel cycle.
445
-------
TABLE V-l. SUMMARY OF EMISSIONS—AIR RECEPTORS
Stage of
Cycle
Year
Parameter
1975 1980 1985 1990
U Mining
V Killing
Th Mining &
Killing
U Conversion
U Enrichment
Fuel Fabrication
Reactor Operation
Fuel Reprocessing
Conversion
Radiological, Cla
Parclculato & Gas
Thermal
Radiological, Cl
Partlculatc & Gas
Thermal
Radiological, Ci
Participate & Gas
Thermal
Radiological, Ci
Participate & Gas
Thermal
Radiological, Ci
Particulate & Gas
Thermal
Radiological, Ci
Particulate & Gas
Thermal
Radiological, Ci
Particulate & Gas
Thermal
Radiological, Ci
Particulate & Gas
Thermal
Radiological, Ci
Particulate & Gas
Thermal
5,000 9,000 16,000 25,000
.3
.56
.5
1.3
.86 1.41 2.79
9.4x10* 2.0xl07 2.4xl07 2.9xl07
32 100 253 504
l.OxlO7 1.7xl07 1.9xl07 2.2xl07
25 62 100 190
Included in Reprocessing
Waste Disposal
Totals
Radiological, Ci
Particulate .& Gas
Thermal
Radiological, Ci
Particulate & Gas
Thermal
0
0
1.94xl07
0
0
3.7xl07
*
0
0
4.3xl07
0
0
S.lxlO7
(a) Cu, curies of radioactivity
(b) Heat In gigauatts.
(e) Heat la megawatts.
446
-------
TABLE V-2. SUCIARY. OF EMISSIONS—WATER RECEPTORS
Stage of
Cycle
U Mining
U Hllllns
Th Mining &
Milling
Parameter 1975
Radiological. Cl(a)
Chemical & Solid
Water Usage
Thermal
Radiological. Cl 1.2
Chemical & Solid
Water Usage
Thermal
Radiological. Cl 0
Chemical & Solid
Year
1980 1935 1990
•
2.4 4.7 8.1
000
U Conversion
U Enrichment
Fuel Fabrication
Water Usage
Thermal
Radiological. Ci
Chemical & Solid
Water Usage
Thermal
Radiological. Ct
Chemical & Solid
Water Usage
Thermal
Radiological, Cl
Chemical & Solid
Water Usage
Thermal
.4
2.2
13.2
..7
4.1
19.8
1.2
6.4
32.5
1.9
10.5
64.5
Beaetor Operation Radiological, Ci
Chemical & Solid
Water Usage
Thermal
Fuel Reprocessing Radiological, Cl
Chemical & Solid
Water Usage
Thermal
Conversion
Radiological, Cl
Chemical & Solid
Water Usage
Thermal
2.7xl05 S.OxlO5' l.SxlO6 2.4x10*
74xl03(b) 132xl03 196xl03 305xl03
2x10* 2x10* 2x10* 2x10*
2.600(0 12,000 20,000 35,000
25 0>) 60 100 190
Included In Reprocessing
Waste Disposal
Total*
Radiological. Cl
Chemical & Solid
Water Usage
Thermal
Radiological. Cl
Chemical & Solid
Water Usage
Thermal
0
0
0
0
2.7xU>5
0
0
0
0
8.0x10.5
0
0
0
0 '
1.5x10*
0
0
0
0
2.4xl06
(•) Cl, curies of radioactivity, vhere blanks exist, no evaluations were made.
(b) Beat In megawatts.
(c) Gallons/minute.
447
-------
TABLE V-3. SUMMARY OF EMISSIONS—LAND
Stage of
Cycle
U Mining
U Hilling
Th Mining &
Milling
U Conversion
U Enrichment
Fuel Fabrication
Reactor Operation
Fuel Reprocessing
Conversion
Waste Disposal
(High Level)
Totals
Parameter
Radiological, Ci(a>
Chemical & So I id (b)
Land Usage (O
Radiological, Cl
Chemical & Solid
Land Usage
Radiological, Ci
Chemical & Solid
Land Usage
Radiological, Ci
Chemical & Solid
Land Usage
Radiological, Ci
Chemical & Solid
Land Usage
Radiological, Cl
Chemical & Solidc)
Land Usage-Waste
Radiological, Ci
Land Usage-Uaste(c)
Radiological, Ci
Chemical & Solid
Land Usage- Waste
Radiological, Ci
Chemical & Solid
Land Usage
Radiological, Ci
Chemical & Solid
Land Usage
Radiological, Cl
Chemical & Solid
Land Usage
1975
I.3xl08
1,193
21.000
13
31
0
2xl05
1.9x10*
1
6xl05
6xl05
12
2.9xl05
2.6xl05
5
Included
0
0
l.lxlO6
1980
2.4xl08
2,013
38,000
42"
53
0
1.4xl06
3.4xlOA
1
l.SxlO6
1.5x10*
30
l.SxlO6
6.8xl05
14
1985
4.5xl08
3,439
•
65,000
120
92
0
2.6x10*
5.9x10*
I
2.8xl06
2.8xl06
50
2.9xl06
l.lxlO6
22
1990
7.7xl08
5.080
lO.lxlO4
230
145
0
6.2xl06
l.OxlO5
2
5.2x10*
5.2xl06
100
I.3xl08
2.2xl06
46
in Reprocessing
1.3x10*
4,290
1.3xi09
1
3.4xl09
11,220
3.4xl09
S.SxlO9
18,180
S.SxlO9
(a) Ci, curies of radioactivity, where blanks exist, no evaluations were made.
(b) Cubic yards of waste rock from open pit and underground mining.
(c) Acres of land required/year.
(d) Ft3 of solid waste/year.
(e) Shipped to offsitc licensed contractor.
448
-------
Reactor. ' The reactor waste treatment system is designed to collect all
gases, liquids, and solids containing radioactivity and treat them to
minimize radiation releases to the environment. A treatment system is
provided for each. Although there will be some variations in the waste
treatment systems for each reactor type, LWR's, HTGR's, and LMFBR's,
these differences are expected to be minor and consist primarily of
chemical reaction systems for neutralizing or precipitating the liquid
waste streams.
The average costs (1970) for radioactive waste treatment systems for a
1000 MWe (megawatts, electrical power) LWR reactor were $2,611,000 capi-
tal cost and $38,430 per year operating cost. Forecasting future waste
facility capital costs is difficult because the policy of "as low as
practicable" is not quantified. We estimate that the installation for
"as low as practicable systems" is about $15 million per reactor and the
operating costs will be about $500,000 per year.
In addition to radionuclide emissions, heat rejection from nuclear
power plants is of concern. The waste heat from a power plant is re-
leased either to a water body or to the atmosphere. The costs for heat
dissipation systems depend on the thermal efficiency of the plant and
the cooling system used. Typical costs for once-through cooling to
water bodies range from $7 to $15 million; evaporative type cooling
systems range from $15 to $22 million; and dry cooling systems range
from $35 to $50 million. The cost of future control mechanisms for re-
ducing thermal discharges could range from 0 to $30 million assuming the
additional cost is that relative to the once-through-cooling-to-fresh-
water cost ($7 million).
Fuels Reprocessing Plant. The reprocessing plant waste treatment systems
consist of gas, liquid, and solid treatment systems. The LMFBR, HTGR,
and LWR reprocessing plant waste treatment systems can be considered to
be similar even though the processes are quite distinct. The primary
sources of waste are: the fission productions separated from the thorium,
uranium, and plutonium recycle streams, the transplutonium isotopes,
small percentages of the uranium, thorium, and plutonium, and activated
or contaminated processing material and corrosion products.
The costs incurred from the waste treatment facility are not very sensi-
tive to the process used. For a 5 ton per day reprocessing plant, using
1970 costs, the waste treatment facility total capital cost is estimated
to be $25 million. Annual operating costs are estimated to be $3 million
per year. It is not unreasonable to assume that "as low as practicable'
will become the guidelines for controlling releases from reprocessing
plants in the future. It is assumed that releases of radioactive gas
to the atmosphere will have to be controlled and the estimated costs
for gas treatment facilities are $7 million capital costs and $1 million
per year for operating costs.
Fuel Fabrication. All fabrication plants can be treated as being essen-
tially similar as far as radioactive wastes and waste treatment are
449
-------
concerned. The principal wastes are airborne participate which are con-
trolled with filtered ventilation systems, and scrap which must be dis-
posed of.
The average capital and operating costs for air treatment systems for a
5 ton a day plant are $2.2 million and $93 thousand per year, respec-
tively. The average cost for water disposal is estimated at $19,000
per year. Capital costs for water disposal systems are estimated at
$224,000. Applying as low as practicable releases to the fabrication
industry could impose some additional control mechanisms and costs; how-
ever, no estimates have been made of these at this time.
Transportation. Since the nuclear fuel cycle has numerous industrial
stages between the extraction of ore to deposit of radioactive wastes
there are numerous steps required in transporting the materials between
these various stages. Railroads are the primary mode of transporting
nuclear materials in the nuclear power industry with shipments by truck
being the secondary mode. The principal means of water transportation
would be transcontinental freighter. In some steps of the process, the
shipments may not go off-site.
The quantities of nuclear materials that will be shipped in these steps
for the years 1975, 1980, 1985, and 1990 were estimated. In general,
except for accidents, the impacts of shipments of nuclear materials are
identical to transportation of any other material. It has been assumed
that no releases occur during the transport of nuclear materials between
process steps of the fuel cycle simply because we have assumed normal
operational conditions. The impact of accidents has not been evaluated
since this would require a statistical analysis of the frequency and
severity of accidents for similar types of materials.
Experience to date indicates that the regulations now applicable assure
a trivial impact to the environment. The AEC and others are currently
conducting statistical evaluations of the frequency and severity of
accidents and the attendant risk for shipments of spent fuel, recovered
plutonium and wastes. Assuming an accident would occur, a ranking of
materials from most hazardous to least hazardous was made. This rank-
ing is based simply upon the relative toxicity and chemical stability
of the compounds. No judgment regarding the effectiveness of the con-
tainer or shipping regulations was factored into the ranking. Plutonium
(nitrate or oxide form) represents the most hazardous material with
spent fuel and radioactive wastes being ranked second and third, re-
spectively.
Nuclear Energy Demand and Nuclear Fuel Requirements
Nuclear Energy Demand
In the time period between 1975 and 1990, nuclear energy will be
450
-------
consumed by the electric utilities. Therefore, the demand for nuclear '
energy may be estimated from the total demand for electrical energy, the
economic forces that determine the relative loading of conventional and
nuclear generating stations and the availability of the nuclear stations.
The data accumulated on the domestic electrical energy demand for the
years 1965 to 1970 can be closely represented by a constant growth rate
of 7.18 percent per year.(v"5) Therefore, this linear growth rate was
used to project the demand for electrical energy up to 1980, which is
shown in Figure V-2. The projection after 1980 is more difficult. The
markets which are now enjoying the most expansion (such as air condi-
tioning) may be approaching saturation and the electrical industry growth
may settle to a value near that of the gross national product—say about—
4 percent per year. On the other hand some new market such as the elec-
tric car may develop and the growth rate may be greater than the 7.18
percent per year rate. For the purposes of this study we have used re-
sults from the updated EQUIPS study(V-l) in which a growth rate of 6.6
percent per year from 1980 to 1990 was assumed. This projection is not
inconsistent with other previous projections.^""'^"'' The analysis
in this study considers only domestic needs and the associated emissions.
Estimates of nuclear demand and supply for the rest of the free world
can be found in Reference V-7.
The segments of the demand for electricity for nonnuclear and nuclear
power sources and the breakdown of nuclear into Light Water Reactor
(LWR), High-Temperature Graphite Reactor (HTGR), and Liquid Metal Fast
Breeder Reactor (LMFBR) generating stations was determined using the
linear programming model of the U.S. power economy(v~2) developed for
the USAEC. Results of the calculation also are plotted on Figure V-2
along with the actual generation using LWR's for 1968 to 1971.'. Demands
by reactor type for four intervals are given in Table V-4.
TABLE V-4. ENERGY DEMAND
Gigawatt Years of Energy
Produced In
1975 1980 1985 1990
Nuclear
Station Type
LWR 50 100 170 260
HTGR 0.25 7 40 90
LMFBR 0.2- 0.5 30
Total Nuclear 50.25 107.2 210.5 380
Total Nonnuclear 215 268 305 325
Total Energy Demand 265 375 515 705
451
-------
1000 * '
4
1 —
f
100
J
?-
.«* '—
s
10
I.
t_
1.
i_
i_
•V.V.t-i =TI.-^^- -:-"---! -.T'-^T-l •• -^ M-:~--.: .:.:•...-!•. :;.-^u- :..:::•! — ..|v.-r.;!r (-• .T.t-r
j ! 1- } — -_--. _ ,
-:
L t ' . i
i i i
:
- i t
1 1 .
= . •;•.:'.
-..- ii.-T-|--T-.-. ^
— -^. ; 1 1 .
1 1
, • I
! -r*---, .
: — y< \t/. — i 1
\ / s. • • - •
' / i ! I'D
^ S ^
• 1 • ' ' - ' /^/' ' ' '
I • * i • • i • • ; : . . - i • • ' \ // • • i ' • '
. ' • t » • // ... ' . .
1
1
/
T-i_=--t-:^ _-•---: :.-.— --i.-— ;.-T :^. ^-i- . i- . _ . ! ii-_ - ^xj .-..--• : : .-.=-: l-'-'-f".— !--':VK-" i/"—:.".-^ •':.--"--•:
1 I — ^ — • -„ .- -H -----J/--4- T-TJ--
»
• 1 ;
1 ' •
— : — :_: ."; =.--.-• /-•-^'Z-\ '-=. -_:i_j-
1 L ; /j ; J ir *./_ — .
=:— . r.L>J.:---JnrJ=---:r=:r/™ • -^-- -->,--=----> I ---^ -'«- //iv- ™i f—_-- -
| : ,
— M— r^-r—
. 1 . . • .1
. i . • . | . • . : ,
! • • i <
•ss*:-5 •-";.".— ~!"--v~-7~r~—'-~!—; i —-•:•- — —--:—=-=-i; • -" ••"•!•/
—h.-^-
^7-— f-^^l— — -
— in 1 ! — / — j •- -j
— ' — 1 LIlFitF/ —
/ 1 / — i
_f -/ 1
/ /
1
-^^-j^T-ri-j.-yrv^; ^^^J^J^S^^I^^^^^^IiS^^S^glJ^v^if^fji;;;;:^: -"-•.
s^iie^M^iiLsS-- i.-^-^issite^- ,lq
i . • •
1
1 • '
! i ' 1
^^S-=i=EgE-bs-|:j~!
r _:.-,.-._.: -:.-; :-r;
1 — / 1 1 1"
,/r\
i/ • '
• /
. ./ .
60 65 70 75 86
i
/ • 1
i
85 90 95
FIGURE V-2. ELECTRICAL ENERGY DEMAND (PRODUCTION)
452
-------
As of August 15, 1972, the American Nuclear Society (ANS)^V~8^ reported
nuclear generating capacity built, under construction, or committed.
They also estimated that an additional 21.7 GW (Gigawatts = 109 watts)
would be committed in the near future. If these construction schedules
are met, the installed capacity in 1975 and 1980 would be as follows:
ANS Estimates of Installed
Nuclear Capacity in Gigawatts
Type 1975 1980
LWR
HTGR
Comparison of. these data with Table V-4 indicates that it would be pos-
sible for the LWR's to meet the indicated demand, but that several HTGR's
must be sold in the next year or so if the potential demand indicated by
the model is to be met. It also is possible that construction schedules
will not be met, so Table V-4 can be regarded as the upper estimate of
the demand range to 1980 and probably can be regarded as the upper esti-
mate to 1990 assuming no major new markets for electricity.
It should be noted that the nonnuclear share of the demand only increases
slightly from 1985 to 1990 on Table V-4. This occurs even though the
nonnuclear capacity increased substantially, since the nuclear plants
are expected to be essentially base load plants and the nonnuclear plants
will be phases out of base load operation and used to satisfy seasonal
and daily peaks. It is expected that much of the new nonnuclear construc-
tion will he of the "mid-range" type designed to operate efficiently 12
hours a day, 5 days a week, in the 1980 to 1990 time period.
Nuclear Fuel Requirements
The linear programming model also produces a complete list of material
flows. These flows reflect the appropriate lead or lag times for each
step of the process to meet the projected electrical demand. For this
reason, it is necessary to project the electrical demand well beyond the
period of interest. In this case a growth rate of 5.6 percent per year
after 1990 was used. This assumption has a strong effect on the flows
in 1990. For example, since nuclear fuel may stay in a reactor for
three or four years, the amount of fuel required and its enrichment de-
pends on projecting up to four years in advance the energy that a reactor
will produce. The l^Og that will ultimately be a constituent of a par-
ticular batch of fuel must be purchased two years before that batch of
fuel is charged to a reactor to provide time for the necessary process
steps. Thus, a 1)303 requirement depends on estimating the electrical
demands in the interval from two to six years in the future. The calcu-
lated material flows are given in Table V-5. The plant capacities
listed in Table V-5 are plant nameplate values. The values of energy
produced listed in Table V-4 are these values times the plant availability
factor. The rest of the table lists the material flows from 1)303 and Th02
requirements to recovered plutonium after reprocessing.
453
-------
TABLE V-5. CALCULATED MATERIAL FLOWS
i
Requirements
Material
Plant Capacity In -
GW
11303 Requirements -
in tons(b)
Th02 Requirements -
in tons
Separative Work In -
Fuel Fabrication
in MT
Fuel Reprocessed
in MT
Plutonium Recovered
LWR
HTGR
LMFBR
LWR
HTGR
LMFBR
HTGR
LWR
HTGR
LMFBR
LWR
HTGR
LMFBR
LWR
HTGR
LMFBR
In MT
1975
61
.33
0
20,000
30
3
15,200
20
3,100
4
1,300
3
1980
138
9.33
.3
31,500
2,500
400
24,500
2,100
5,400
270
3
3,400
(d)
3
31
1985
225
56
.7
49,000
9,500
1,000
28,900
8,100
9,000
800
7
5,500
(d)
7
63
1990
357
119
40
73,800
17,000
1,400
2,200
42,600
14,600
600
14,100
1,800
1,600
10,100
820
, 540
150
0
(a)* GW meaning gigawatts or 10 watts.
(b) Short tons (2000 #).
(c) MT meaning metric tons.
(d) Commercial reprocessing to start in 1986.
454
-------
Uranium Mining
Technology Summary
Uranium occurs throughout the world in both the lithosphere and in the
oceans. Uranium mining operations involve extracting the crude ore
from uranium mineral deposits and transporting the ore to the mill.
Nearly all of the domestic ore deposits and known reserves occur in
sedimentary formations of the Jurassic and Tertiary periods. About
half of the deposits occur in the Colorado Plateau region, principally
in the Ambrosia Lake district in northern New Mexico. The other half
occur in sedimentary formations of the Jurassic and Tertiary 'periods.
About half of the deposits occur in the Colorado Plateau region, prin-
cipally in the Ambrosia Lake district in northern New Mexico. The other
half occur principally in the Wyoming Basin district in central Wyoming.
About 10 percent of the deposits occur in the Colorado Plateau region,
principally in the Ambrosia Lake district in northern New Mexico. The
other half occur principally in the Wyoming Basin district in central
Wyoming. About 10 percent of the reserves are scattered throughout the
other western states. Most of the uranium reserves are shallow; the
median depth is 350 feet, and 90 percent are less than 1,000 feet.
The average grade of ore is 0.2 percent 11303, and the average deposit
contains 3,000 tons U30g.
Both underground and open pit methods are used. Underground mining is
used for the small ore bodies near the surface and for large ore bodies
over 400 feet deep. Open pit mining is used for large ore bodies less
than 400 feet in depth. In 1969, the average underground mine produced
50 tons of 0303 annually and employed 18 people. The average open pit
mine produced 430 tons of U^Og annually and employed 68 people.
Currently, 57 percent of the V^OQ is mined underground and 41 percent
is open pit. The remaining 2 percent comes from other sources such as
by-products of vanadium and thorium mining. In the future the USAEC
stockpile could likewise contribute; a constant 2 percent from all other
sources is projected in the future and is not considered in che uranium
mining impact. However, data on the ore reserves (that which is recov-
erable at a cost under $10/lb U30g) indicate a trend, showing 56 percent
of the reserves should be mined open pit and 44 percent underground be-
cause the known deposits favor open pit mining techniques. These data
suggest that future uranium mining will be more oriented towards open
pit mines. An estimated breakdown for each five-year interval from
1975 to 1990 is given in Table V-6. Using these fractions and the total
1*308 requirements, throughputs for each mining process for the years
1975, 1980, 1985, and 1990 can be obtained and these are given in Table V-7.
An effluent flowsheet for uranium mining is shown in Figure V-3. The
process involves simply removing the ore from the ground and placing
it in the vehicle used to transport it to the mill.
455
-------
'iABLE V-6. ESTIMATED DISTRIBUTION OF URANIUM EXTRACTION
Year
1970 Data
1975 Estimate
1980 Estimate
1985 Estimate
1990 Estimate
Underground
57
55
50
45
40
Percent
Open Pit
41
43
48
53
58
Other
2
2
2
2
2
TABLE V-7. SUMMARY OF URANIUM MINING THROUGHPUTS
1975 1980 1985 L990
1)305 Requirements by Plant Type, tons
LWR 20,000 31,500 49,000 73,800
HTGR 30 2,500 9,500 17,000
LMFBR 1,400
Total U30g Requirements, tons 20,030 34,000 58,500 92,200
Amount Underground Mined 11,017 17,000 26,325 36,880
Amount Open Pit Mined 8.-614 16,320 31,005 53,476
Amount Other Processes 400 680 1,170 1,844
456
-------
Untreated
Residuals
Radon
Participates
Open Pit
Mining
Groundv/ater
in
Receptors
Earth
Streams
Underground
Mining
Receptor
Air
Overburden
to
Mine Dump
Receptor
Earth
Output
Uranium Ore
Untreated
Residuals
Radon
Participates
Receptor
Air
Waste To Mine
Dump Or
Backfill
Receptors
Earth
FIGURE V-3. URANIUM MINING
-------
Emissions
Environmental parameters would include land use, water usage and con-
tamination, the usage of other resources in mining, construction of
access roads and power Lines, dumping of waste rock, and air pollution.
The potential magnitude of each of these parameters is discussed in the
following paragraphs.
Air. Surface air pollution is apparently no concern. The radon pro-
blem is confined to miners in underground mines, and atmospheric dilu-
tion is sufficient above ground.
Water. Potential water usage, withdrawal, and contamination during
uranium mining are difficult to estimate. Some ore deposits are in
active aquifiers so some additional leaching may occur when the deposit
is disturbed. Other deposits are in impermeable strata so this affect
would not be present, but some waste rock brought to the surface may con-
tain a small amount of uranium and its daughters. This rock could wea-
ther and contaminate surface waters. No data were immediately available
to quantify these affects.
Land. Most mines are located near mills, probably within ten miles.
If half this distance is traveled on main arterials, then about five
miles of access road would be required per mine. Power lines would be
required at the mill site so that, at most, ten additional miles of
power transmission line would be required per mine. Since mines tend
to be clustered, these estimates would tend to be high.
Waste rock is very high in uranium open pit mining, running about 30
cubic yards per ton of ore. In underground mining, the waste rock
would be much lower—one cubic yard or less per ton of ore.
Land requirements for underground mines would probably average less than
ten acres of cleared area for the surface buildings and mine dump for
each mine. The mine property and adjacent claims, however, would cover
several thousand adjoining acres. The average open pit mine would re-
quire an estimated 400 acres for mining and stripping the overburden.
Summary of Emissions. Assuming (1) uranium mining practices follow
the current reserve data, (2) a homogeneous linear production function
of the first degree, and (3) an average mine life of 20 years, we can
express the potential emissions in terms of tons of U^Og consumed as
shown in Table V-8. These data are combined with the 1)303 throughputs
from underground and open pit mining (Table V-7), to give the summation
of incremental emissions for the 5-year periods from 1975 to 1990. These
are given in Table V-9 for each mining process and are added together
(net columns) to give the total incremental emissions.
Land used in open pit mining could be partially reclaimed during the
mining period by covering waste rock with topsoil and planting a cover
crop. After the ore body is exhausted, the entire land area could be
458
-------
reclaimed by refilling and planting. In underground mines the waste
rock could be partially disposed of by backfilling mined out stopcs.
The incremental impact of uranium mining operations on land usage is
shown in Table V-10; it is assumed that the widths of land affected by
transmission lines and access roads are. 20 and 50 feet, respectively.
TABLE V-8. POTENTIAL ENVIRONMENTAL IMPACT OF URANIUM MINING
(Data expressed as quantity per ton
Parameter
Underground Mining
Open Pit Mining
Surface Area Affected
Access Roads
Transmission Lines
Waste Rock
Air:
Particulates
Radon Gas
Water:
Deposit Leaching
Waste Leaching
0.01 acre
0.005 mile
0.01 mile
450 cubic \ards
No data available
No data available
No data available
No data available
0.05 acre
0.0006 mile
0.001 mile
14,000 cubic yards
No data available
No data available
No data available
No data available
TABLE V-10. SUMMARY OF INCREMENTAL LAND USAGE FOR URANIUM MINING
Transmistion Lines, acres
(20 ft wide)
Access Roads, acres
(50 ft wide)
1975
288
365
1980
452
575
1985
713
913
1990
1090
1316
Mine Surface Area, acres
Total Acres
540
1193
986
2013
1813
3439
2674
5080
It is assumed that mining operations have a negligible affect on the
concentration of radioactive isotopes in water. However, if it is de-
termined that there is an increase, the water could be collected and
treated. In the case of ore deposits in an aquifier the treatment would
459
-------
TABLE V-9. SUMttKT 0? ORASHM HZNBtO IMPACTS
Impact
Land
• Surface area,
acres affected
- Access roads,
miles affected*
• Transmission
MJ
no
55
no
1975
Q._P.M.-rt
430
5.2
8.6 .
Net
540
60.2
118.6
• U.H.
170
85
170 .
1980
P.P.M.
816
9.8
16.3
Net
986
94.8
186.3
U.H.
263
132.
263
1985
"•-»-__•_,
1550
18.6
31.0
f
Net
1813
150.6
294
U.H.
369
185
396
1990
Q.JVH.,
2674
32.1
53.4
Net
3043
217.1
449.4
lines, miles
affected**
- Waste rock. 4.95x10* 120.6xl06 125x10* 7.7x10* 228.5x10* 236x10* 11.8x10* 434.1x10* 446x10* 16.6x10* 748.7x10* 765x10*
cubic yards
Air
. Parttculates No Data Available
. Radon emission ' No Data Available
Water
- Deposit leaching No Data Available
- Waste leaching No Data Available
t U.H. • Underground mine.
ft O.P.M. • Open pit mine.
* IMdth of roads not Included. •
•* Width of transmission lines not Included.
-------
be applied to Che effluent from the dewatering pumps. In the case of
deposits in a dry area, any water that contacted the ore would first
have to be collected and then treated.
Control Mechanism Costs
For underground mining operations, atmospheric dilution of radon gas
and particulates is sufficient and does not constitute a problem in the
atmosphere. For surface mines, except for rare inversions, radon gas
does not constitute a problem. Even this occurs only at the bottom of
the open pit mine. Dust from the mining operation can become a nuisance
hazard when mining uranium ore in some formations. There are many effec-
tive and inexpensive ways of eliminating the dust problem. Thus, no
additional costs associated with minimizing the environmental emission
of uranium mining have been considered.
Uranium Milling
Technology Summary
Uranium milling operations involve the extraction of uranium from ores.
Generally, milling facilities are separate from mining operations and a
single mill normally processes the output of a number of mines. The
uranium-bearing ore, as it is delivered to the mills, may have a uranium
content of from O.I to 2'percent (expressed as 1)303) and generally aver-
ages about 0.20 percent. This uranium is present primarily as 11^38
(99.27 percent) and U235 (0.71 percent), both of which are radioactive
parents of long chains of radioactive daughter products. The majority
of the ores delivered to the mill contain the daughter elements in
secular equilibrium; i.e., the daughters are being formed at the same
rate at which they are decaying. Among these are the longer lived
daughters radium-226, lead-210, polonium-210, and thorium-230, and the
short-lived gas radon-222.
The crude ores delivered to the mill are crushed, ground, and leached
with a suitable solvent, either a sulfuric acid solution or a sodium
carbonate solution, depending on the chemical composition of the ore.
'The resulting solutions, containing the uranium and other soluble com-
ponents of the ore, are first physically separated from the insoluble
portion of the ore, or gangue, then purified by solvent extraction or
ion exchange techniques, and finally concentrated by chemical precipi-
tation and filtration. The uranium product, the yellow-colored filter
cake, is washed and dried before being shipped to feed material centers
as "yellowcake". The 1)303 requirements by recovery process for the
years 1975, 1980, 1985, and 1990 are given in Table V-ll.
461
-------
TABLE V-ll. SUMMARY OF URANIUM MILLING THROUGHPUTS
1975 1980 1985 1990
UsOs Recovered, tons
Acid Leach Process^3)
Carbonate Leach Process'3'
Average V^OQ Content of Ore, %
Average Processing Loss, %
Total Ore Processed, tons
Acid Leach Process
Carbonate Leach Process
20,000
15,200
4,800
.2
5.2
8xl06
2.5xl06
34,000
26,000
8,000
.2
5.2
14x1 O5
4xl06
58,500
45,500
13,000
' .2
5.2
.
24xl06
7xl06
92,000
70,000
22,000
.20
5.2
37xl06
llxlO6
(a) No separate considerations were given for milling processes other
than acid leaching and carbonate leaching, such as heap leaching,
in situ leaching, or mine water treatment.
Emissions
Environmental parameters in uranium milling operations include land use,
water use and contamination, and effluent releases to the air. A waste
effluent flowsheet for uranium milling operations is given in Figure V-4.
The estimated distribution of radioisotopes in the milling process for
producing one kiloton jof UjOs is given in Table V-12. The contributions
of U23S, Ra226> Pb210> po210> Th23°, and Rn222 are included in the esti-
mated total release of radionuclides because of their relatively strict
maximum permissible concentration limits in water, and their toxicity.
While the composition of ore deposit varies widely, and will probably
decrease in quality as the known deposits continue to be worked, for
this study the available ore has been assumed to have an average U$OQ
content of 0.20 percent. Assuming a 5.2 percent processing loss, and
an average activity of the ore of 515 Ci of U2^8 per ton of ore,
5.27x105 tons of ore, containing 270 Cu of U2^8 and each of daughter
elements of interest, have been assumed to be processed to recover one
kiloton of
Air. The short-lived gas radon, a decay product of radon, a decay pro-
duct of radium, is probably released from the ore during the crushing
and grinding steps and is routed by the mill ventilation control system
to the gaseous effluent stack. Subsequent to the milling operations,
radon continues to be formed in the tailings piles as the radium in
the waste piles continues its normal decay. Air erosion of the tail-
ings accumulations with the subsequent dispersal of the radioisotopes
fixed in the gangue is minimized by leveling and covering the tailings
pile with suitable earth and vegetation covers.
Water. The bulk of the radioisotopes, other than uranium, that are
contained in the original ore remain in the gangue which is stored in
462
-------
s
IN-PUT
Uranium Ore
RECYCLE
Uranium Ore
dusts
OUTPUT
PROOUCTIQ.N
Uranium extraction
bHU.>s_l( L i I DUALS
Perticu~lat.es
Dissolved redioisoto
Solids
Gases
es
llirE?i:/\L U1SPOSAL
Pirticulitcs
Dtssotvcd redlolsoto
Solids
UNTREATED RESIDUALS
Radon gas
_L
>es
EXTERNAL CONTRACT
DISPOSAL
None
TR-ATKCtlT
Just eoTlectToii
:hemical prc-cip1tatio|T'
Settling ponds
Rb'CEPIQRS
Air
JL
TREATED RESIDUAL
TR/VISFLR
Collected dusts
REOPT(iRS_
and-Earth iir.poL-ndmenjt
effluent
FIGURE V-4. URANIUM MILLING
-------
TABLE V-12. DISTRIBUTION 07 RADIO ISOTOPES UJ URANIUM KILLING PROCESSES
FOR PRODUCING OSS KILOTON OF UO FOR ALL YEARS
Add loach Process - C1 (
-------
tailings piles. The very small amounts of seme radioisotopes that are
leached from the ore along with the uranium are contained: (1) in the
raffinate from the purification step, (2) in the barren solution from
the uranium precipitation step, and (3) in the yellowcake product. The
raffinate and barren solutions are chemically treated to precipitate the
radioisotopes, and are discharged with the gangue to the tailings piles.
The aqueous solutions discharged to tailing or slime ponds are largely
dissipated by evaporation or by seepage. Any outfall of such liquids
into natural waters is monitored for its radioactive content. Restric-
tions on the release of radionuclides in liquid wastes necessitate
cither (1) recycle of clarified liquors with limitation of fresh water
intake or just offset evaporation and seepage losses, or (2) treatment
of effluents flowing off-site to precipitate and retain these nuclides.
The latter expedient is now used in only three mills.
Tailings comprise an assortment of particle sizes ranging from slime to
sand. They are mixed with water and pumped to the tailings ponds whore
the solids settle, and the water is recycled. The sands tend to segre-
gate as the stream is delivered to the pond, leaving the liquid and
slime to collect in low-lying areas. Abandoned tailings piles are
stabilized against wind and water erosion.
land. Land requirements for a uranium mill include surface area for
production facilities and waste piles. Since we do not have estimates
of these requirements readily available, we will neglect these factors
in this study. There is an impact from earth impoundment of radioiso-
topes.
All solid and liquid wastes have been assumed to be discharged to tail-
ings ponds for storage. The water content of the ponds at most mills
will remain constant by either solar evaporation or seepage into the
ground. Where seepage is possible, radionuclides will remain fixed in
the soil beneath the pond and will not migrate with the water. A small
percentage of mills will discharge excess pond waters to either natural
waterways or deep well injection sites after meeting established stand-
ards for effluent waters.
Summary of E-nissions. The uranium throughputs in the mill (Table V-ll)
are combined with the distribution of radioisotopes on the uranium mill-
ing processes (Table V-12) and summed to give the total radioisotope
effluent discharged to air, land, and water receptors. These values are
given in Table V-13 for the years 1975, 1980, 1985, and 1990.
Control Mechanisms and Costs
Processing of the ores results in airborne dust plus released radon gas
during grinding operations and liquid wastes containing uranium during
the dissolution of the ores and subsequent concentration of the uranium
oxides. Dusts and radioactive gases created during grinding can be con-
trolled by construction of appropriate ventilation hoods and by filtration
465
-------
of the effluent air. The radon gas passed through the air purification
systems and is discharged with the atmosphere whereby it is dispersed.
It would be possible to absorb the radon on activated carbon or to liquefy
It, but such systems would be very expensive because of the large quanti-
ties of air accompanying the radon. Du.sts removed in the ventilation
system could be sent to the dissolution equipment and would not create
a separate disposal problem.
TABLE V-13. SUMMARY OF URANIUM MILLING EMISSIONS
Radioisotope Discharge to Receptors (Annual)
Total Curies of U238, Rn222, Ra226, Th230,
1975 1980 1985 1990
Acid Leach Process:
Air 4,000
-------
Thorium Mining and Milling
Technology Summary
The past and current demands for thorium have been small and have been
almost entirely for nonenergy needs. However, increased use of thorium
in high-temperature gas reactors is expected in the near future and could
result in a factor of twenty or more increase in the milling and refining
of thorium ores by the year 1990.
Aside from a brief period of stockpiling by the AEG prior to 1962, the
production of thorium has averaged about 110 tons (expressed as thorium
oxide, Th02) per year. The principal uses have been for the manufacture
of incandescent gas mantles and magnesium alloy additives. Assuming a
modest growth rate of about 3 percent per year for these noncnergy uses
of thorium, an annual requirement of about 200 tons can be foreseen by
the year 1990. However, based upon the forecast of commercial develop-
ment of thorium fueled power reactors, the annual dompstic requirements
for reactor grade thorium oxide alone has been estimated at approxi-
mately 2000 tons by the year 1990.
Thorium Mining. Historically, most thorium has been recovered as a by-
product in the chemical processing of monazite beach sands for their
rare earth oxide (REO) content. Monazite is a naturally occurring min-
eral, essentially a phosphate of the rare earths, cerium and lanthanum,
in which thorium and the yttrium earths substitute for cerium. In addi-
tion there are usually present small to moderate amounts of uranium,
iron, aluminum, calcium, magnesium, silicon, titanium, and zirconium.
Unlike many other rocks and minerals, monazite is not soluble in water,
and so is not destroyed during erosion processes. Instead, the pulver-
ized monazite accumulates, along with other erosion resistant minerals,
as nand on river bottoms and ocean beaches. While natural separations
processes have created some sand deposits that have been almost pure
monazite, the domestic sources arc mixtures of many erosion resistant
minerals. These deposits are generally mined by placer mining methods,
and separated into relatively pure mineral fractions by froth flotation,
tabling, gravity separation, magnetic separation, or other ore benefici-
ation techniques. These preliminary separations arc generally accom-
plished at the mine site with the tailings being returned to their
natural environment. Since there arc no crushing or grinding operations
and no chemical treatments during this separation, there is no increase
in radioactive release to the environment. With proper controls there
is no long-term impact on air, water, or Land.
Thorium Milling. The upgraded ore is chemically processed to effect
further separation and purification of the desired elements. Historic-
ally the initial treatment has been to grind the ore and then solubilize
it, either with a hot concentrated sulfuric acid treatment or a hot con-
centrated sodium hydroxide-hydrochloric acid treatment. Careful step-
wise neutralization and filtration of the solubilized ore then results
467
-------
in the removal of the insoluble gangue materials and the fractional
precipitation of relatively pure fractions of thorium, uranium, and
rare earth compounds. The crude thorium fraction is then redissolved
and purified by fractional precipitation, fractional crystallization
or solvent extraction.
However, for the continuous, large-scale production of thorium of
reactor-grade quality, solvent extraction processes utilizing solubil-
ized ore solutions directly are highly attractive. Patterned after
uranium solvent extraction processes, several thorium solvent extrac-
tion processes have been investigated, some through the pilot-plant
stage.
The refining of the concentrated monazite ore will probably utilize a
hot-caustic ore digestion process and after removal of the resultant tri-
sodium phosphate solution, the metal hydroxides in the filter cake will
be dissolved in nitric acid. A multiple step, solvent extraction pro-
cess will then be used to separate the thorium, uranium, and rare earth
fractions from one another and from any undissolved gangue materials.
It has been assumed that 100 percent of the thorium, uranium, and
daughter elements will be solubilized by the digestion process. It has
been assumed that about 3 percent of the uranium will'be lost to the
filtrate when the hydrous oxides are filtered from the trisodium phos-
phate solution. It also has been assumed that approximately 0.1 per-
cent of the thorium and uranium will be lost to the solvent extraction
waste solution in the separation process. Finally, it has been assumed
that 100 percent of the radium will appear in the solvent extraction
waste solution.
The uranium nitrate fraction will enter the uranium fuel cycle for even-
tual fabrication into reactor fuel elements. This source of uranium is
only about 0.1 percent of the total uranium processed for reactor use
and its contribution is included in the Uranium Milling section of this
report.
It has been assumed that the thorium nitrate fraction from the solvent
extraction process will be converted to the oxide in the milling plant
and shipped to the fuel fabricator as the oxide. It has been assumed
that no radioactive wastes will be generated by this conversion.
The trisodium phosphate fraction, containing approximately 100 ppm
uranium will be utilized as a crude TSP source without further uranium
separation.
The requirements of thorium oxide (Th02) for the years of interest are
shown in Table V-14. While the composition of ore deposits varies widely,
depending on the location of the deposit, for this study it has been
assumed that domestic deposits will be utilized and concentrated at the
(nine site to about 90 percent pure monazite. The average composition of
the ore concentrate has been assumed to be:
468
-------
Percent
Thorium (as Th02> 4
Uranium (as U02) 0.2
Gangue 10
The estimated distribution of radioisotopes in the milling process for
producing one ton of Th02 is given in Table V-15. In the decay of the
parent thoritim-232 to stable lead-208, 10 other radioisotopes are formed.
Because of the extremely short half-lives of most of these radioisotopes
only the parent thorium-232, radium-228, and thorium-228 have been con-
sidered for their environment.nl emission. Then, because of the rela-
tively small quantities of uranium associated with natural thorium, only
the parent uranium-238, nnd the very hazardous daughter, radium-226,
have been considered of the radioisotopes formed in the normal decay
of uranium-238. The daughters have been assumed Lo be in secular equili-
brium with the parents. The half-lives and specific activities of these
isotopes have been assumed as follows:
1/2 Life,
Isotope yr Ci/lb g/Ci
Th232 1.39 x 1010 5.03 x 10"5 9.01 x 106
Th228 1.91 1.22 x 10"3
Ra228 5^7 3 63 x 10~3
U238 4.51 x 109 1.51 x 10"* 3.00 x 106
Ra226 1.62 x 103 1.02
TABLE V-14. SUMMARY 07 Th02 MILLING THROUGHPUTS
1975 1980 1985 1990
Nonenergy Uses 130 150 170 200
Reactor Use 0 270 1000 2100
Total 130 420 1170 2300
Emissions
Environmental parameters in thorium milling operations include land use,
water use and contamination, and effluent releases to the air. For the
purposes of this study, it is assumed that the mining of thorium does
not result in any environmental impact. The process waste flowsheet
for thorium milling operations is given in Figure V-5.
Air. Radon gas is released during processing, presumably at the hot-
caustic digestion step; however, the equipment is large and the gas
volume small providing time for most of the gas to decay since the half
469
-------
TABLE V-15. DISTRIBUTION OF RADIOISOTOPES IN THE PRODUCTION
OF ONE TON OF TM>2
Item
Gangue -
Ibs
Th02 - Ibs
Th - Ibs
Th232 .
.
Th228 -
-
Ra228 -
-
U02
U
U238 .
-
Ra226 _
-
Gi
gm
Ci
gm
Ci
gm
Ib
Ib
Ci
gm
Ci
gm
Tri-Sodium
Ore Th02 Phosphate U02
Concentrate Product Product Product
5000
2002 2000
1759 1758
8.85 x 10'2
8.0 x 105
8.85 x l(T2
1.1 x 10'4
8.85 x UT2
3.2 x 10'4
100 3 97
88 2.64 85.5
1.33 x 10-2 3.99 x 10~4 1.29 x 10'2
4.0 x 104 1.2 x 103 3.9 x 104
1.33 x 10-2
1.4 x lO'2
Solvent
Extraction
Waste
2
1.76
8.85 x 10"5
8.0 x 102
8.85 x 10~5
1.1 x 10'7
8.85 x lO-2
3.2 x 10'4
0.1
.088
1.33 x 10~5
4.0 x 101
1.33 x 10'2
1.4 x ID'2
-------
INPUT
Konazlte Ore
Concentrate
OUTPUT
Thorle - ThO,
PRODUCTION
Thortum Extraction
GROSS RLS1DUALS
Mssolvcd rcoloisotcpcs
)issolvcd inert materla
Incjissolvcd solids
Jlssolvod radloisotopcs
Ji'ssolved Inert n-.ateria
solids
UNTREATED RESIDUALS
Radon
EXTERNAL CONTRACT
DISPOSAL
U03 product
Triscdiuti phosphate
product
TREATIirta
Chemical p-cclpltatlon
Settling ponds
TREATED RCSIOUAL
TRAi.'SrER
Hone
RtCEPTORS
Air
_L
RLCLFTORS
Land - Earth Impound-
FIGURE V-5. THORIUM MILLING
-------
life is only 56 seconds. Any residual is vented. Little or no particu-
lates are expected.
Water. All liquid effluents are clarified by chemical precipitation
and impounding in settling ponds. Any water released would be analyzed
for chemical and radioactive content.
Land. The land area required for collection of solid wastes and settl-
ing ponds has not been estimated. This land area is the receptor for
essentially all of the residual radioactivity.
Summary of Emissions. The thorium throughputs in the mill (Table V-14)
are combined with the distribution of radioisotopes in the production
of one ton of ThC>2 (Table V-15) and summed to give the total curies dis-
charge to air, land, and water receptors. These values are given in
Table V-16 for the years 1975, 1980, 1985, and 1990.
TABLE V-16. SUMMARY OF THORIUM MILLING EMISSIONS
Radioisotope Discharge to Receptors
Air
Land
Water
1975
13
0
Total, Curies
Ra228, U2'
1980
0
42
0
of Th , Th
58 , and Ra226
1985
0
230
0
(a) The actual distribution of the short-lived gas
radon22^ throughout the milling industry is not
known, particularly since the ore is mined in a
pulverized state and is mechanically concentrated
at the mine site prior to chemical milling pro-
cedures. Its contribution to the air receptor
is not included in this study.
Control Mechanisms and Costs
Air. In the event better control is required the process vents may be
placed under slight vacuum to preclude direct leakage to the air.
One-thousand-fold reduction in radon activity could be obtained in a
vent system with sufficient volume to provide a 10-minute hold-up.
Costs for this increased control have not been estimated.
Water. All seepage and outflow should be monitored for radioactivity,
soluble chemicals, and solids. Fresh water input should be controlled
such that it is offset by evaporation and seepage.
472
-------
Land. The land area which is to receive the waste and fettling ponds
should be stripped of top soil and seeded if required and monitoring
wells provided. Precautions against erosion are required during use.
When a given area has received the scheduled quantity of waste it
should be re-covered with top soil and planted with a cover crop.
Costs have not been estimated.
Uranium Conversion
Technology Summary
Crude natural uranium ore concentrates, yellowcake, are converted to
uranium hexafluoride for purification to reactor-grade quality and as a
feed material for the gaseous diffusion enrichment of the b'235_u238
ratio. Two commercial facilities owned by Allied Chemical and Kerr-
McGee exist for the conversion of natural uranium ore concentrates. In
the Allied Chemical process the ore concentrates are processed directly,
after being pelletized to produce a feed material suitable for subse-
quent fluid-bed reactor systems. The concentrate is reduced with hydro-
gen to crude U02> and is followed by hydrofluorination with anhydrous IIF
to produce UF^. In these two steps, a major portion of the impurities
present in the original concentrate as volatile compounds (such as NHj,
H20, C02> etc.) or which form volatile compounds (such as S, Si, Mo, U,
etc.) are eliminated in the off-gases. The crude UF, is then converted
to UFg with elemental F2- In this step, a major portion of the impuri-
ties forming nonvolatile compounds (such as Fe, Na, Cu, Mg, etc.) are
rejected as solid ash. The small amount of remaining impurities vapor-
ized and entrained with the UFg, are removed by fractional distillation
in both high- and low-boiling fractions. These fractions and minor
amounts of scrap materials are treated for uranium recovery in a small
auxiliary scrap-recovery system with a wet chemistry technique. Cer-
tain radioir.otopes tend to build up in the fluid-bed heat exchange
materials and necessitate the periodic replacement of a portion of this
inert material. Ash wastes from the scrap recovery system and contami-
nated inert heat exchange materials arc drummed and stored for eventual
disposal. Off-gas scrubbers discharge effluents directly to waterways
in accord with applicable radiation protection standards.
The Kerr-McGee process is somewhat similar, except the crude yellowcake
is first purified by a solvent extraction process with the resulting
uranyl nitrate solution being calcined directly to UC^. Hydrofluorina-
tion and fluorination steps are similar but the fractional distillation
step is not required. Raffinate from the solvent extraction purifica-
tion is impounded in limestone-lined earthen ponds. Evaporation from
the ponds approximately equals rainfall, and pond levels are maintained
by seepage into the surrounding ground. Test well monitoring indicates
that the radioisotopes impounded are relatively immobile. Off-gas
scrubber solutions are discharged through limestone beds to waterways.
Assuming that the uranium conversion will be split evenly between the
473
-------
Allied Chemical process and the Kerr-McGec process, then the uranium
conversion requirements are as shown in Table V-17.
TABLE V-17. SUMMARY OF URANIUM CONVERSION
THROUGHPUTS
Yellowcake, tons U-jOg
Recovered, tons U
1975
20,000
17,000
1980
34,000
29,000
1985
58,500
50,000
1990
92,000
78,000
Emissions
Environmental parameters in uranium conversion operations include land
use, water use and contamination, and effluent releases to the air. A
waste effluent flowsheet for uranium conversion operations is shown in
Figure V-6. The estimated distribution of radioisotopes in converting
to one kiloton of uranium is given in Table V-18.
TABLE V-18. DISTRIBUTION OF RADIOISOTOPES IN THE
CONVERSION OF ONE KILOTON OF URANIUM
Curies
U238
Allied Chem. (1/2 kiloton U)
Ash
Scrubber Solution
TrtA *• t* M «a ^ 1-1 v i
-------
INPUT
Yellowcake
PRODUCTION
Fluon'notion
RECYCLE
*•
«sl
in
Di
INTERNAL DISPOSAL
isolved radioisetopes
Solid ranioisotopes
Solid inert material:
UNTREATED RESIDUALS
None
OUTPUT
Uranium
Hexafluorlde
GROSS RESIDUALS
Dissolved rariioisotop
Solid ra'Jioisotopes
Solid inert rraterials
>s
1
TREATMENT
Chemical treatment
Settling ponrJs
Drummed storage
EXTERNAL CONTRACT
DISPOSAL
TREATED RESIDUAL
TRANSFER
None
RECEPTORS
Hone
RECEPTORS
•Jater-Liquid effluent;
Land-Drums:! ashes ai
he;
-burtli
01 MljUIOS
FIGURE V-6. URANIUM CONVERSION
-------
into the groundwater. Well monitoring indicates that the pond contents
are relatively immobile.
Land. In the Allied process all of the uranium wastes, except the HF
scrubber solution, are recycled (for product recovery) by a wet chemistry
recovery method. Yellowcake impurities are removed in the recycle step.
Some impurities collect in the fluid-bed heat exchange material, necessi-
tating a periodic replacement of a portion of the bed. No data are
available on the volume of "inert" heat exchange material replaced yearly.
All inert wastes and yellowcake impurities are drummed and stored. HF
scrubber solutions are discharged to waterways after neutralization.
Summary of Emissions. The uranium throughputs in Table V-17 are com-
bined with the distribution of radioisotopes in conversion (Table V-18)
and summed to yield the total discharge to air, land, and water receptors
for the years 1975, 1930, 1985, and 1990. These values are given in
Table V-19. The conversion of uranium recovered from irradiated fuels
is not included in these estimates since the fluorination processes are
not established at this time. It is most probable that these processes
will be incorporated with fuel reprocessing plants and any wastes gener-
ated will probably be recycled through the reprocessing plant for product
recovery.
TABLE V-19. SUMMARY OF URANIUM CONVERSION IMPACTS
Radioisotopc Discharge to Receptors
Total Curies of U238, R226, Th230
1975 1980 1985 1990
Air
Land
Water
0
.4
0
53(a)
.7
0
1.2
0
145(a)
1.9
Control Mechanisms
Monitoring of wells adjacent to the waste ponds will reveal any exces-
sive movement of the pond contents into the ground water. After a pond
becomes full, it can be removed from service and covered with top soil
and planted with a cover crop to prevent erosion. Costs have not been
estimated for either the well installations or final entombment of the
ponds.
Inert wastes and impurities from the Allied process stored in drums
must be periodically inspected to assure that the drums have not failed.
Scrubber solutions discharged to waterways must be monitored to assure
that appropriate standards for such releases are not exceeded. Again,
no costs have been estimated.
476
-------
Uranium Enrichment
Technology Summary
Part of the uranium in the unirradiated power reactor fuel is enriched
to assays above the natural assay in the USAEC gaseous diffusion plants
(GDP's). The owner of the uranium to be enriched delivers it to the
GDP's as U?5 and receives back enriched UF6 plus (if he wants it) UFfc
depleted in U235.
At present the only commercial uranium enrichment facilities- in the
United States are the USAEC gaseous diffusion plants. These plants
have ample capacity for current enriched fuel requirements ancl are ex-
pected to have ample capacity through 1980 if the planned capacity in-
creases are completed. The required capacity increases after 1980 are
assumed to be provided by construction of new private GDP's.
The standard operation of the GDP's for commercial uranium enrichment
is expected to consist of (1) the customer delivers UFg to the GDP, (2)
the GDP enriches the UFg, and (3) the enriched UFg is delivered to the
customer. It is assumed that the GDP feed plants for the production of
UFg from other uranium compounds will not be used.
Current operation of the Oak Ridge GDP is assumed representative of all
GDP operation for enrichment of power reactor fuels. There is no feed
plant ojje in Liny at Oak Ridge--only UFg is received as feed.
The only radioactive isotopes handled at the GDP's are uranium isotopes.
In general, these appear as three waste streams: (1) leaking gases con-
taining uranium, (2) uranium cleaned from the surfaces of equipment
being maintained, and (3) miscellaneous solid wastes with uranium con-
tamination.
All waste recovery systems are justified by recovery of the value of
the uranium in the waste streams. The elimination of radiation re-
leases is a side benefit since the recovery systems would have been
installed whether or not the uranium was radioactive.
The throughputs for the uranium enrichment processes are tabulated in
Table V-20 for the years 1975, I960, 1985, and 1990. These throughputs
arc based upon a tails assay of 0.2 weight percent U2-^. All uranium
recovered during operation of the uranium recovery plant is sold as pro-
duct to feed preparation plants. All uranium discharged from light water
reactors is returned to the diffusion plants for reenrichment.
477
-------
TABLE V-20. SUMMARY OF URANIUM ENRICHMENT THROUGHPUTS
1975 19SO 1985 1990
TonnesOO of Separative Work 15,200 26,600 37,000 57,800
(a) Tonnes = metric tons.
Emissions
Environmental parameters in uranium enrichment operations include land
use, water use and contamination, and effluent releases to the air. A
waste effluent flowsheet for uranium enrichment operations is shown in
Figure V-7.
Air. Part of the uranium in the leaking gas streams is removed from the
exhaust air stream by standard air purification equipment. The recovered
uranium is stored or treated as necescary for eventual incorporation in-
to the uranium fuel cycle. A very small part of the uranium passing
through the GDP's leaks out during sampling or transfer operations, etc.,
and a small part adheres to the internal surfaces of the plant equipment.
Appropriate exhaust gases are treated to recover the uranium content,
and the uranium adhering to the equipment is recovered whenever the
equipment has sufficient resale value to justify installation of all
uranium recovery facilities solely on the basis of the recovered uranium
value. All miscellaneous solid radioactive wastes are incinerated and
the waste gases are treated before release to the atmosphere.
Diffusion plants consume large quantities of electricity for pumping the
gases through the plant. All of this electricity is converted to heat,
which is removed from the process by heat exchangers. The heat then is
either transferred to the air in cooling towers or released in heated
water to a nearby river. Insufficient information is readily available
to permit estimate of the portion of the heat discharged to air or water.
The amount of heat discharged as a result of production of enriched
uranium for the power industry is as follows:
Year Kwhr of Heat
1975 2.1 x lo}°
1980 3.6 x 10iu
1985 8.3 x 10}°
1990 1.3 x 1011
Water. The primary effluent from the uranium recovery and decontamina-
tion facility is a liquid stream containing minor concentrations of
uranium and other chemicals. This stream passes through an equalization
basin and then is discharged to a river. Although some of the uranium
may settle out in the basin, it is assumed that all uranium passes through
the basin without settling.
478
-------
UFg Feed-
Gaseous
Diffusion
Plants
Gross Residuals
(Uranium waste
stream:;)
Enriched UFfi
Depleted UF,
*•
•s»
VO
Internal Disposal
1
Treatment
(Incineration, filtra-
tion, chemical action)
Air and Uater
Receptors
(Uranium oxides and
fluorides)
Treated Residual
Transfer
Uranium
Oxides
FIGURE V-7. URANIUM ENRICHMENT
-------
Land The tails uranium is a stored product, part of which is sold
to fuel fabricators for manufacture of LMFBR blanket fuels. The quan-
tity of waste uranium is proportional to the units of separative work
produced. No waste products are stored permanently on-site. The only
land used is for the process facilities and the equalization basin.
Summary of Emissions. There are no waste treatment systems installed
solely for reducing the quantity of radioactive materials released to
the environment. All waste treatment systems would be installed any-
way to reduce other chemical releases or to prevent lo§s of uranium
values. All waste is treated.
The emissions to air, water, and land are summarized in Table V-21 for
each isotope and totaled.
The forecast releases were obtained by assuming that the amount released
is proportional to the units of separative work produced. Recent Oak
Ridge GDP experience was used as the basis. This is a conservative
assumption that probably results in an overestimate of the forecast re-
leases by possibly as much as 200 percent. New GDP's built in the future
will probably have improved seals and larger equipment capacities. The
leakage rate per unit of product generally decreases as the equipment
capacity increases. There are no releases to the land.
Control Mechanisms and Costs
Control of uranium releases to the air consists of assuring that the
purification systems on the effluent ventilation system are operating
properly. Similarly, control of uranium releases to water consist of
measuring the concentration in the effluent streams to be certain that
the liquid purification streams are operating properly. Since all of
these purification systems are justified by the value of the recovered
uranium, there is no extra cost for control mechanisms solely for reduc-
tion of the environmental emission of releases.
Fuel Fabrication
Technology Summary
Fuel fabrication may be divided into four broad groupings based on the
contained nuclear material. The LWR's require two types, U0_ using
slightly enriched uranium, and mixed UC^-PuC^ using natural uranium and
recovered plutonium. The amount of the latter depends upon plutonium
availability. The LMFBR1s use the same two types, U0£ in the blankets
and mixed oxides in the core. The other two types are used by the HTGR
Through 1985 the HTGR fuel will be a mixture of U02 enriched to 93 per-
cent U^35 and Th02- After the reprocessing plant starts up in 1986,
some elements will contain recovered uranium which is predominantly
The fuel fabrication requirements are presented in Table V-22.
480
-------
TABLE V-21. SUHKAKY 0? URANIUM ENRICHMENT IMPACTS
00
1975
Amount
Gases & Airborne Material
U234 .024
U235 2.8
U236 .081
U238 377
TOTAL 380
Liquids fi Wateroerne Material
U234 .18
U235 21
U236 .63
U238 &938
TOTAL 2950
Curies
0.144
0.006
0.005
0.126
0.281
1.12
0.047
0.039
0.932
2.19
1980
Amount
(Kqs.)
.044
5
.026
6S2
687
.34
39
2
5315
5357
Curies
0.269
0.011
0.016
0.228
0.524.
2.10
0.036
0.125
1.77
4.08
1935
Amount
(Kqs.) Curies
.07 .428
7.2 .016
.7 .044
372 .325
SSO .813
.55 3.37
56 .12
5.4 .34
7640 ,2.55
7700 6.38
1990
Amount
(Kcs.)
.12
12
1.5
..1540
1550
0.9
12
1.5
11.960
12.060*
Curies
0.710
0.025
0.095
0.514
1.345
5.51
0.75
0.09S
3.99
10.46
-------
TABLE V-22. FUEL FABRICATION REQUIREMENTS
Fabrication Requirements,
metric tons of heavy metal
Element Type 1975 1980 1985 1990
U02 - LWR
- LMFBR
Mixed Oxides of U -f P - LWR
- LMFBR
Mixed Oxides of Th -f- U2?5
Mixed Oxides of Th + U233
3,000
'
100
3.5
4,500
2
900
1
270
7/00
4.7
1,600
2.3
800
13,600
1,070
500
530
1,000
800
U0n Fuel Fabrication
£
Current fabrication plants receive UF^ and convert it to UC*2 by hydro-
lysis in water to form U02F2 and H2F2 = HF. The U02F2 is treated with
ammonium hydroxide to form ammonium diuranate which is then calcined
and reduced with hydrogen to form U02- The f luidized-bed process is
under active development and may be expected to replace the ammonium
diuranate in the near future, since capital and operating costs are
lower and waste management is simplified. In this process the UF, is
reacted rh'rpctly with steam and hydrogen in a series of beds to yield
U02 directly.
The UC<2 is pressed into pellets and sintered. The sintered pellets are
sized to very close tolerances by ccntcrlcss grinding. The pellets are
loaded into the cladding tubes which are sealed by welding. The finished
rods are cleaned to remove external contamination and assembled into fuel
elements.
The waste process flowsheet is illustrated in Figure V-8. The nuclear
fuel fabrication industry is unique in that the base value of the raw
material exceeds by about a factor of two the value added in the fabri-
cation process. The extremely high-quality standards of the industry
result in a high rate of scrap generation. In most industries this
scrnp has a low economic value and a low pollution potential; as a re-
sult, it is usually considered waste. However, the scrap UOn has a high
economic value and a significant pollution potential. Thus, it is im-
possible t6 allocate the amount of this recycle which can be attributed
solely to pollution control.
The loss of material during the fabrication step, shown schematically
in Figure V-8, is dependent on the flows through the various parts of
the process. The flows through some parts, particularly following the
U02 conversion step, are much greater because of the material recycled
internally. Table V-23 shows the projected U02 internal recycle rates
482
-------
00
Inputs
Recyclud
(uo2)
Outputs I
(fuel elerentsj
Fuel
Fabrication
,Process
"Recycle
Gross Residual
Internal
Disposal
External
Contract
Disposal
Contaminated Waste
Burial
Filter Cleaning
FIGURE V-8. U02
FABRICATION
-------
during the 1975 to 1990 time period.(v~10) These material .recycle
rates were used Lo adjust the releases to air and land. The losses to
water arc primarily from the UC>2 conversion process and were not in-
creased by the values in Table V-23.
TABLE V-23. INTERNAL RECYCLE RATES
Total Recycle. %
1975 17
1980 15
1985 15
1990 15
Emissions From UOp FLIP! Fabrication. IL should be pointed out that in
many cases no historical data were available to estimate the emissions.
In other cases, it was necessary to deduce releases from Special
Nuclear Material (SNM) licenses and their amendments. The projected
releases are even more speculative inasmuch as they usually project
current technology and do not encompass possible improvements.
Air. The amount of U02 released to air is taken from a 1966 survey of
the fiatl fabrication industry.^"11) This value is given in Table V-24.
TABLE V-24. AMOUNT OF U02 RELEASED IN FABRICATING
ONE METRIC TON OF FUEL
Grams of U02
Curies of U02
Air
l.lxlO1
2xlO-5
Water
2.5xl03
4x10-3
Land Burial
2.0x10°
3xlO'6
Water. The amounts of U02 in the waste water are also taken from this
1966 survey.^'11) This value is given in Table V-24.
i
Land. The amount of U0~ in the waste to land burial was taken from
the 1966 survey, with the exception of the volume of compacted dry
waste. It was estimated that six cubic feet of dry waste are gener-
ated in processing one ton of fuel. This estimate is based upon more
recent environmental report submittals by fuel fabricators. Waste
burial was all assumed to go to a private external contractor. While
this is not rigorously true (a small percentage of low level waste is
484
-------
buried by fabricators on their own property), the eventual disposal of
this waste to the land is handled accurately by this assumption.
Summary of Emissions. For the purpose of converting the weight of UO*
in the waste streams to curies, the following uranium assay was assumed:
Assumed Uranium Assay
Wt 7. Ci/RU
U234 0.022 1.36xlO'6
U235 2.56 5.48xlO-8
U238 97.42 3.24xlO"7
Total 100.00 1.74x10-5
The throughputs in Table V-22, increased to reflect the internal recycle
as given in Table V-23, are combined with the release rates shown in
Table V-24 to estimate releases to air, land, and water receptors. Using
the assumed assay of uranium shown above, the activity values were de-
rived and are given in Table V-25.
TABLE V-25. SUMMARY OF TOTAL RADIONUCLIDE RELEASE
[GATING U02 1
(in curies)
IN FABRICATING U02 FUEL
Air Land Burial(a) Water
1975
1980
1985
1990
0.56
0.86
1.41
2.79
0.0090
0.0135
0.0222
0.0440
13.2
19.8
32.5
64.5
(a) This material sent to external contractor for
controlled land burial
PuOo Recycle Fuel Fabrication
Plutonium oxide is always used as a mixture with uranium oxide in fuel
elements. For LWTl's the Pu02 content will range from 2 percent to 5
percent while for LMFBR's it will be 10 to 25 percent. The U©2 is pre-
pared as described in the preceding section. The plutonium nitrate
solution is converted to Pu02 by precipitating plutonium oxalate and
calcining. The oxides are mechanically mixed and the remaining steps
are as described in the preceding section. The plutonium is assumed to
have the following analysis:
485
-------
Analysis of High Exposure Fuel From Yankee-Rowe Reactor
(31,400 MWD/MT Exposure)
Activity/Amount
Nuclide Amount Ct/g Pu
Pu236 0.047 (ppm) 0.025xlO'3
Pu23.° 1.1 (wa) o.l89
61.6 0.0378
20.9 0.0472
,,, 12.6 13.1'
Pu242 3.8 0.145xlO-3
Total 100.0 Avg. 1.68
Since the activity of natural uranium is less than'l Ci/gU; it is safe
to ignore the uranium isotopes in considering the activity of PuOo-U09
fuel. Z
Thus, to get the activity released in terms of metric tons of fuel fab-
ricated, it is required to specify the plutonium oxide content in the
fuel. For a LWR, the fuel assembly is assumed to be 2.5 percent PuC^
and 97.5 percent U02- For the LMFBR the plutonium fuel is assumed to be
15 percent Pu(>2 and 85 percent 1102- These enrichments were then used to
calculate the Pud2 throughput and subsequently the amounts of Pu02 lost
during fabrication.
Emissions From PuOp Recycle Fuel Fabrication. The waste system flow as
shown in Figure V-9 is basically the same as that for U02 fuel fabrica-
tion. Again the conversion facilities from plutonium nitrate to the
oxide were assumed to be included in the fabrication plants. The ration-
ale for including "Process Recycle" is the samt as in U02 fuel fabrica-
tion and will not be repeated here.
Air. The only data available for stack emissions from a plant producing
mixed oxide fuel elements comes from the Han ford Plutonium Fabrication
Laboratory. Emissions have routinely been below the detection limit of
2.2x10"^ Ci/week. If one scales these data up to the production level
of 100 and 900 tons for 1975 and 1980, respectively, it would be con-
cluded that the release to air for these years would be less than 5 Ci
for 1975 and less than 47 Ci for 1980. For LMFBR fuel it was assumed
that the releases would increase in direct proportion to the plutonium
enrichment. Table V-26 shows the releases to air calculated per ton of
LWR and LMFBR fuel. Plutonium enrichments of 2.5 and 15 percent were
used for the LWR and LMFBR, respectively.
Summary of Emissions. The throughputs (Table V-22) increased to reflect
internal recycle, arc combined with the release rates (Table V--26) to
give the total U0~-Pu02 released. Using the plutonium content and com-
position shown above, the total activity is estimated. These values are
given in Table V-27.
486
-------
oo
External
Contract
Disposal
Contaminated Waste
Burial
Filter Cleaning
FIGURE V-9. MIXED OXIDE FUEL FABRICATION
-------
TABLE V-26. RELEASE RATES IN FABRICATION OF
U02-Pu02 FUEL
(Based on 1MT of fuel fabricated in 1980)
Air
Grains
Curies
LWR
4xlO~9
7xlO"7
LMFBR
3xlO'7
4.2xlO'6
Water
LWR
0
0
LMFBR
0
0
Land
LWRU)
A
l.lxlO2
2xl02
LMFBR
7.0xl02
1.2xl03
(a) Releases in 1980 are assumed to be 75 percent of the 1975 releases.
TABLE V-27. SUMMARY OF TOTAL RADIONUCLIDE RELEASE
IN FABRICATING U02-Pu02 FUEL
- Curies
AirLand Burial(o)Water
1975 •
1980
1985
1990
70 Ci
630 Ci
1100 Ci
2600 Ci
.2xlo5<»
1. 8xlO^(b)
3.2xlo5
7.4xl05
0
0
0
0
(a) This material sent to external contractor for
controlled land burial.
(b) Based on present and forecasted practice. These
may change appreciably if Pu waste." are required
to be reduced to a homogeneous, nonoxidizable
form before burial. This would increase the
economic incentive for chcmicnl recovery of Pu.
Permanent disposal charges could have a similar
effect.
Inspection of Table V-27 shows very low releases to air or water. The
very low allowable limits for Pu release (6x10"^ Ci/ml for soluble
pu239 in air) require multiple air filtration with absolute filters.
No planned releases are made to the water.
488
-------
U-Th Fuel Fabrication
The commercial acceptance of the HTGR concept by the power industry
means that the U-Th fuel cycle must be considered a significant source
of wastes during the period of interest.
Present plans of Gulf General Atomic call for the construction of a
large (at least 5 tons per day) integrated reprocessing and fuel fabri-
cation plant. While the design details of this plant have not been
announced, some conclusions can be made about the type of nuclear wastes
which will be generated and the time when they may be expected to be re-
leased. The proposed startup date for the new plant is not until 1986.
Even though irradiated HTGR fuel elements will be discharged in signifi-
cant quantities starting in the middle of this decade, a "U-233 buyback"
policy of the AEC allows the irradiated fuel to be stored, with a minimal
economic penalty, until the plant is ready for operation. This means
that the reprocessing-fabrication plant will probably come on stream
later than would be the case without the buyback policy; it likewise
means that the plant will rapidly build up to full capacity operation
once it does start.
The following shows both the annual and cumulative amounts of fuel ex-
pected lo be discharged from HTGR's in the period of interest:
Fuel Discharged From HTGR's
Year
1980 1985 .19_9_0
Fuel discharged in year (tonnes metal) 16 270 820
Cumulative discharged through year end 31 680 3575
(tonnes metal)
If it is assumed that the plant starts up in 1986, it would probably
not achieve full-scale operation until 1986. At 80 percent plant fac-
tor a 5 ton/day plant processes 1460 tonnes per year. Thus, it would
be capable of processing the backlog in a year or two such that by 1990
it will be processing only current production. An overview of this
transition was described by Lee and Jaye^V"^^ at the 1971 winter meet-
ing of the American Society of Mechanical Engineers. The current pro-
duction in 1990 will require the production of about 800 tons of fuel
containing recycled uranium and the remaining production of 1000 tons
will contain only thorium and enriched uranium from the enrichment
facility. The assumed composition of these two types of fuel is as
follows:
489
-------
Isotope
Th-232
U-232
U-233
U-234
U-235
U-236
U-238
Isotopic Composition of HTHR Fuc-ls
Wt % of Heavy Metal
U-235-Th Fuel
93.95
3 ppb
.06
5.54
.03
.42
Recycled Fuel
91.84
11.3
2.26
.87
4.64
.05
.34
ppm
Emissions From U-Th Fuel Fabrication. The waste flow diagram for HTGR
fuel fabrication is shown in Figure V-10. The contributions of the
various isotopes to the released activity will be a function of time
after reprocessing due to the grouch of the U-232 isotopes. For these
calculations, it is assumed that the releases to the air and water occur
a short time after reprocessing while those to land occur 6 months after
reprocessing. These contributions are shown in Table V-28.
TABLE V-28. ISOTOPIC CONTRIBUTIONS TO HTGR FUEL RELEASES
IN CURIES PER TON OF MATERIAL RELEASED
Isotope
Th-232
U-232 (and
daughters)
U-233
U-234
U-235
U-236
U-238
Total
Recycled
Ci/T
Released to
Air and Water
0.10
242
251
54
.10
.03
.001
547
Fuel
Ci/T
Released
to Land
0.1
527
251
54
.10
.03
.001
832
U- 235-Th
Ci/T
Released to
Air and Water
0.10
.06
3.7
.12
.02
.001
4.0
Fuel
Ci/T
Released
to Land
0 10
14
3 7
12
02
.001
4.1
The releases to air and water are assumed to be comparable to those ex-
pected in a Pu02-U02 plant in the fabrication plant used through 1985.
Due to the close coupled reprocessing-fabrication process in use after
1985, it is assumed that it will be economically sound to reprocess much
of the fabrication scrap which would not be reprocessed in separate
plants. It was arbitrarily assumed that the solid scrap buried would
be one-half that in a comparable Pu02-U02 plant. The plant design was
assumed to include holdup tanks and monitoring such that water release
would be nil.
490
-------
VO
External
Contract
Disposal
Contaminated Uaste
Burial
Filter Cleaning
Chemical Processing
FIGURE V-LO. HTGR FUEL FABRICATION
-------
Summary of Emissions. Tlie throughputs for HTCR fuel''(Table V-22)
assuming the isotopic composition given .ibovo is combined with the re-
lease rates (Table V-26) and the activity of the released materials
(Table V-28) to estimate the total activity released to air, water, and
land receptors. These values are summarized in Table V-29.
TABLE V-29. SUMMARY OF TOTAL RADIONUCLIDE RELEASE
FROM 11TGR FUEL FABRICATION
Year Air, Ci Land,(a) Ci Water, Ci
1975
1980
1985
1990
1
1
1
1
.086
5
15
1500
0
0
0
0
(a) This material sent to external contractor for
controlled land burial.
Summary of Fuel Fabrication Releases. The summary of releases for the
years of interest from all four types of fuel fabrication facilities
is given in Table V-30.
TABLE v-30. SUMMARY OF RELEASES FROM FUEL FABRICATION PLANTS
Year Air, Ci Land,
-------
all air is filtered at least once and the air from problem areas is £ . .-
tered two or three times. Ruilding entrances and exits may be provided
with air locks and the building air pressure may be continuously re-
corded to insure that a vacuum is always maintained. Discharge air may
be sampled with high velocity samplers to detect any leakage or by-
passing of the filters.
Water. Process water requirements in a fabrication plant are nominal
so all water is collected, analyzed, and treated if necessary before
release. *
Land. Solid contaminated waste is compacted if necessary and packaged
to minimize leakage and normally sent to a licensed waste disposal site.
Controls would consist of insuring that the container is indeed scaled
and that there is no surface contamination. Burials should not be per-
mitted at fabrication sites where surface water could leach contamina-
tion from a failed container and enter the ground uater. The remaining
control would be test wells to monitor ground water level to permit re-
moval if it should rise to the level of the waste.
Costs. Costs for on-site burial have not been estimated but the cost of
contract burial has been assumed to be $1 per cubic foot exclusive of
packaging and shipping. Packaging costs and shipping costs are assumed
to average $5 and $3 per cubic foot, respectively. Water and air treat-
ment costs were derived from BNW estimates for 1975 and scaled to the
other years based on throughput ratios to 0.6 power. These costs are
presented in Table V-31. The costs for waste control in the HTGR fuel
fabrication plant are not included since the data were not readily
available.
Power Reactor Operation
Technology Summary
A nuclear power plant consists primarily of a nuclear reactor which gen-
erates a hot coolant fluid and a turbine generator plant which converts
the heat energy in the reactor coolant into electricity. At present,
most of the reactors being built are cooled by light water and have
metallic clad fuel rods containing uranium and plutonium oxide fuels.
The high-temperature gas reactor (HTGR) is being developed and initial
operation of large commercial units is expected in 1980. By 1990 about
one-quarter of the power reactor capacity is expected to be HTGR's. The
HTGR uses spherical particles of uranium and thorium oxide coated with
silicon carbide and graphite and placed in a graphite matrix. A third
type of reactor, the liquid metal fast breeder reactor (LMFBR), also is
being developed and is exoected to be introduced commercially in 1986.
Only seven percent of the power reactor capacity is expected to be LMFBR1s
in 1990. The LMFBR is expected to have a liquid sodium coolant and a
stainless steel clad fuel rod containing uranium and plutonium dioxides.
493
-------
TABLE V-31. ESTIMATED COSTS TO CONTROL RADIOACTIVE RELEASES
FROM FUEL FABRICATION PLANTS
Cost in Thousands of Dollars
Control Component 1975 1980 1985 1990
Air Filtration - UO- Plant
Capital 6,720 8,560 11,550 17,600
Annual Operating 280 357 481 726
Air Filtration - PuO? Plant - ' :
Capital - ' 2,000 7/80 10,600 18,500
Annual Operating 100 370 530 930
Water Treatment - U0? Plant
Capital • 672 857 1,155 1,740
Annual Operating 56 71 96 145
Water Treatment - PuO? Plant
Capital 250 934 1,325 2,320
Annual Operating 50 187 265 464
Solid Waste - U0? Plant
Capital 15 20 26 40
Annual Operating 135 203 333 645
Solid Waste - Pu02 Plant
Capital 3 6 9 15
Annual Operating 7 49 87 224
Operation of pover reactors creates radioisotopes by fissioning uranium
and pluLonium and by absorption of neutron;; in the reactor components.
Most of the fission products remain in the fuel elements and arc shipped
to the fuel reprocessing plants with the spent fuel. A small fraction
escapes from failed fuel or by diffusion through the fuel cladding and
enters the reactor coolant stream.
Reactor components that absorb neutrons to create radioisotopes are (1)
fuel materials, (2) the coolant, (3) boron poison in the coolant, (4)
coolant impurities, and (5) all reactor structural components and fuel
cladding. These radioisotopes remain in the reactor or travel uith the
coolant until they are removed by (1) neutron absorption, (2) gas re-
lease in the off-gas systems, (3) coolant purification, (4) coolant
leakage, or (5) removal of reactor equipment for disposal. The reactor
waste treatment system is designed to collect all gases, liquids, and
solids containing radioactivity and treat them to minimize radiation
releases to the environment. Radioisotopes removed from the liquid and
gas streams are pacl.nged and shipped off-site for burial as solid radio-
494
-------
active wastes or arc stored in cylinders as compressed gases. Residual
radioisotopes that remain in the effluent liquids from the radwaste
system are diluted to concentrations within the standards when released.
Residual radioisotopcs in the off-gases arc diluted in ventilation air
to concentrations within the standards and released. The radioactive
waste flow diagram for power reactor operation is shown in Figure V-ll.
Forecasting future waste facility capital costs requires considerable
speculation at present. The current designs for waste systems are gen-
erally quite adequate for keeping waste releases far below permissible
limits. However, current reevaluation of radiation limits may result
in reduction of the permissible limits or of actual releases after 1980.
In this study, it is assumed that current waste equipment systems arc
representative of the equipment in operation until 1980 and that- "as low
as practical" systems will be installed on all reactors starting opera-
tion after 1980.
The total quantity of waste releases was determined by analysis of past
solid waste data and by use of the DOSIS computer code.^"'-^ Solid
waste data were collected for operating reactors and analysed to deter-
mine typical waste generation rates.
The DOSIS code computes the quantities of liquid and gaseous wastes gen-
erated and than follows them through the waste treatment facilities to
determine the amount (.hat is released.
The computations in the DOSIS code are based upon Safety Analysis Report
(Westinj'house ref. SAR,(V~W) Verplant SAR,(V-15) and Fort St. Vrain
SA1<(V-16)) (jata that represent equilibrium conditions. A follow-on
study should undertake a comprehensive evaluation of the generation of
radioactive isotopes in the coolant.
The capital and operating costs estimates for the waste treatment systems
in existing reactor plants were based on the data ir ORNL-4070.(v~ ^)
The capital costs for reactors started up after 1970 were obtained from
the CONCEPT^'"18) computer code of Oak Ridge National Laboratory of OKNL.
Emissions
There are three general types of radioactive wastes generated at power
reactors—gaseous, liquid, and solid. A treatment system is provided
for each type. Other significant environmental impacts result from heat
releases and use of land.
In order to permit completion of this study as scheduled, several simpli-
fying and general assumptions for description of the reactors and their
effects on the environment were necessary. These were:
o Defective fuel includes faulty welds which leak only gaseous fission
products and cracks which release the full spectrum of fission products.
495
-------
Fresh
Fuel Elements
Power Reactor
Internal Disposal
Irradiated
Fuel Ele-cnts
Gross Residual
(Radioisotopcs)
1
Treatment
(Storage, Filtration,
Doiom'zation,
Distillation)
Treated Residual
Transfer
(Solid Wastes)
External
Contract
Disposal
Air and Water
Receptors
(Radioisotopes)
FIGURE V-L1. POWER REACTOR OPERATION
-------
e Decommissioning will not be considered.
o Liquid wastes from HTGR's and LMFBR's are decontamination wastes,
laboratory wastes, and laundry wastes after treatment.
e HTGR waste treatment is based on the Fort St. Vrain FSAR, plus
bottling of rare gases for shipment to a permanent disposal site.
o LMFBR waste treatment is based on studies by Uestinghouse Hanford
Company.
Air. Radioactive gaseous wastes result primarily from release of fission
product gases from failed fuel elements and absorption of neutrons by the
reactor coolant and impurities in the coolant. These gases then are e-
volvcd from the coolant, particularly following pressure reductions during
reactor outages and coolant purification operations, or from condenser
vents.
The radioactivity of t.he gases is reduced primarily by decay, filtration,
condensation, or absorption on activated charcoal. Decay occurs during
storage in tanks or on charcoal beds for as long as several years. The
gases are then filtered and released through the air ventilation exhaust
system'or sent to permanent disposal in suitable containers.
The radioactive gases released to the ventilation systems travel with the
ventilation air mid are released to Lhc environment when the vcntilaLi.on
air leaves the ventilation stack. The gaser. continue to follow that air
as it mixes with the atmosphere and arc gradually diluted and dispersed
in accordance with the turbulence of the. atmosphere. Simultaneously, the
quantity of radioactivity gradually decreases as the radioisotopes decay.
Radioactive participates released to the atmosphere will gradually settle
out or be washed out in accordance with the size of the particulates and
the type weather. Noble gases generally will remain mixed in the atmos-
phere.
The radiation dose received by humans as a result of releases are depen-
dent on many variables such as quantities of radionuclides released,
locations of the people, and atmosphere conditions. The dose resulting
from operation of a reactor can be predicted reasonably accurately only
by a detailed study considering all variables for that reactor.
Water. Liquid wastes result from reactor coolant system leakage, reactor
coolant purification, and numerous miscellaneous sources, such as laundry
drains, equipment decontamination, pump seals, etc. The liquid wastes
are collected in holding tanks, analyzed for radioactivity, treated (if
necessary) to reduce the radioactivity, and then either re-used or released.
The treatment usually is evaporation or ion exchange. The still bottoms
or spent resins being handled as solid wastes.
497
-------
The released radioactive liquids generally arc released into the circula-
ting water effluent system which Llicn carries the radioisotopcs into the
receiving body. The release rate is such that the effluent is below the
maximum permissible concentration. As a general rule, the receiving body
is large enough or has a high enough continuous flow so that the radio-
isotopes are diluted to concentrations far below the maximum permissible
under government standards.
The radiation dose received by humans using the water containing the
radioisotopcs depends primarily on the radioisotopes concentrations,
the use of the \«iter, and the contact time for the human. Typical
examples of the human activities that result in dose are: .
o Drinking
o Swimming
o Consuming aquatic life
9 Boating
e Consuming foodc irrigated with the contaminated viator,
The. dose received by humans as a result of releases to water is dependent
on many variables. Again, the dose resulting from operation of a reactor
can be predicted reasonably accurately only by a detailed study considering
all variables for that reactor.
The quantity of cooling water required for removing the waste heat depends
on the reactor thermal efficiency. An LVJR re-quires about 1500 cfs of flow.
The HTGR and LMFBR probably will nctd only about 1100 cfs. Part of this
cooling water is evaporated during transfer of the heat to the atmosplicre.
Tho amount of evaporation is essentially zero for cooling wi th cold ocean
water. On the other hand, a mechanical draft cooling tower may evaporate
as much as 50 cfs.
Almost all plants built prior to 1970 used once through cooling. Host of
these plants will probably continue to utilize this cooling method. A
1969 study by Uice and Colc(v~^) estimates that the heat sink capacity
of major streams in this country would soon be used up. They broke the
country down into 9 regions as shown in Figure V-12 and accumulated stream
flow and temperature data for all rivers in the United States with minimum
monthly average flows greater than 1000 cfs. In estimating the energy
which could be added to each stream, they used the average flow in the
month witli the lowest total run off in the 1956-1966 time period. Table
V-32 compares the anticipated projected increase in heat load from electri-
cal plants built between 1965 and 1980 with the heat dissipation ability of
the streams. It can be seen that in almost every area of the country, there
is insufficient heat dissipation capability in the major streams.
498
-------
O
O
FIGISE V-12. REGIONAL DIVISIONS
-------
TABLE V-32. COMPARISON OF PROJECTED HEAT RELEASED FROM
THERMAL POWER PLANTS BUILT BETWEEN 1965-
1980 WITH THE HEAT SINK CAPABILITY OF THE
STREAMS
Region of
Country
1
2
3
4
5
6
7
8
9
Total or Average
Projected
Additional Power
Generation 1965-1980
39
69
26
74
48
110
85
74
33
558
Heat
Sink Capability
of Streams
in Region
27.64
5.80
10.96
24.36
4.56
8.60
7.68
6.36
60.48
156.44
Percent
of
Capacity
140
1190
240
300
1050
1280
1110
1160
55
(avg.)356
The growth in regions 3, 5, 6, and 9 accounts for about 40 percent of the
total increase in electrical demand. Except for region 9 cooling Lowers
or ponds vill have to be installed for almost every new plant in that
area. The remaining 60 percent of the expected growth in capacity proba-
bly will be met by a combination of plants with ocean and tower coding.
If it is assumed that one-half of these plants have ocean cooling, one
obtains a 70 percent/30 percent split between once through and close
cycle cooling for all plants aftc-r 1980. Prior to 1980, there will be a
build-up toward the 70/30 split since all plants built prior to 1970 will
probably continue to une once through cooling. In 1975, based on present
trends, about 20 pcrcp.nt of all nuclear reactors will be utilising once
through ocean cooling, 30 percent will be using cooling towers, and 50
percent will still be using once through fresh water cooling. By 1980,
the percentages using once through cooling and closed cycle cooling will
probably reverse. Based on these trends, Table V-33 was constructed to
quantify the probable quantities of waste heat sent to the various re-
ceptors during the 1975-1990 time period.
Land. Each nuclear reactor is built in an exclusion area in which un-
restricted public occupancy is not permitted. This exclusion area is
designed according to the siting requirements of 10C1TR100 which concern
safety aspects of the facility. The size of the exclusion area is de-
pendent on the reactor size, the design of plant safety systems, and the
local meteorology. For a reactor which incorporates "as low as practicable"
technology to control routine radioactivity discharges, the continuous
radiation dose received by a person residing permanently at the edge of
500
-------
this exclusion area will satisfy the limits specified iA proposed Appendix
I to 10CFR50. Actual power plant sites usually are larger than the
exclusion area and range up to several thousand acres.
TABLE V-33. RECEPTOR LOADINGS FOR HEAT DISSIPATED
FROM NUCLEAR POWER REACTORS
Gigauatts/Yoar
Receptor IS 75 1980 1985 1990
Streams and Rivers
Atmosphere
Ocean
53
32
21
72
100
60
72
253
126
72 -
504
233
The land actually occupied by the power plant is relatively small--on
the order of twenty acres. The land required by the transmission system
can be quite large, depending on the length of new line that must be
built. As an example, a 300-foot wide right-of-way will occupy about 36
acres of land for each mile of length. In many cases, though, that land
can still be used for agriculture.
Solid wastes consist of gas bottles, still bottoms, spent resins, obsolete
or failed equipment, and miscellaneous wastes, such as'paper, rags, used
clothing, etc. Most solid wastes are packaged in 55-gal.lon drums, with
or without concrete for shielding or solidification. Larger items require
other appropriate containers designed priiMari1y to prevent release of
radioactive materials during handling. All solid wastes are shipped off-
site for burial at licensed waste disposal sites.
Because radioactive solid wastes are not released to the land, there should
be no radiation dose to humans as a result of direct contact with the
radiolfsotopcs. There is a small dose, though, that results from trans-
portation of the wastes to the burial ground. As a general riilo, the
wastes are transported several hundred miJcs from the reactov plant to
one of the few licensed commercial burial grounds. The drums of waste
travel on trucks without external shielding. Persons in cars on the
highways and in adjacent land area will receive radiation as the trucks
pass by. Preliminary calculations indicate that this total dose for a
1000 MWe reactor is small (<0.1 man-rom/yr).
The quantity of solid radioactive wastes shipped to licensed burial grounds
is dependent on the design of the radwastc systems. For "as low as
practicable" systems the quantity is estimated to be from 1000 to 1700
drums per year per reactor.
Summary of Emi ssion. Assuming that the HTGR's and LMFBR's have about the
same environmental impacts as do LWR's, the potential, environmental im-
pacts can be expressed in terms of the impact per 1000 Mtf plant as shewn
501
-------
in Table V-34. The total quantity of radioisotopes released in each of
the four years considered in this study is presented in Table V-35.
TABLE V-34. POTENTIAL ENVIRONMENTAL IMPACT OF
POWER OPERATION
Parameter
Typical Values per 1000 MWe Reactor
Heat releases
Radioisotope releases(
To air
To liquids
To burial
Land occupancy
Transmission lines
Exclusion area
Plant occupancy
Water evaporation
Cooling water flow
1500 to 2000 MW
curies/yr
curies/yr
curies/yr
1000 to 1700 drums/yr
36 acres/mile
100 to 500 acres
^20 acres
Up to 50 cfs
1100 to 1500 cfs
TABLE V-35. POWER REACTOR OFERATION-RADIONUCLIDE
RELEASES TO THE ENVIRONMENT
Curies
Water
Year
1975
1980
1985
1990
Air
9.4xl06
2. 0x10 7
2.6xl07
3.9xl07
Lithium
2.7xl05
S.OxlO5
1.8xl06
3.9xl06
Others
339
1,013
3,430
8,500
Control Mechanisms and Costs
The location and amount of heat released to the environment is controlled
by the design of the cooling system. The choices range from the simplcr
once-through cooling systems on water bodies, which discharge all heat
into the water body, to costly dry cooling towers, which discharge all
heat to the air. The design selection is based on the environmental con-
ditions around the individual reactor plants. The total installation cost
ranges from about $8,000,000 for the simple once-through system to as much
502
-------
as $80,000,000 for dry towers. The annual operating costs range from a-
bout $500,000/ycar to as much as $8,000,000/year, exclusive of capacity
penalties.
Some power plants have supplemental cooling towers that are operated only
during critical periods of the year--such as the summer period when high
river temperatures exist. Such systems generally are operated whenever
undesirable water body conditions exist or during all weather conditions
that do not result in undesirable water body conditions fogging or icing.
Release of radionuclides generally is controlled by (1) the design of the
radwaste systems, and (2) the mode of operation of the radwaste systems.
The initial control decision is the design decision since this- generally
determines the maximum treatment possible for the raduastes. The actual
design can vary from essentially 2ero treatment of the wastes before
release to the environment to intensive treatment resulting in "as low as
practicable" or essentially aero release. The corresponding capital costs
vary from about. $3,000,000 to about $15,000,000 per reactcr, and the
annual operating costs from about $40,000/year to about $500,000/year per
reactor.
The method of operating the raduaste system will determine the amounts of
releases, particularly to water bodies. The. most convenient method is to
operate the. system such that the releases result in radioisotopc concen-
trations or doses well below permissible limits. It is possible, though,
in some cacus to operate thfc systems more intensively in combination with
maximum recycle of treated water such that there is a much smaller re-
lease rate. Such operation ir.ay not be justified economically by the
resultant minor reduction in the amount of radioisotopes released or in
the reduction of population radiation dose, but may be justified from a
political standpoint. The increase in total radiation dose received by
plant employees may be more significant than the usually trivial re-
duction in dose to the general population.
Release of chemicals to water bodies generally are controlled by releasing
the chemicals at a low enough rate thct tha dilution by the flow in the
receiving body reduces the concentrations below applicable government
standards. The operating costs for accomplishing such dilution generally
are trivial. Generally, the extra construction cost for assuring proper
dilution is trivial, but occasionally costs up to $1,000,000 may be
necessary if special diffusers or long pipelines must be used. Similarly
costs up to $1,000,000 mr.y be necessary if a satisfactory water body is
not available so that seepage or evaporation ponds must be used.
Releases of sanitary wastes generally are controlled by construction of
sanitary treatment systems designed to meet government standards. Control
then consists only of periodic inspection and maintenance, as appropriate.
503
-------
Fuel Reprocessing
rTechno1or.y Summary
Fuel assemblies which reach their goal exposure are discharged from the
reactor, cooled (aged) and transported to the reprocessing plant. In the
reprocessing plant the uranium, thorium and plutonium are separated from
the wastes.
In the 1975-to 1990 time period, 95 percent of the reprocessed fuel will
be irradiated in a LWR. The reprocessing technologies for HTGR, LWR, and
LMFBR fuel are quite distinct at Lhe head-end of the process. However,
for the v:aste handling step the differences are very small," In addition,
no commercial'LMFBR or HTGR reprocessing plants have been built. When all
these facts are combined the resulting conclusion is that the environmen-
tal impacts of the reprocessing industry can be most accurately assessed
by using LWR reprocessing technology for tach reactor concept.
The spent fuel from the reactor is transported from the reactor to the
reprocessing plant in heavy shielded casks. The cask is unloaded and the
fuel stored in a large water-filled pool. The fuel elements to be re-
processed are transferred to the head-end of the plant where the assem-
blies are sheared into 2-inch lengths to expose the fuel. The fuel is then
dissolved with nitric acid in batch dissolving tanks. The leached hulls
constitute a solid waste that is ultimately disposed of by land burial.
During dissolution, volatile gases are released from the fuel and are
collected in a gaseous waste processing system. The nitric acid solution
of the fuel, containing uranium, plutonium, and nearly all the fission
products is the feed solution to the solvent extraction process.
Nearly all major reprocessing facilities employ some form of Purex
process(V-20) which makes use of the organic complexing compound tributyl
phosphate (TBP), in an inert hydrocarbon diluent. Countercurrent extrac-
tion with the aqueous phase extracts the uranium and plutonium into the
organic phrse and leaves the fission products in the waste phase.
The containment of the volatile fission products, especially l!31 is one
of the most difficult problems in reprocessing. The gaseous wastes from
the reprocessing steps are treated Chemically as well as by filtration,
sorption and scrubbing in order to reduce their radioactive content to
levels that can be discharged to the atmosphere.
The LWR fuel being reprocessed has normally been cooled at least 150
days. At this time tritium, Kr85 and iodine are the important gaseous
wastes. Inorganic iodine is removed by reaction with AgN03 impregnated
on ceramic packing and by scrubbing with Hg(N03)2-HN03 or caustic
solutions.(V-*l) Organic iodine, particularly methyl iodide, can be re-
moved most efficiently by catalytic decomposition and sorption on silver,
copper or iodine-impregnated charcoal. The efficiency of the iodine units
is dependent on the concentration of iodine. A 99.6 percent efficiency
is a commonly quoted design efficiency in cases where organic iodides are
504
-------
not removed.' ' With organic iodine treatment, efficiencies of 99.99
have been quoted, (v"23)
At the present time most reprocessing plants treat the off-gas streams
only for iodine and participates. Particulars arc removed by sand
filters, ™~2 i) deep bed fiberglas filters or a bank of high efficiency
participate air filters. Noble gas collection using cryogenic distilla-
tion^"^) or absorption in f. luorocarbons(v~26) are possible. There is
no currently available tritium removal system.
It can be anticipated that all radioactive liquid wastes from fuel re-
processing will be evaporated and blend c-d to yield only two streams: a
high-level waste consisting of a highly concentrated solution of fission
products and actinides and a low-level aqueous waste that has been
sufficiently decontaminated of. radioisotopes to permit it to be either
discharged to the environment or recycled to the process.
Past practice has been to store the high level liquid wastes in large
underground tanks. This process will probably be curtailed because of
the difficulty in providing cafe containment of the wastes from highly
exposed power reactor fuels. Adequate liquid storage systems may simply
be too large and costly as compared to the cost of early solidification.
Solidified wastes would then be stored on site for several years prior to
shipment to an off-site government repository.
In addition to the high-level aqueous treatment system, large volumes of
process water containing lev/- level wastes are also present. Two to 500
gallons of contaminated water are produced for each metric ton of fuel
processed. These streams, which contain about .1 percent of all the
fission products, can be decontaminated by a factor of 10^ for nil iso-
topes except tritium. At the present time tritium must cither be dis-
charged into the area streams or sent into the atmosphere as water vapor.
The following paragraphs taken from an Oak Ridge summary report:' '
puts the tritium discharge levels in perspective.
Tritium is produced in the fission of U and PU» vich yields of
about 0.01 percent and 0.02 percent, respectively. '' It merits
special consideration from the standpoint of its management in fuel re-
processing because it is unresponsive to separation and concentration by
conventional procedures for treating waste. (V-28,V-29) jn fuci repro-
cessing, less than 1 percent can he expected to volatilize during the
dissolution of oxide fuels. (V-30) There is experimental evidence that
tritium tends to escape from oxide fuels during reactor operation; (
however, the tritium remaining with the fuel can be expected to appear
as tritiated water in the reprocessing plant evaporator condcnsates.
If this tritium could be uniformly dispersed throughout the environment,
the resulting increase in background would be of little significance.^ '
In the actual case, however, a fuel-processing plant will have only its
immediate environs available for dispersion, and the capacity of these
environs to accept tritium will depend on the rate that the latter is
505
-------
If the.
released, as well as on the many environmental factors that pertain to the
particular site.
Two immediately available possibilities for the release of tritium-bear-
ing wastes under existing regulations are: (1) dilution and release
directly to surface waters, and (2) distillation into the plant off-gas
system and subsequent release up the stack.
The quantity of tritium that can be released to surface waters can be
computed within the limitations that the concentration shall ngt exceed
the permissible concentration in water under 10CFR20, or 3x10 u-c/cc at
the boundary of the controlled zone, and that the concentration shall
subsequently not exceed 1x10° jic/cc for the general population. If t
controlled zone borders a stream of any significant size, the first ot
these restrictions is controlling.
A ton of fuel irradiated to a burnup of 33,000 MWd contains about 700
curies of tritium, which would require dilution in water to the extent
of about 63 million gallons before it could be released from the con-
trolled zone at the permissible concentration of 3.10 |j,c/cc. The
total aqueous effluent from a plant operating with a Purcx process flow-
sheet may be as much as 106 gallons per ton of fuel processed, but this
is far short of the requirements for tritium dilution. The most
practical means of achieving the on-site dilution requirements would ba
to have available, for this purpose, a stream flowing through the con-
trolled area. To meet the specification for use by the general popula-
tion, this stream would have to flow into a larger body of water to
achieve additional dilution by a factor of 3 or more.
It is desirable that a plant be situated adjacent to a large, preferably
navigable, river for other (and possibly more important) reasons than
tritium disposal; however, it is much less obvious that acceptable sites
should be limited to those which, in addition, ci.compass a stream of
the size useful for dilution. Therefore, we conclude that, with re-
strictions as presently interpreted, the alternative of release to cur-
face waters is of very limited applicability as a general case.
Distillation into the plant off-gas provides a more effective means of
releasing tritium. Calculations presented in Section 8 of Reference V-21
indicate that plants having spent fuel capacities up to 20 metric tons
per day and site boundaries two to three km distant can release their
tritium in this manner under existing regulations. This is not to imply,
however, that attempts should not be made to develop methods for re-
moving tritium, before it becomes greatly diluted with air or process
streams, and encapsulating it for a long-terra storage.
Emission
In this section the emissions will be expressed in terms of a 5 ton per
day reprocessing plant operating at 75 percent capacity. In one year
this plant has a throughput of 1370 metric tons of heavy metal. This is
506
-------
equivalent to the discharge from reactors having a total, installed capaci-
ty of 50 GW. Table V-36 shows the projected de.mand for 'fuel reprocessing.
Current plans project a 1986 startup date for Lhc HTGR plant. Thus, no
fuel reprocessing demand is shown in Table V-36 until 1990 for the IITGR.
The environmental impacts of plant operation on the air, water, and land
will be discussed sequentially. A waste flow diagram for reprocessing is
shown in Figure V-13.
TABLE V-36. REPROCESSING PLANT THROUGHPUTS
Me trig .Ton /Yoa r
LWR
HTGR
LMFBR
1975
1300
0
0
1980
3400
0
3
1985
5500
C
7
1990
10,100
820
540
Air. The emissions from the reprocessing plant operations to air are
"summarized in Table V-37. The reprocessing plant has two major impacts.
One is the release of radioactive gares and pari.iculates. The second is
the decay heat from the radioactive materials in the reprocessing plan!.
Tn addition sonic iodine and sor.ie volatile rare earth chemical compounds
are released. The technology exists to routinely collect these gases.
It is assumed tlinu all new reprocessing plants coming on line after 1975
will be able to remove 99.99 percent of all the radioactive gases.
The table on participate and gas releases was left blank since their
major effect was included under the radiological release heading.
In calculating the heat load, the energy released through radioactive
decay was assumed to be released directly to the air. Another source of
heat is the evaporators and concentrators in the reprocessing plant. It
was estimated that this load was about equal to the heat generated by
radioactive decay and this heat was taken up by Lhc process cooling water
stream.
Water. The major environmental impact of a reprocessing plant on water
results from the requirement for large volumes of process water. It is
estimated that a 5 MT/day reprocessing plant needs about 2,600 gpm of
process and cooling water.^ Older plants discharged some waste
streams from the plant. However, newer plants continually clean up and
reuse all their process water and a cooling water system would be uncon-
taminatccl. The releases to water are summarized in Table V-38. There are
no radiological releases to the water from any plants other than these
already licensed. As was mentioned in the section on air releases, half
507
-------
Irradiated
Fuel
in
O
Go
Nuclear Fuels
Repracesslng
U03, or l'F6;
Pu(NO,), Solution
6> ?jQ
Internal Disposal
RadlorvjcUde
Wastes
MARKET
EXTERNALITIES
Treat
cent
5 Year
0
Htgh Leve
! *
Mr, Lend, Water
Receptors
Solldifl
of
Liqui
Storage
f
1 Wastes
i
cation
ds
External
Contract
Disposal
FIGURE V-13. NUCLEAR FUELS REPROCESSIKG
-------
the thermal load on the reprocessing plant was assumed to be discharged
in the cooling water stream. The bottom part of Table V-38 summarizes the
projected heat loads on the water for all the reprocessing plants in the
time period of interest.
Land. The reprocessing plant, produces both high and low level radioactive
wastes. Both will be solidified to minimize their mobility and then
shipped off site for disposal. Table V-39 gives the curies and volumes of
high level waste shipped off site. It is assumed that they have been
stored for five years on site prior to shipment for perpetual storage at
a government repository. It is estimated that 200 ft^ of low level waste
are generated for each ton of fuel reprocessed.(V~21) The major source of
radiation from the low-level wastes is the cladding hulls. The curies and
volumes of these wastes packaged and tent 'co a licensed contractor are
shown in Table V"AOU It is assumed that these waster, are transported soon
after the fuel h£4s been reprocessed.
Control Mechanisms and Costs
The LMFBR, 1ITGR, and the LWl reprocessing plant waste treatment systems
can be considered to be similar even though the processes are quite
distinct.
The primary sources of waste are: the fission productions separated from
the thorium, uranium, and plutonium recycle streams; the trans-plutoniuip
isotopes; small percentages of the uranium, thorium, and plutonium; and
activated or contaminated processing material.
TABLE V-37. ENVIRONMENTAL EFFECTS OF FUEL REPROCESSING ON ATR
3-975 1980 _19B5 1990
Radiological Curios/Year
LWR • 1.0x10? ].7xlO? 1.9x107 2.1x.l07
HTGR 9.5xlO^>
LMFBR small small 4.7x105
Total 1.0x107 1.7x10? 1.9x10? 2.2x107
Participate and Gas Tons/Year
. LV.'R
HTGR
LMFBR
Total nil nil nil nil
Thermal
MW
LWR 24 62 100 180
HTGR 0 0 0 30
LMFBR 0 <1
-------
TABLE V-38. ENVIRONMENTAL EFFECTS OF FUEL REPROCESSING
ON WATER
1975 1980 1985 1990
Radiological Curies/Year
LWR 2xlOA 2x10* 2xl04 2x10*
HTGR 0000
LMFBR 0 00 0
Total 2x10* 2x10* 2x10* 2xl04
Water Usage - Gpm
LWR 3,000 7,000 11,000 20,000
HTGR 0 0 0 1,600
LMFBR 0 nil nil 2,200
Total 3,000 7,000 11,000 24,000
Thermal GWt
LWK
HTGR
LMFBR
Ttoal
2 4
0
0
24
62
0
<1
62
100
0
<1
100
180
30
20
220
The reprocessing plant waste treatment systems can be subdivided into
gas, liquid, and solid treatment systems. Ultimately the solid and
liquid streams arc combined so only two systems arc needed. The gas
treatment systems are estimated to comprise about 10 percent of the total
reprocessing plant cost.(V-33) Thus, based on 1970 costs, the gas
treatment facilities for a 5-ton per day plant valued at 66 million would
cost 7 million dollars. The annual operating cost of these facilities is
about 1 million dollars. In the near future additional off-gas treat-
ment facilities to collect, noble gases will probably be required. It is
estimated that the additional treatment would add another 10 percent to
the total plant cost.(v~2i) -phus, in the near future many plants may be
required to add additional off-gas treatment equipment which will cost
about 7 million dollars to procure and install. The annual operating cost
of the plant will probably increase by about 1 million dollars a year as
a result of this additional equipment.
The costs incurred from the solid waste treatment facility are not very
sensitive to the process used. For this analysis it will be assumed that
the wastes are immediately solidified and then stored for five years prior
to sending them to the government waste repository. For a 5 ton/day re-
processing plant, the waste treatment facility total installed cost is
estimated to be about 18 million dollars. Annual operating costs are
estimated to be $1.9 million/year.(V-21.V-34)
510
-------
TABLE V-39.
CURIES AND VOLUMES OF HIGH-LEVEL WASTE SENT TO
A GOVERNMENT REPOSITORY FOR PERPETUAL STORAGE
LWR
HTGR
LKFBR
Total
1975
curies/yr
0
0
0
0
0
ffVyr
0
0
0
0
1980
curies/yr
1.3x10
0
0
1.3x10
9
9
•3
ft°/yr
1300
0
0
1.3xl03
1985
curies/yr
3.4x"109
0
4x1 06
3.4xl09
•3
ftVyr
3400
0
3
3.4xl03
1990
curies/yr
5.5x1
0
8x1 06
6.5x1
O9
O9
ft
5.
7
5.
O
Vyr
5xl03
0
5x1 03
TABLE V-40. CURIES AND VOLUMES OF LOW LEVEL WASTE PACKAGED AND SENT TO
A LICENSED REPOSITORY FROM THE REPROCESSING PLANTS
LWR
HTGR
LMFBR
1975
curies/yr ft°/yr
2.9xl05 2.6xl05
0 0
0 0
1980
curics/yr ft /yr
7.5xl05 6.3xl05
0 0
7.4xl05 6.8xl05
1985
curics/yr ft /yr
1.2xl06 l.lxlO6
0 0
1.7xl06 1.4xl03
1990
3
curies/yr ft /yr
2.2xl06 2.0xl06
<105 l.lxlO5
1.3xl08 1.6xl05
6
8
Total 2.9xlOJ 2.6x10° 1.5x10" S.SxlO"' 2.9x10" 1.1x10" 1.3x10° 2.3x10
-------
Radioactivc Wastc Disposal
Technology Sumniary
The solid radioactive wastes generated by the nuclear power industry are
classified primarily in accordance with the level of radioactivity and
the disposition of the wastes. A flowsheet is given in 1'igure V-14.
The high-level wastes are defined as the wastes containing most of the
radioactive fission products separated from the irradiated fuel elements
at the reprocessing plants. These intensely radioactive materials produce
most of the highly-penetrating radiation in the nuclear power industry
outside of the reactor primary loops and also contain significant quanti-
ties of plutonium. They currently are scheduled for storage in special
repositories with an extremely low probability of release to the environ-
ment.
The low-level wastes arc defined as all other radioactive wastes and
generally have relatively low radiation levels even without shielding.
Because of these lower radiation levels, it is considered satisfactory
to package and store them in locations where they can be collected for
eventual burial at licensed waste disposal sites.
Currently low-level radioactive materials generated in the nuclear power
industry are packaged in leak-proof containers for transit (usually 55-
gallon drums) and shipped off site to commercial burial sites. These
materials consist of a multitide of items such as floor sweepings, spont
resins, vaste still bottoms, failed or obsolete equipment, etc. Most of
it contains relatively small amounts of radioactivity; but some, such as
burned-out power reactor control rods, contain thousands of curies of
radioactivity.
When the materials are received at the disposal site, they are simply
dumped into a burial trench and covered with a layer of dirt. The trenches
are built in locations where the expected eventual failure of the Wcisce
containers is not expected to result in travel of the radioactive materi-
als away from the burial site. This is achieved by choosing locations
where the materials will be stored above the water table and there is
little probability that the wastes would be washed down to the water table.
As a general rule, however, the radioactivity of these wastes is low
enough that the burial sites could be re-entered and wastes repackaged,
if environmental monitoring shows that there could be an uncontrolled
release to the environment.
There is no treatment of surface burial wastes at the burial sites. The
shipping containers are designed to prevent release of radioactive materi-
als during transportation and burial.
High-level radioactive wastes currently are stored as liquid solutions in
tanks. After 1975, all sucli wastes are expected to be solidified and
stored in permanent engineered storage. Economic analysis shows that the
512
-------
Radioactive
. Wastes
Waste Receiving
Operation
Gross Residuals
(Waste Materials)
Internal
Disposal
Untreated
Residual
Land Receptor
(Burin! Site)
FIGURE V-1A.' RADIOACTIVE WASTE DISPOSAL
513
-------
best procedure is to store the wastes for several years at the reprocessing
plant to permit decay of the short half-life radioisotopes. This reduces
the heat-generation rate and radiation hazard during shipment and storage
in the permanent facilities. The wastes may be temporarily stored as
either liquid solutions or solidified wastes at the reprocessing plant
site; the choice depending on the physical form of the wastes when dis-
charged from the fuel separations process.
In this study the wastes are assumed to be stored for five years (about
the optimum period) before shipment to the mines. The wastes are encap-
sulated before shipment, and arc stored in the permanent facility without
removal from the capsules or treatment.
The low level activity wastes include only materials received from private
nuclear industry In the areas of feed materials conversion, fuel fabrica-
tion, and reactor operations. All v;astes are received ready to bury. It
excludes materials from the uranium mills and mines. This activity in-
cludes only radioactive materials permanently buried at commercial surface
burial waste sites. It does not include materials sent to deep burial
sites or materials buried near the surface at other sites. This account
does not include samples, failed equipment, etc., shipped from production
plants to research facilities or government bodies for analyses and investi-
gations of equipment performance.
The high level activity wastes include only materials expected to be
placed in permanent engineered storage and all wastes are received ready
for storage. The material buried consists only of highly radioactive
materials, primarily fission products, from fuel reprocessing plants.
^nvironmcntal Jmpact.
Environmental impacts in disposing of radioactive waste involves only
land use. There is no escape of radioactive materials from the burial
sites to the air or adjacent water tables. The amount of material to be
handled and its activity for each of the years 1975, 1980, 1985, and ]990
are given in Table V-41.
TABLE V-41. SUMMARY OF RADIOACTIVE WASTE
1975 1980 1985 1990
Amount, cu ft l.SxlO6 2.9xl06 5xlO& lOxlO6
Activity, curies 5.7xl06 1.3x10$ 3.4xl09 5.5xl09
514
-------
Transportation in the Nuclear Industry
Transportation of various materials is required to link the various steps
indicated in Figure V-l which is in the Technical Approach Section of this
report. A process flowsheet for transportation is given in Figure V-15.
Railroads are the primary mode of transporting nuclear materials in the
nuclear power industry ^7ith shipments by truck being the secondary mode.
The principal means of water transportation would be transcontinental
freighter. In some steps of the process, the shipments would not go off-
site.
The quantities of nuclear materials that will be shipped in the years 1975,
1980, 1985, and 1990 are given in Table V-42. The industrial chemical
shipments needed to support the processes are not included. In general,
except for accidents, the impacts of shipments of nuclear materials is
identical to transportation of any other material. The usual require-
ments for use of right-of-way, energy consumption, and capital equipment
acquisitions have their normal impact on the environment. The impact of
accidents has not been evaluated since this would require a statistical
analysis of the frequency and severity of accidents for similar types of
materials. All nuclear materials are in innocuous form or arc packaged
to minimize loss of control of the material in the event of an accident.
Thus, the cleanup after an accident presents no greater problem than any
other industrial chemical shipment.
The AEG and others are currently conducting statistical evaluations of the
frequency and severity of accidents and the attendant risk for shipments
of spent fuel, recovered plutonium, and wastes. If we assume an accident,
the following is a ranking of materials from the most hazardous, if prompt
and effective cleanup steps are not taken.
Material Being Shipped
0 Plutonium
e Spent Fuel
o Wastes
0 UF6
0 Fuel Elements
0 U03
o
0 Thorium Ore
515
-------
Extraction
Ul
Extraction
locale
Pre-Ut1l1rst1on
Prccesslnc
Australia
Continental U.S.
South Africa
South Ar.erlca
USSR
of
Mods
•Korenelature
R.T.W are Rail. Truekt toter Transportation and 0 1s c-.-s1te.
Post-Utilisation
Processing
Liquid Ketal
Fast Reactor
H1ch Tempera ture
as Cooled Rctctcr
FIGURE V-15. NUCLEAR (FISSION) FUEL CYCLE PROCESS FLOWSHEET
-------
TABLE V-42. NUCLEAR MATERIAL SHIPMENTS
(Toes)
Material
Uranium Ore
Thorium Ore (Reactor use)
U3°8
ThO, (Reactor use
C
UFg to enrichment-natural
-Recovered
UF, to fabrication
0
Fuel Elements - LWR .
- HTGR
- LKFBR
Spent Fuel - LWR
- HTGR
- LMFBR
UO, - Recovered uranium
Plutonium
Waste
• 1975
9.Sxl06
180
ISxlO3
7
23x1 03
1900
4450
5100
40
2000
1500
3
T.SxlO6 cu. ft.
1930
16x106
6700
31xl03
270
39x1 O3
5000
6650
8900
3100
5
5600
5
4000
31
2.9xl06 cu. ft.
1935 .
23x1 O6
25x1 O3
53-<103
1000
67x1 O3
8100
13300
ISxlO3
gxlO3
12
9x1 03
12
6600
63
5x1 O6 cu. ft.
1990
44x1 O6
52x1 O3
84x1 O3
2100
105x103
ISxlO3
21x103
23x1 O3
2ixl03
2600
17xl03
9400
SCO
12xl03
150
lOxlO6 cu. ft.
Net weight of material indicated does not include container, shielding, or protective
packaging which in the case of spent fusl and plutonium is of the order of 50 tines '
the weight of the material and must make the return trip enipty.
-------
s> Uranium Ore
This ranking is based upon the relative toxicity and chemical stability of
the compounds and makes no judgment regarding the effectiveness of the con-
tainer or shipping regulations. The fuel elements are ranked above 1103
since they may contain pLutoniuin, and below UFg because of their chemical
and physical stability.
We have assumed that no releases occur during the transport of nuclear
materials between process steps of the fuel cycle simply because we have
assumed normal operational conditions. Therefore, control mechanisms and
associated costs were not studied.
References
V-l. BNWL-B-141, "Data for Preliminary Demonstration Phase of the Environ-
mental Quality Information and Planning System (EQUIPS)", Battelle,
Pacific Northwest Laboratory,- December, 1971.
V-2, R. L. Engel, "DAEDALUS II: A Computer Code to Generate a Linear
Programming Model of a Nuclear Power Economy", BNWL-1459, June, 1970.
V-3, USAEC Division of Reactor Development and Technology, "Potential
Nuclear Power Growth Patterns", WASH-109S, December, 1970.
V-4. D. E. Deonigi, R. W. McKec, and D. R. Haffner, "Isotope Production
and Availability From Power Reactors", BNUL-716, July, 1968.
V-5. Federal Power Commission Press Release No. 17372.
V-6. U.S. Energy Outlook, An Initial Appraisal 1971-1985, An Interim
Report of the National Petroleum Council, Volume One, July, 1971.
V-7. USAEC Division of Operations Analysis and Forecasting, Forecast of
Growth of Nuclear Power, UASH-1139, January, 1971.
V-8. "Preliminary Program International Conference on Nuclear Solutions
to World Energy Problems", American Nuclear Society Winter Meeting,
November 12-17, 1972, Washington, D.C., Supplement to Nuclear News,
pp 99-108, Spetember, 1972.
V-9. An Assessment of the Economic Effects of Radiation Exposure Stan-
dards For Uranium Mirers, Report to Federal Radiation Council,
Arthur D. Little, Inc., September, 1970.
V-10. J. B. Burnham, L. G. Merker, and D. E. Deonigi, "Comparative Costs
of Oxide Fuel Elements", Vols. 1, 2, and 3 and Appendix, BNUL-273,
July, 1966.
V-ll. ASA Subcommittee N5.2, "Current Practices in the Handling and
Storage of Wastes From Nuclear Fuel Fabrication Operations, Novem-
ber, 1966.
518
-------
V-12. D. H. Leo and S. Jaye, "High Temperatute Gas-Cooled Reactor Fuel
Costs Today and Tomorrow", Gulf General Atomic Document, GA-10730,
September 1, 1971.
V-13. Unpublished data.
V-14. Reference Safety Analysis Report (RESAR), Rev. 1, Westinghouse.
V-15. Verplank Nuclear Power Station Safety Analysis Report.
V-16. Fort St. Vrain Power Station Safety Analysis Report, Public Service
Company of Colorado.
V-17. J. 0. .Blomeke, F. E. Harrington, Management of Radioactive Wastes
of Nuclear Power Stations, ORNL-4070, January, 1968.
V-18. R. C. DeLozier, L. D. Reynolds, and H. I. Baucrs, Concept -
Computerized Conceptual Cost Estimates for Ster.m Electric Power
Plants - Phase 1: User's Manual, ORNL-TM-3276 (October, 1971).
V-19. K. R. Wise and B. M. Cole, "A Survey of Heat Sink Capacity of Major
Streams Within the U.S.", BNWL-951, Battelle-Northwest, 1969.
V-20. %E. R. Irish and W. H. Rcas, The Purex Process - A Solvent
Extraction Reprocessing Method for Irradiated Uranium, HW-49483A,
1957.
V-21. Siting of Fuel Reprocessing Plants and Waste Management Facilities,
ORNL-4451, 1970.
V-22. Nuclear Fuel Services, Inc., Safety Analysis Report, AEC Docket No.
50-201.
V-23. R. E. Adams, R. D. Ackely, and W. E. Brovming, Jr., "Removal of
Radioactive Methyl Iodide From Steam-Air Systems", ORNL-4040,
1967,
V-24. G. H. Sykes and J. A. Harper, "Design and Operation of a Large Sand
Bed for Air Filtration", in Treatment of Airborne Radioactive Wastes
(Proceedings of a Symposium), CONF-680S11, 1968.
V-25. c. L. Bendixen and G. F. Offutt, Rare Gas Recovery Facility at the
Idaho Chemical Processing Plant, IN-1221, April 1969.
V-26. J. R. Merriman, J. H. Pashley, K. c. Habiger, M. J. Stevenson, and
L. W. Anderson, "Concentration and Collection of Krypton and Xenon
by Selective-Absorption in Fluorocarbon Solvents", in Treatment of
Airborne Radioactive Wastes (Proceedings of a Symposium), COHF-
680811, 1968.
519
-------
V-27. N, D, Dudey, "Review of Low-Mass Atom Productipn in Fast Reactors",
ANL-7434, 1968.
V-28. W. A. Hansy, "Fission-Product Tritium in Fuel-Processing Waste",
Nucl. Safety 5 (4), pp 339-403, 1964.
V-29. J. 0. Biomekc, "Management of Fission Product Tritium in Fuel
Processing Wastes", ORNL-TM-851, May, 1964.
V-30. J. H. Goode, "Hot-Cell Evaluation of the Release of Tritium and
85Krypton During Processing of ThO^-UOo Fuels", ORNL-3956, June,
1966.
V-31. J. II. Gcode and V.C.A. Vaughen, ''ORNL Experiments on the Behavior
of Tritium During Head-End Processing of Irradiated Reactor Fuels",
ORNL-TM-2793, February, 1970.
V-32. D. G. Jacobs, "Sources of Tritium and Its Behavior Upon Release to
the Environment", TID-24635, 1968.
V-33. J. 0. Blomeke, et al., "Estimated Costs of High-Levcl Waste Manage-
ment", Proceeding!; of the Symposium on the Solidification and
Storage of High Level Radioactive Wastes, CONF-600208, 1966.
V-34. J. 0. McElroy, et al., "Waste Solidification Program Summary
Report", Volume II, BNWL-1667, 1972.
520
-------
APPENDIX W
ADVANCED ENERGY SYSTEMS
Table of Contents
Sunimary 523
Fuel Cell Energy Systems 526
Solar Energy Systems 531
Heat Pumps .....'.. 540
Geothcrmal Power 542
Thermonuclear Fusion 553
Breeder Reactors 555
Tidal Power 566
Magnetohydrodynami.es 574
Thermionic Power 578
Thermoelectric 579
References 582
List of Tables
W-l. Environnental Ranking of Advanced Energy Systems. . . . 524
W-2. Estimated Funding Effort and Requirements Related
to Fuel Cells 530
W-3. Projected Program Costs and Schedule for Three
Options 538
W-4. Coefficients of Performance for Electrically Driven
Heat Pumps with Various Sources and Sinks 540
W-5. Burden of Environment 1,000 MW Geothertnal Plant .... 550
W-6. Proposed Geothermal Resources Research Program 552
W-7. Effectiveness and Economic Costs for Pollution Control
with Respect to Meeting Existing and Anticipated
Regulations 553
W-8. World Energy Reserves of "Infinite Fuels" 554
W-9. Prominent CTR Energy Cycles 555
W-10. Summary of Effluents 561
W-ll. D-Li Energy Cycle Effluents 1000 MWe, 40 Percent
Efficiency 563
W-12. Nuclear Fusion Costs (by Milestone) 563
W-13. Nuclear Fusion Costs by Year in Millions of 1971
Dollars 554
List of Figures
W-l. Power System Efficiency Comparison. . 528
W-2. Solar Energy Conversion Modes 532
521
-------
List of Figures (continued)
W-3. Conceptual Deuterium Tritium Fuel Cycle 557
W-4. Conceptual Design of an Inertial Confinement CTR
Power Plant 559
W-5. Conceptual Design of an Electro-Magnetic CTR Power
Plant 560
W-6. Simplified Power-Cycle Diagram, 1000 MWe GCFBR 567
W-7. Simplified Flow Diagram of MSBR System 570
W-8. Nuclear Steam-Supply Components in a Liquid-Metal-
Coolcd Breeder Reactor 572
522
-------
APPENDIX W
ADVANCED ENERGY SYSTEMS
Summary
The objective of this phase of the study was to identify potential ad-
vanced energy systems, to identify the environmental burdens, and to
rank the systems environmentally. ;
In order to rank the prospective energy systems environmentally, con-
sideration must be given to a wide range of factors. In many cases, it
is not possible to develop quantitative measures of the extent of envir-
onmental burden. More important, there is not yet available a method
for comparing emissions. For example, it is not possible to trade,
quantitatively, cooling water requirements for air pollutant emissions.
Thus, for present purposes it has been necessary to make qualitative
judgments of the relative significance of many environmental burdens.
Consideration has been given to cooling water requirements and emissions
of common air pollutants; land requirements for solar energy collectors
and for strip mining; to problems associated with a large variety of waste
products; to the potential for local or meso-scale climate modification;
and many others.
Each energy system was considered in terms of both real and potential
environmental burden. They were then grouped relative to each other into
four qualitative classes, from excellent to poor, to reflect increasing
environmental burden. Consideration was given not only to adverse factors;
any environmental gains were also considered. For example, breeder re-
actor systems were credited for negative fuel consumption; solid waste
utilization in steam electric plants received credit both for its contri-
bution to the reduction of solid waste disposal problems and for reducing
the need for virgin fuels.
Some of the systems can be considered to be rapidly emerging technology;
some of the environmental factors charged against them may be resolved
soon. In some cases, there is conflicting information as to the potential
burden. In most cases, the scientists and engineers who are closely
associated with a particular system tend to be very optimistic about the
potential of that sysLem to provide significant energy at relatively modest
environmental cost. Considerable effort was devoted to achieving a bal-
ance and avoiding excessive optimism or pessimism.
The rankings of the selected advanced energy systems arc presented in
Table W-l. Those considered capable of producing significant power in
the future arc identified.
523
-------
TABLE W-l. ENVIRONMENTAL RANKING OF ADVANCED ENERGY SYSTEMS
Excellent
Solar Energy (Residential)(c)
Heat Pumps (Residential, Electric)(
Conventional Hydroelectric'3'
Good
Tidal
Geothermal (Hydrocracked dry rock)^c'
Solar (Rankine cycle)(c)
Solar (Stirling)^
Geothermal (Natural)(>c'
Fusion
Solar (Satellite)
Solar (Photovoltaic)
Natural gas/steam/electric(
Fair
Geothermal (nuclear stimulated)
Magnetohydrodynamic (Closed cycle, nuclear)^ '
Breeder reactors (gas-cooled(c), liquid motal(c), and molten salt)
Fuel Cells (Coal-to-hydrogen gasification)(c)
Light Water Nuclear Reactors(a»b»c)
Fuel Cell (Nuclear-electrolytic hydrogen)'0'
Thermoelectric (Solar)
Gasified coal/steam/elcctric(c)
Solid Waste Utilization (Trash-coal/steam/electric)'b»c'
Magnetohydrodynamic (Open-cycle - coal/stcam/electric)(c/
Poor
Coal/Steam/Electric ^a^
Thermionic (Nuclear)
(a) The conventional systems in 1972 are included for reference pur-
poses only.
(b) Capable of producing significantly increased energy by 1975.
(c) Capable of producing significant energy by 1990.
524
-------
Much of the reasoning behind the relative positions assigned to the
various systems can be illustrated briefly as follows.
Fuel eel! systems have at least two advantages over conventional steam
electric systems; they are more efficient thermally and would produce
substantially less air pollution. These advantages may be illusory,
however, because the fuel production would represent an additional step
which would reduce overall efficiency. Moreover, if the fuel is produced
by gasifying fossil fuels, there would be some production of conventional
air pollutants.
The solar energy systems arc widely considered to be environmentally
"clean". However, the collectors would require the dedication of very
large land areas. Systems using satellite collectors would require beam
transmission of the energy to receivers on the ground. Some concern has
been expressed for the potential hazard associated with the relative
intensity of the proposed beam of electromagnetic radiation.
Residential heat pumps represent largely beneficial environmental impact
because they would reduce the load on central power plants. On the other
hand, there would be a requirement for supplementary space heating at
times for which resistance heating systems appear attractive. In that
ease, widespread use of heat pumps might lead to increased central power
station load, with attendant environmental insults, during the heating
season.
The various approaches suggested for utilizing geothermal energy are all
site limited, and all appear to require dedication of substantial amounts
of land, much of which is presently scenic. In addition, there is a
potential for the contamination of surface water with dissolved salts,
and for air pollution with hydrogen sulfide or ammonia, for example.
Concern has also been expressed over possible subsidence of relatively
large areas, and for possible seismic activity as a result of deep well
injection.
.Controlled Thermonuclear Fusion reactors have several potential advantages
over fission reactors and fossil-fueled plants. They should be more
efficient, thus requiring less cooling capacity; there will be no combus-
tion products; and radioactive wastes will be largely contained. How-
ever, there will be substantial tritium production, and the reactor
structures will be radioactive.
Utilization of tidal currents to produce electricity is attractive as a
nonpolluting system. However, there are several environmental factors,
including alteration of estuaries, both physically and biologically, and
the potential for local or mcso-scale alteration of weather and climate.
Solid waste combustion in thermal electric plants has already been men-
tioned for its overall beneficial environmental effects. A system util-
izing solid waste would produce similar air pollution except appreciably
525
-------
reduced sulfur emissions and possibly increased heat rejection problems
as compared to a conventional coal-fired plant.
Breeder reactors as a group have similarly been mentioned as having a
decided environmental advantage because of their fuel production as
opposed to consumption. However, their thermal efficiency is not al-
together favorable, and their production of tritium and fission products
which must be stored for decay represent adverse environmental factors.
In addition, the shipment and reprocessing of fuel in large quantities
represents a certain environmental risk because of the possibility of
accidents.
MaRnctohydrodynamic power systems have received much favorable attention
largely because of their relatively high thermal efficiency. Seed re-
covery must be thorough for economic as well as environmental reasons,
but it is not known how important might be the escape of relatively small
amounts, by weight, of very small diameter seed particles which are
extremely difficult to capture. Sulfur recovery within the system is a
decided bonus but the very high temperatures associated with MUD will tend
to cnchance production of oxides of nitrogen.
Therrooe1ectrIc and thermionic systems are not expected to provide any
significant power to meet national demands by 1990 or beyond.
The more complete detailed descriptions of the selected advanced energy
systems are presented in the following section. It should be recognized
that the order in which they are presented is not necessarily the order
of environmental ranking nor energy potential which is presented in
Table W-l.
Fuel Cell Energy Systems
A fuel cell is an electrochemical energy conversion device that can con-
tinuously produce electrical energy from an input of chemical fuel and
oxidizer. The fuel cell is not limited as Carnot cycle systems and theo-
retically can achieve higher energy efficiency. However, high capital
costs prevent fuel cells use for large-scale central station power gener-
ation. Fuel cell power plants are more competitive in smaller sizes
(<50 1-M) for dispersed power generation. The problems of conversion of
DC as generated in the fuel cell to AC as used universally at present must
also be considered along with the costs of such conversion when it is
required.
Fuel cells can be roughly classified by type of electrolyte:
Aqueous electrolytes: temperature range, 0-200 C
Molten salt electrolytes: temperature range, 500-700 C
Solid electrolytes: temperature range above 700 C
526
-------
The lower temperature aqueous electrolyte type fuel cells hold the most
promise for the future. Oxygen in the air is used as the oxidizer and
hydrocarbons and hydrogen are the principal fuels of interest.
Four specific fuel cell systems of interest are described here, together
with an appraisal of their acceptability.
System 1.
Natural gas distributed by pipeiiiie is the fuel and oxygen in the air is
the oxidizer. The fuel cell power plant consists of three subsystems:
(1) a steam reformer to convert methane to hydrogen and carbon dioxide,
(2) the fuel cell stacks, and (3) a DC to AC inverter. There are several
possible applications beiiig studied that can be grouped according to size
and location:
System 1A 12-50 kw Residential/commercial
System IB 10-20 MW Substation
System 1C 100 KW Central station.
System 1A. This has been the subject of the $50 million TARGET program of
Pratt & Whitney Aircraft (P&WA) and the gas utility industry, begun in
1967, and now in the second phase of field test.^ ' The principal
limitation has been capital cost which has been decreased from about
$1500/kw in 1968 to about $400/kw in 1972 with forecasts cf $200 to
$250/kw during commercial production (Phase 3). Because of the dependence
on natural gas, it is unlikely that this system will find wide application
before the 1980's when coal gasification will provide a reliable supply
of synthetic gas (methane).
System IB. This is similar to System 1A and is the subject of current
studies for the electric utility industry(w~2) to realize the advantages
of dispersed siting on the electric power network (electric transmission
savings) for either base load or peaking duty with estimated installed
costs of $140 to $165/kw and $110 to $135/kw, respectively. For sub-
station use, versatility in operation on other fuels is required in
addition to natural gas, such as, propane and low-sulfur liquid fuels.
Estimates of cost goals indicate that to be competitive with nuclear
energy, fuel cell fuel costs would have to be below $0.80/10^ Btu; to be
competitive with gas turbines fuel cost could be in the range of $0.80
to $1.10/10 Btu. Whether the system's goals can be achieved will be
determined by about 1976 with potential use by 1980. Near-term use is
limited by supply of natural gas and low sulfur liquid fuels; long-range
use is dependent on development of synthetic gas (methane) by coal gasi-
fication in the 1980's.
System 1C. Use of fuel cells for large-scale central station power gener-
ation does not appear promising with present fuels or future synthetic
fuels because the efficiency advantage of fuel cells over steam and gas
turbine systems decreases as power output increases to 100 MW and larger
(sec Figure W-l). Also a principal savings for fuel cells is in dispersed
527
-------
use with pipeline transmission of gas energy where credit for savings over
electric transmission can be -realized.
System 2 -
Hydrogen gas produced from coal and distributed by pipeline is the fuel
and oxygen in the air as the oxidizer. The fuel cell power plant is
simpler and lower cost than System 1 since ah integral reformer is not
needed. . For use of pipeline hydrogen, it is questionable that fuel cells
could be^dispersed to the single residence level. Thus, the urban energy
system currently under study by Battelle at about the 1 1-Itf level appears
optimum for safety while retaining most of the economic and esthetic
advantages of underground gas transmission as opposed to. overhead electri-
cal transmission and retaining the option for utilization of waste heat.
fry_s tetn ^3
Nuclear energy (fission or fusion) can be the primary energy source to pro-
duce low cost electrical energy which is used to produce hydrogen by water
electrolysis (other schemes for direct production of hydrogen from v/ater
by nuclear energy are presently remote possibilities). Hydrogen then be-
comes the energy carrier via underground pipelines for dispersed utilisa-
tion of fuel cells at urban load centers as in System 2.
System 4
Solar energy can bo used directly as the primary energy source to produce
electricity (by thermal or photovoltaic means) which is used to produce
hydrogen by water electrolysis. Hydrogen then becomes the energy carrier
via underground pipelines for dispersed utilization of fuel cells at
urban load centers as in System 2.
Potential Environmental Burden of Fuel Cells
_g vs. tern 1. - Integral Reformer (Natural Gas, Oil). Reduced waste heat
rejection is possible with System 1 because of higher thermal efficiency
of fuel cells compared to conventional energy converters. As a first
approximation, the improvement in fuel utilization for fuel cells can be
estimated from efficiency versus power output shown below.
DO
40
EFFICIENCY
rcnccNT 30
10
met ecu SYM
0' t_l,.UUIU 1 I I I III- 1 1 11IUII |_1J .,!.,._ .,,.„;.,
' 13 IOO 1.OOO. 10.OOO 1OO.COO
POWER 0'JTPUT - C.ILOWATTS
FIGURE W-l. POWER SYSTEM EFFICIENCY COMPARISON^'2)
528
-------
Fuel cells have reduced atmospheric pollution emissions'compared to most
combustion systems. Fuel cells with integral reformers have integral
scrubbers to remove sulfur dioxides. Principal source of atmospheric
contaminants is the fuel burned to supply heat to reformer. Significant
reduction of atmospheric pollutants is achieved with fuel cells compared
to gas-fired central station as shown in the following tabulation:
Pounds per Thousand kwhr
Gas-Fired Fuel
Central Station Cells(a)
Sulfur Dioxide 0.3 0.0003
Nitrogen Oxides 4 0.24 •
Hydrocarbons 2.8 0.23
Participates 0.1 0.00003
(a) Based on data from experimental fuel cells
Source: Reference W-2
Since fuel cells do not require a heat sink as do Carnot cycle systems,
the heat load represented by the inefficiency is added to the atmosphere
(air cooling used) rather than water, and heat dissipation is as dis-
persed as the fuel cell power plants. Some heat can be beneficially used
at residential/commercial sites.
The use of dispersed fuel cells results in a proportionate reduction of
overhead electrical transmission requirements with improvement of land use
and esthetic benefit.
The use of fuel cells on pipeline gas can be arranged to provide energy
storage for peak use periods and reduce requirements for other peak load
systems such as: conventional fossil fueled peaking systems, use of
marginal fossil-fueled base-load systems of high pollution level, and
pumped-hydro storage.
Future use of coal gasification to provide a (high Btu) synthetic gas for
pipeline distribution wil add to the atmospheric pollution load at the
coal gasification site while removing sulfur and reducing the sulfur
oxide atmospheric pollution .it the fuel cell site.
System 2. Pipeline Hydrogen (Fron Coal). The use of pipeline hydrogen
will eliminate atmospheric pollution load at fuel cell sites compared to
System 1. Coal gasification will provide some .atmospheric pollutants but
probably no significant NOX if carried out at low enough temperature.
Sulfur and other atmospheric contaminant control will be greatly reduced
by economy of large-scale pollution control and will only be produced at
cites remote from urban areas.
System 3. Nuclear Energy (Hvdrogen bv Electrolysis). Local atmospheric
pollution will be completely eliminated, compared to Systems 1 and 2, by
use of electrolysis of water as the source of hydrogen (rather than coal).
529
-------
There will be an increased thermal pollution load at trhe nuclear/electric
generating site due to the inefficiency of water electrolysis and greater
need for electric power. Present state-of-the-art water electrolysis is
less than 50 percent efficient. Advanced water electrolysis cells are
expected to increase the efficiency to -75 percent, and long-range goals
would be an efficiency of 80 to 90 percent. It should be noted that
theoretical electrical energy (voltage) efficiencies of water electroly-
sis and fuel cell arc 100 percent. Theoretical thermal efficiency of hy-
drogen production by electrolysis is about 120 percent but corresponding
theoretical thermal efficiency of l^/C^ fuel cell about 82 percent.
With hydrogen generation using nuclear/electric source and pipeline dis-
tribution of hydrogen, remote siting of the nuclear plant is possible.
Energy distribution by pipeline hydrogen is more economical than under-
ground electrical distribution in general and more economical than high
voltage overhead electrical transmission for distance greater than 400
miles.
Systemi 4. Solar Energy (Hydrogen by Electrolysis). An inefficiency in
hydrogen generation by water electrolysis using a solar/electric energy
source does not add materially to the thermal burden of the earth.
This is an ideal system in that there is no atmospheric pollution, no
thermal pollution, and no overhead transmission lines. Hydrogen provides
a means of underground energy storage for peak power demand and would
eliminate the need for pumped hydro sites,
Estimated Funding Effort and Requirements
Estimated funding requirements for research and development related to
fuel cells are given in Table W-2.
TABLE.W-2. ESTIMATED FUNDING EFFORT AND REQUIREMENTS RELATED
TO FUEL CELLS (Millions of Dollars)
Millions of Dollars
Expenditures Expenditure for Each 5-Year Period Through
to Date, Beyond
System 1972 1975 1980 1985 . 1990 . 1990
1, N 5000
2(c) 5000
3 and 4(c) 2
26 (b)
3(d)
3
15 21 lo(b)
5 . . 25 / »
5(e) 9(e)
?
25(3)
12(e)
?
9
?
(a) This is estimated past expenditures on TARGET program and related fuel
cell research. Does not include ^-$250,000,000-of prior government R&D
530
-------
related to developing Apollo and Gemini fuel cells.
(b) Estimated funding by electric utilities to evaluate fuel cells for
substation use.
(c) System 2 costs do not include funding on coal gasification or
production of hydrogen from coal.
(d) Estimated expenditure to develop urban fuel cell concept and re-
lated hydrogen transmission technology, and to explore residential
d-c usage and waste heat utilization.
(e) Estimated expenditure to develop water electrolysis as an'economic
alternative to hydrogen production from fossil fuels by use of
nuclear and/or solar energy.
Magnitude of Energy That Can Be Developed
For System 1, the magnitude of the energy that can be developed using a
fuel cell system is limited by the present availability of natural gas
that can be directed from other uses to this form of electric energy
production. The use of low sulfur liquid fuels presents a similar short
term supply situation.
Successful development of economic coal gasification would permit a high
percentage of electric needs to be satisfied by fuel cells using either
synthetic methane or hydrogen for System 2.
Systems 3 and 4 are predicated on reduction in cost of electric power
by fission, fusion, or solar means to near or less than the cost of
hydrogen produced from coal. All electric energy needs beyond the year
2000 could ultimately be provided by a hydrogen distribution system with
dispersed urban fuel cells. Also, with low cost hydrogen, residential,
commercial, and industrial thermal energy requirements could be satisfied
by pipeline hydrogen as well as the needs of the chemical and metallurgical
industries for hydrogen (i.e., ammonia and iron ore reduction).
Solar Energy Systems
Several types of systems for converting solar energy to electrical energy
are theoretically feasible for large-scale central power station use.
These will be discussed below. It should be kept in mind that residential
healing and cooling consumes nearly one-fourth of the fuel required for the
United States and that solar energy could best provide a substantial portion
of these requirements "on site" to reduce the overall central power station
requirements. (W-3.V7-4)
Figure W-2 is a diagram showing various solar energy conversion modes pre-
sently available with expected efficiencies indicated.'k~^' Not shown on
531
-------
PHOTOVOLTAIC
CONVERTER
01
u>
N>
10% (20%)
STATIC
CONCENTRATOR
THERMOELECTRIC
CONVERTER
0% (20%)
SOLATt RADIATION
CONCENTRATOR
THERMIONIC
CONVERTER
10% (25)4)
LLECTRIC
POWER
( ) EXPECTED FUTURE EFFICIENCY
DYNAMIC
COLLECTOR
VAPOR CYCLE
CONVERTERS
25% (40%)
GENERATOR
THERMAL
COLLECTOR
HEATER
4C%
T
r
HOT GAS
HOTLIQUID
FIGURE W-2. SOLAR ENERGY CONVERSION MODES
-------
this figure is the simole scheme that has existed since1the creation of
the world, which is using solar energy to grow trees to provide fuel for
conventional power plants. Ov"3)
If one considers the average daily radiation for the continental United
States, it is realized that the energy level is quite low. Therefore,
large collector areas are required to capture enough energy to power a
large electrical generating station, For example, the average daily
amount of total solar radiation (direct and diffuse) incident on a
horizontal surface in the continental United States is about 600
Langley's/day (2,210 Btu/ft -day, or 27 watts/ft2) in June and decreases
to about 200 Langley1s/day (740 Etu/ft2-day. or 9 watts/ft2) in De-
cember.' ' Thus, if a horizontal flat plate collector and -associated
equipment were 100 percent efficient in converting this solar energy to
electricity, a 1,000 MW station would require a collector area of
approximately 1.3 square miles in June, and 4.0 square miles in December.
Focusing collectors which track the sun will level out this yearly
variation in radiation intensity. The direct-normal intensity at 40
degrees north latitude will always average about 290 Btu/hr-ft at noon
on clear days, but the hours of sunlight will vary from about 15 hours
on June 21 to only about 9 hours on December 21.(w"7) Therefore, the
total flux received on a surface kept normal to the sunlight will vary
from about 3,200 Btu/ft2-day (39 watts/ft2) in June to about 2,000 Btu/
ft2-day (24 watts/ft ) in December. Consequently, a 1,000 MW generating
station, using sunlight-tracking collectors and operating at 100 percent
conversion efficiency, would require a collector area of approximately
1.3 square miles in June and 4.0 square miles in December.
Another consideration influencing the design of solar collectors is the
maximum operating temperature required by the energy conversion system.
The following tabulation outlines the basic requirements.' ' ' The use
of surface coatings to increase the ratio of solar energy absorbed to
the thermal radiation emitted will tend to increase the maximum tempera-
tures achieved for each type of collector and increase the collection
efficiency.
Maximum Operating Temperature Type Collector
Below 100 C (212 F) Stationary, nonfocusing
100 C (212 F) to 200 C (392 F) Stationary, focusing, low
concentration
Above 200 C (392 F) Tracking, focusing
Considering the overall technological and economical feasibility of the
various solar energy conversion systems discussed herein, they are rated
below in descending order of priority in terms of energy capability:
1. Residential heating, cooling, and hot water
2. Rankine cycle
533
-------
3. Solar cells.
4. Stirling engines.
5. Satellite system.
ResidentialHeating and Cooling
It has been reported that about 25 percent of the total energy con-
sumption in the United States is for the heating and cooling of build-
ings, and that 22 percent of the total is consumed for residential
dwellings. v«~3) QJJ the energy required for homes, an average all-
electric home in the United States consumes about 100 million Btu's
(29,300 Icwhr) per year, of which 45 percent is for heating, 15 percent
for cooling, and 25 percent for hot water.' "' Thus, if solar energy
were used to provide for the residential heating, cooling, and hot
water needs, this would represent a total energy savings of almost 20
percent.
Solar energy is already well distributed, and its quantity is quite well
matched Lo residential needs for comfort heating, cooling, and hot water.
For example, the average total amount of solar radiation (direct and
diffuse) falling on 1,000 square feet of horizontal surface in the United
States is approximately 550 million Btu's per year. However, energy
storage requirements, and winter and summer needs would have to be consi-
dered carefully for each locality, we well as optimum sloping of the roof
collectors for year-round use.
Perhaps it may never be feasible to provide for 100 percent of residential
heating and cooling by means of on-site collection and storage of solar
energy. One analysis, which considered only solar heating, concluded
that it is most economical to design for only about 50 percent of the
total requirements in most area.s of the United States. (W"10)
Enviromr.cntra 1 Factors. The successful development of "on-site" solar
heating and cooling for residential dwellings could reduce the environ-
mental pollution caused by central power plants by as much as 10-to 20
percent. Since solar energy is already well distributed, the use of its
energy when and where it is received will have the least overall detri-
mental effect on the surrounding environs.
Capital Costs. Home heating with solar energy is estimated to be cost
competitive with electric resistance heating at $0.02/kwhr ($5.85/10 Btu)
for many parts of the United States.(W~3) However, solar collector and
heat storage systems have not yet been developed to the necessary dependa-
bility and economy required for widespread public use.
RM) Expenditures. A complete 10-year progi'am of research and development
for solar heating and cooling of dwellings has been formulated.(w"3) This
calls for a total expenditure of between $10 to $20 million over the 10-
year period.
534
-------
Solnr Povorcd Rankine Cycle
This type of system usually consists of solar concentrators to focus the
sunlight onto heat collector tubes. This heat is then transferred by
means of a circulating fluid to a heat storage unit. The stored heat
energy is used as needed to produce stcrm for a conventional steam
turbine generating plant.
At least two such designs are currently under study.(W-4) Aden Maine!
at the University of Arizona is designing a collector using Frcsnel lenses
to concentrate the solar flux 10 times and focus them onto stainless steel
or glass ceramic pipes. These pipes would have selective coatings to
increase the relative absorptance of the solar energy, and would be en-
closed in evacuated glass tubes to further reduce heat losses. Nitrogen
gas would be circulated through the pipes and transfer the heat to a
central heat storage system consisting of an eutectic mixture of molten
salts. This stored heat would then be used to produce steam for a conven-
tional turbine as required.
The second study, headed by Ernst Eckert at the University of Minnesota
and Roger Schmidt at Minneapolis-Honeywell, Inc., utilizes a parabolic
reflector to concentrate the sunlight onto a heat pipe. Again, selective
coatings and evacuated chambers would be used to increase the collection
efficiency. Each heat pipe would have a separate heat storage unit
and the steam generated would be returned to the turbine-generator.
Work on solar-powered vapor turbines has been conducted by H. Tabor,
and a 6GO-\?att experimental unit has been built using dichlorobcnzene
as a working fluid.(W-8.W-11)
Another type of solar-powered Rankine cycle would use the thermal gra-
dients in the oceans to opnrate a turbine-generator unit.(W"12,W-13)
However, the overall temperature difference available is quite low (about
40 F) and, consequently, the overall thermal efficiency of the plant will
be very low, probably less than 5 percent. Therefore, very large heat
exchanger surface areas are required. If these heat exchangers can be
designed for low cost by proper design, and if efficient components are
developed, then this scheme may prove useful for some coastal regions
where favorable temperature gradients exist in the ocean.
Environmental Factors. Although solar energy has probably the fewest
potential environmental problems associated with its use of any of the
major sources of energy, some problems do exist. Collecting surfaces
absorb more sunlight than the earth does, and while this is not likely
to alter the local thermal balance in household or other small-scale use,
the large expanse of collecting surface required for a central power
plant might. For example, at an estimated maximum overall efficiency of
20 percent, a 1,000 MW solar-powered generating station would require a
collector surface area of approximately 12 square miles, assuming an
average daily intensity of 15 watts per square foot on a year-round
basis. However, a solar plant may have to be sized for winter radiation
535
-------
conditions, which could increase the collector size by 50 percent.
Thermal pollution will also be a problem if water-cooled steam con-
densers are used—even more so than with nuclear power plants because
solar installations are expected to have even lower thermal efficiencies.
If waste heat is returned to the atmosphere, it could help to restore the
local thermal balance. The effects of these changes in the thermal bal-
ance would depend on the local meteorological conditions, but are expected
to be small.
A floating power plant operating on the thermal gradients in the ocean
would have almost no detrimental environmental impact. It may present
some hazard to ships, and it would have to be designed to remain opera-
tional during severe storm conditions.
.Capj tal Costs. It is estimated that the cost of solar-thermal plants will
be not more than two or three times what fossil-fueled plants (less than
$500/kw) or nuclear-genera ting plants cost now, and that rising fuel costs
will eventually tip the balance in favor of solar-thermal plants whose
fuel is "free".(W-4) Before accurate estimates of costs can be made, how-
ever, more detailed engineering studies and some additional researcli are
necessary. But Moinel believes that full-scale solar-thermal power plants
could be built as early as 1985 with an adequate research effort. Other
estimates are somewhat less optimistic, but a group of western utility
companies is considering the development of a small solar-powered facility
that could serve as a prototype for peak load applications.
The capital costs for a floating power plant were estimated by J. H.
Anderson, Jr.'""^) to be only $l66/kw, and the total cost of electricity
to be only $0.00285/kwhr. However, considerable research and development
work needs to be done on various components of this system to verify these
estimates.
Solar Cells
Arrays of solar cells have been developed for use in space applications
to generate electrical energy directly from sunlight. For terrestrial
applications their output is reduced approximately tenfoldrbecause of the
lower radiation intensities and the diurnal variations. In addition,
storage of the electrical energy would be required, as well as conversion
from d-c to a-c power.
Environmenta1 Fac t or s. Thermal pollution is essentially zero for solar
cell arrays, as the sunlight is converted directly to electrical energy.
However, large land areas will be required because of the low conversion
efficiencies (e.g., 6 to S percent presently, perhaps increasing to 20
percent eventually). The estimated direct current output for terres-
trial use is 1 watt per square foot (w"5) so that a 1,000 MW generating
station would require approximately 36 square miles of land area, or about
23,000 acres. There certainly will be an environmental impact of such a
"solar farm" due to thermal updrafts such as now exist over cities, and
536
-------
because the land itself becomes unproductive.
Capital Costs. The present cost of small solar arrays (10 to 100 kw)
using silicon cells is about $300,000 per kw. Projected estimates for
array sizes of 1 to 1,000 liW are $50,000 per kv and for 1,000 to 10,000
IN sizes are $5,000 per Kw. O^"5) Some very recent estimates of costs
of thin-film CdS cells, once fully developed for low cost mass production,
indicate the costs may ultimately be reduced to less than $l,000/kw.
However, the efficiency of these cells may be less than 6 percent.
R&D Expenditure's. More than $10 million have been expended thus far in
developing silicon solar cells for space applications. To develop solar
cell arrays sufficiently to supply a significant portion of the electri-
cal energy requirements of the United States by the year 2000, an expen-
diture approaching $300 million per year for six years may be required. ('•''"-
Table W-3 presents another projected research costs program for develop-
ing low-cost solar arrays as a first basic step toward achieving largo"
scale use of solar cells.' '
Solar-Powered Stirling Engines
Focusing parabolic solar collectors have been used to power small Stirling
hot-air engines' ' >N '' and these could be mass produced for large-
scale generation of electrical power. Ov?~18) ^ parabolic solar collector
6 feet in diameter could generate approximately 200 watts using a Stirling
engine, which is an overall energy conversion efficiency of about 8 per-
cent at peak radiation intensities.
Environmental Factors. Again, a large area of land would be required for
a large-scale generating plant because of the low conversion efficiency.
If many small individual units were used, then somewhat more land would
be required because of space needed around each unit. The land area re-
quired would probably match or exceed that listed tor solar cells, namely
36 square miles for a 1,000 HW station.
The thermal pollution problems would be similar to those discussed for
the Rankine Cycle systems, as waste heat must be dissipated either to
the ambient air or another heat sink.
Capi.ta 1 Cost s. It has been estimated that solar powered Stirling' engines
could produce electricity for about $500 per kw while the sun is shining,
viliich is about one-third of the total time."1' ' These costs were divi-
ded up as follows: $1 per square foot for the 6 foot diameter prarbolic
collector, and $15 each for the 200-watt Stirling engines which could be
mass-produced. The remainder of the costs would involve tracking systems,
maintenance, etc.
R&D Expenditures. Solar-powered Stirling engines are a proven concept in
principle, but some problems with seals and with lubricants over long
537
-------
TABLE V-3. PROJECTED PROGRAM COSTS AKD SCHEDULE FOR THREE OPTIONS
U)
00
~ OFTIOi"
. RSSOttCSS
. PKASS • " '
E?£ IMVS A
?reli-JLiiarjr design & fcislbility asscss-.cnt.
Ccn:cpfjal design of alternative approaches.
Identification of critical systCT, para-.eters.
Fiiasc \
Estibliia aysten feasibility & r.ost dcsirablo
a;;roac :es. Assessment of tc:?i-.ical ad\-anccs needed.
Crass cost ar.4 schedule projection. '
Rase 3
Preliminary dcsic^ of preferred systcn. Detail
assc:s*.:n* of rcquire:r:r.ts iTclvidlr.g resource,
eirufacluriis wl test rcqyircsents. Preliminary
:y:tca :ost 6 r.chcduVo prajcctio.n. All pre-cccsl-t-
rcr.t objccti-rts csrpletcd.
Phase C
Firal definition: Frcesirs of concepts, approaches,
dcilgr.s, schcd-jic:, ari costs of pre£r
-------
time periods arc yet to be solved. Also, optimization studies would be
needed before arriving at a final design for large-scale power plants.
An expenditure of several million dollars per year for 10 years would
probably be required to develop such a system.
Satellite Solar Collection System
This scheme involves the putting of at lenst two giant satellite systems
into synchronous orbits with large arrays of solar cells to intercept
the solar energy. This energy mil then be converted to microwave radia-
tion, and beamed to earth receivers where it. could be reconverted to
electrical energy.(W"19,K-20)
One such satellite solar power station designed to produce 10,000 MW
would have a solar collector array area of 25 square miles, a microwave
transmitting antenna area of 1 sauaro mile, and an earth-based receiving
antenna area of 36 square miles.(W-20)
Environmental Fat-tors. The major impact of this arrangement would be the
possible hazard of the energy beam transmitted to earth. The intensities
may be high enough to cause seme damage to objects or living beings.
Safety measures would have to be devised to prevent entry into the beam.
Capital Costs. Cost estimates for this system have not been published,
but they will undoubtedly be very high. The costs given for solar cells
in another section will apply for the solar collector array. In addition,
there would be the cost of improving the technology for the microwave
transmitting and receiving equipment, as well as putting all of the
equipment into a synchronous orbit.
R&D Expenditures. It has been suggested that -the United States spend $500
million in the next 10 yearn to study the feasibility of a satellite solar
energy system.(W-21)
R&D costs for developing cheaper solar cells to be used in satellite sys-
tems are given in the solar cells section.
Other Systems
Other solar energy conversion systems include thermoelectric and thermionic
converters, and closed-cycle Brayton systems.
Thermoelectric and thermionic systems are described elsewhere in this re-
port, and solar concentrators would be used to provide the high surface
temperatures required. However, as yet, the overall efficiencies and
life expectancies are lovr, and the material costs arc high.
A closed-cycle Brayton (gas turbine) system could be operated using solar
collectors as a heat source, but its overall efficiency would be lower than
a comparable Rankine cycle because a gas compressor would be required in
539
-------
addition to a turbine expander. Also, larger heat exchangers would be
needed to compensate Cor lover heat transfer coefficients on the gas
side, as opposed to higher condensing and evaporating coefficients for
Rankine cycles,
Heat Pumps
The heat pump is a refrigeration system which can be used to provide both
heating and cooling. Heat pumps are also referred to as reverse-cycle
refrigeration, although this is somewhat of a misnomer since the basic
refrigeration cycle is still used. Heat pumps have primarily found
application in the comfort control of residential homes, although some
heat pumps have been installed in larger commercial buildings.
Although the heat pump could theoretically utilise any therirodynamic
cycle that produces refrigeration, economic considerations dictate that
the vapor compressions cycle bo used. The evaporator draws heat from a
low temperature source (the outdoor environment in the heating season and
the indoor environment in the cooling season) and this heat is rejected,
along with the heat of compression of the fluid, to the higher temperature
sink. • During the summer, heat is "pumped" to the outdoors and in the
whiter it is "pumped" indoors.
The most common measure of performance of the heat pump is the coefficient
of performance (C.O.P.), which is the ratio of the "useful" heat moved
to the quantity of energy required to operate the system. In the winter
season the useful heat is the energy rejected by the condenser. The
useful heat in the summer is the energy absorbed by the evaporator.
Table W~4 lists typical values of C.O.P.'s obtainable with various heat
sources and sinks.
TABLE W-4. COEFFICIENTS OF PERFORMANCE FOR
ELECTRICALLY DRIVEN HEAT PUMPS
WITH VARIOUS SOURCES AND SINKS
C.O.P.
Source/Sink Heating Cooling
Air
Water
Earth
2.5
5.0
3.0
3.0
4.0
3.0
540
-------
Environmental Burden
The widespread use of heat pumps for residential and commercial space
heating and cooling could substantially reduce the local air pollution
caused by the more conventional fossil-fuel fired heating systems since
the operation of these systems is essentially pollution free. The
electrical energy that is required is normally generated at a central
power plant where more sophisticated pollution control devices are avail-
able.
Heat pump systems can also conserve significant amounts of energy during
the heating season since a portion of the energy released to the heated
space is energy which vould not normally be tapped. This can be illus-
trated by considering the overall efficiency of utilization of fuel for
heating a home. For a typical gas- or oil-fired furnace, the efficiency
can be considered to be about 75 percent. For the case of the central
power station operating at 40 percent efficiency in conjunction with a
air-to-air heat pump operating with a C.O.P. of 2.5, the overall efficien-
cy can be calculated as 40 percent times 2.5 or 100 percent. This
represents a 33 percent increase over typical residential gas- or oil-
fired furnaces. Thus, the overall efficiency of utilisation of the fuel
is improved considerably. Supplemental resistance heating is sometimes
used in conjunction with residential heat pumps during the heating season.
Any extensive use of this supplemental heating system lowers the overall
energy efficiency and adversely accentuates the demand imposed on central
stations.
The environmental impact of using air as the heat source/sink is quite
small, but if water or earth is used as the source, the impact on the
environment must be assessed more carefully. If well water is used, the
water must be disposed of in a suitable manner, which usually means
drilling another well to return the heated or cooled water to the ground.
For earth heat sources, the changes brought about by continuously with-
drawing or adding heat from or to a finite mass of «;arth must be assessed.
Capital Costs
A three-ton heat pump unit installed in a typical residential home
( 1500 square feet) would cost about $1800. Operating costs of heating
a home with an electrically driven heat pump run appreciably higher than
the same house heated by natural gas, but about half as much as the same
house heated by electrical resistance heating.^
R&D Expendi turcs
Heat pump technology is well developed at the present time and commercially
available units have been on the market for some time. These units have
not found wide acceptance in the northern part of the country; however, due
to the fact that the C.O.P. of the, air-source heat pump drops off at
lower ambient temperatures. The use of solar energy as a heat source has
541
-------
received some attention. If suitable techniques for ^utilizing this energy
could be developed, the use of heat pumps would undoubtedly become more
widespread.
Ceothermal Power
System Description and Status
Geothermal power is the utilization of heat from the earth's interior to
produce electrical power and serve other useful purposes.
The present world utilization of energy from geothermal sources is about
1200 MW. While this represents an exceedingly small percentage of total
world and United States usage (about 0.1 percent in each case), geothcr.na!
power can be significant in its local utilization, e.g., California, Italy,
and New Zealand. The relative anticipated growth of geothermal power is
estimated to be 4000 MM by 1980, Approximately one-third of this growth
will occur in California, of which the majority will be in the Geysers
region.
In a recent article on geothermal energy Rexv^"22) estimated that by con-
certed exploration and development the proven geothermal resource could
be betwen 100,000 MW and 1,000,000 1E-I in the year 2000. Another(w~23)
estimate of the geothermal resource is 132,000 NW in 1985 and 395,000 1-!W
in 2000. By comparison, the present power capacity of the United States
is a little over 300,000 MW.
At the present time, any discussion of geothermal power1 must keep in mind
the distinctions between utilization, resource, and resource potential.
Thus, while present utilisation is small (about 1200 Ml'.') and proven re-
sources only a few times that, the known resource potential is significant-
ly larger. The utilization of this resource potential, both in the United
States and the world, will depend on technological development as well as
political and economic factors. Large-scale utilization of geothermal
power is unproven, but the tremendous resource potential as well as
advantages in economics, environmental pollution, and nondepletion make
it a highly attractive source for future energy needs.
Description of the Geothermal Energy System
In certain limited locations groundwater through pores and fissures in the
rock conies in contact with hot material rising from the earth's interior.
This results in locally large natural underground reservoirs of steam and/
or hot water which can be tapped by drilling to drive turbines in power
plants and provide space heating in buildings and greenhouses. These
geothermal energy sources can be described by
1. Natural steam systems.
(a) Dry steam fields which have a relatively high energy content
542
-------
(b) Wet steam fields which produce a mixture of hot water and
steam and have a lower energy content
2. Hot water fields which have a low energy content.
Fields of the first type can be used directly to produce electrical
energy from steam. It has been proposed that a heat exchanger using a
low boiling fluid such as freon be used to produce electricity in the
second type. The economics of this system have not been demonstrated
and may be unfavorable. This hot water source of energy can also be
used for local heating.
All types of geothermal resources are currently being used as sources of
energy. Dry'steam fields are generating about 700 MW of power at
Larderollo, Italy, and the Geysers, California. The Uairakei, New
Zealand, field produces about 200 MW of power from wet steam. At Cerro
Prieto, in Maja, California, a wet steam field is expected to start
producing 75 MW in January, 1973. Geothermal hot water is used for
residential heating in Oregon, Idaho, Iceland, and Siberia.
The identification of these geothermal resources has been based on surface
manifestations, e.g., hot springs and geysers. This is quite similar to
the early identification of oil reservoirs. As resource identification
techniques improve the extent and magnitude of the hot water or steam
geothermal resources are expected to increase significantly. This could
result in increased planning for the utilization of geothermal energy by
the nations' utilities companies.
Another, possibly more extensive, source of geothormal power is dry, hot
rock which does not have water associated with it. Means of tapping this
geothermal potential have not proved technically feasible, but field
experiments to test the concept have begun. Should this concept be
proven feasible, geothermal power could be used extansively.
A possible third geothermal energy source exists; the so-called geo-
pressure regions. Deep sedimentary basins filled with sand and clay or
shale of a young geologic age (such as exist off the U.S. Gulf Coast) are
generally undercompactcd to depths of several kilometers. The resultant
pores are filled with fluid. However, because of the undercompaction these
interstitial or pore fluids are at pressures between the hydrostatic and
lithostatic head. These regions are said to be gcopressurized.
The search for oil and gas throughout the world has discovered many geo-
pressure reservoirs. These have not been tapped for geothermal heat. The
location of many of them occurs in regions different from the steam and
hot water sources so that the geopressurc regions could potentially expand
the geothermal resource potential significantly.
Natural Steam Systems
As described above, the natural steam systems can be divided into dry and
543
-------
wet sources. The means of using dry geothermal steam to generate elec-
tric power is straightfon.'ard and is like the similar portion of a con-
ventional power plant except that the operating pressures and tempera-
tures are considerably lower. This requires turbines of special design.
•
Steam is available at the well head and is piped directly to the power
plant. The steam requires no special treatment other than filtering
out rock particles. The steam is expanded through a turbine, thereby
turning a conventional electric generator. The steam is discharged
through a condenser and converted into water. Because the dry steam
contains low impurities, the majority o£ the water can be evaporated
in cooling towers. A small amount of water containing concentrated
impurities must be dJsposcd of by surface means or by reinjection into
the ground.
In the case of wet steam sources steam must be separated from the water.
The hot water rising in the geothermal wells flashes to a mixture of
steam and water as the pressure decreases. The stcan and water are
separated outside the well head; the steam follows a cycle similar to
that described for the dry source. The water must be discharged into
the environment or rcjnjectcd into the ground. Because the water makes
up two-th'irds to four-fifths the fluid removed from the ground and
often carries a large dissolved mineral content, it poses serious en-
vironmental problems. Ceopressure systems may provide water hot enough
to flash into steam.
Hot Water Systems
In this proposed system, the hot water is pumped through a heat ex-
changer. Part of the energy would be transferred to a low boiling work-
ing fluid such as frcon and isobutane. The geothermal water, now
cooled, can be returned to the earth or disposed of in some other way.
The heat exchanger act.s as a boiler for the working fluid which is
evaporated and passed through a power turbine to generate electricity.
The fluid is then condensed and the working fluid is pumped to high
pressure and again run through the heat exchanger. This is -exactly
the fashion in which a conventional fossil-fired steam boiler or a
nuclear power plant operates. This type of system is also usable for
a pumped wet steam energy source.
Dry Rock Systems
The proposed dry rock system would utilize the energy from hot-dry
rocks close to the earth's surface. These are believed to be much more
widespread than the steam and hoc water sources. The approach would
be to drill a well deep into the hot rock. This rock is then frac-
tured by some means in order to provide a large volume whereby a work-
Ing fluid can be injected and heated. It has been proposed to fracture
the rock by conventional hydrofracturing techniques(w~24) or by nuclear
explosives.(W-25) Both approaches are unprovcn and speculative.
544
-------
The working fluid is injected into one drill hole and removed from an-
other drill hole spaced a considerable distance away. Depending on the
site location, temperature and pressure of the working fluid, and avail-
ability of local water, the power generating part of the cycle can be
any of the above discussed options or a suitable combination of them.
Potential Environmental Burden
Impact on the Land.
Land Use. The most obvious environmental effects associated with geo-
thermal power is the intrusion of an industrial operation into a usually
nonindustrial area. For example, a geothermal well is drilled in the
same fashion as an oil well. Problems include noise, the appearance of
drill rigs, access roadways, drill platform pads, drill cuttings, and
drill fluids. After the well is drilled it must be tested. This re-
sults in noise, wastewater, and probable air pollution. These are tem-
porary effects and can be minimized by careful planning. Once drilled
and in production the actual geothermal well can be made unobtrusive
and, hopefully, will offer no severe environmental problems.
Because the working fluid cannot be moved more than a mile without
serious heat loss, the generating plant must be located near the wells,
thereby localizing the total environmental impact to the site where the
geothermal field is located. The fluid is transported to the generating
plant by insulated pipes; these pipes are costly to run below ground;
therefore, the tendency will be to run them above ground. Such pipes
are visible environmental disturbances. The power and water plants are
conventional with noticeable noise level and cooling towers. The cool-
ing towers are large and evaporate steam into the atmosphere. Thus, a
residential usage would generally be incompatible with a geothermal
field.
Using the Geysers field as an example, present well-flow information in-
dicates that sufficient steam can be produced for a 1000 MM plant from
an area between 4 and 8 square miles. However, since only a small part
of the whole field is required for the wells, pipelines, and generat-
ing plants, the rest can be utilized for other purposes. For example,
at the Lardercllo field in Italy, where geothermal steam has been util-
ized for power production for nearly 60 years, an intensive agricultural
industry is carried on within the steam field, and many vineyards and
orchards are interspersed among the pipelines and wells. 0^-26)
The uses of the land associated with a geothermal field must be site de-
pendent, e.g., topography, climate, ground cover, etc. Many of the
known geothermal resource areas in the United States occur in places
that arc valued for their scenic beauty. Thus, the industrial character
of the geothermal area will notably affect the scenic values. The
evaluation of the environmental impact of a 520thermal field on the
land seems to be dependent on the viewpoint of the observer.(W-26,W-27)
545
-------
However, there seems to be general agreement that the'environmental
impact of a geothermal field is less than that of a correspondingly
sized nuclear or fossil fuel plant if one considers the total impact
of the mining, milling, fabrication, transportation, plant facilities,
fuel storage, and waste.
Subsidence. When large quantities of fluids are removed from an under-
ground reservoir, the land surface may sink. The consequences are
sometimes disastrous as was the case with the Wilmington, California,
oil field. Subsidence can occur when the reservoir rock is very porous;
removal of the fluid can cause the rock grains to fail or compact. If
the reservoir consists of fractured rock, subsidence is unlikely. The
ideal approach to utilization of the geothermal resource would be to re-
move fluid af or near its recharge rate, thus conserving the resource.
This approach would probably eliminate the subsidence problem. Since
subsidence could have serious environmental effects, but is not common,
future geothermal developments will have to be monitored for this
effect.
Seismic. Experience near Denver, Colorado, has indicated that seismic
activity can be stimulated by the injection of water deep underground.
The seismic effects of water withdrawal and reinjection in geothermal
fields will be peculiar to the particular area, and cannot be stated to
be or not to be a problem at this time. There are suggestions that the
induced nicroseisuiiri ty relieves strain on faults and tends to prevent
major earthquakes. 0'-'-28) However, because this seismic activity is not
predictable at the present time, it should be carefully monitored to in-
dicate possible hazards.
The seismic effects associated with nuclear stimulation of a dry geo-
themial resource is a different situation. While these effects are de-
pendent on the size of the device, depth of burial, geological struc-
ture, and location, it is highly unlikely that device sizes larger than
100 kilotons will be seismically acceptable for use at most locations.
Pollution Factors.
Thermal. In order for a thermal electric power plant to operate at
maximum efficiency, the steam must be condensed after passing through
the turbine. The amount of cold water required to condense the steam
in thermal plants is large. An efficient 1,000 MW fossil fuel plant
using cooling towers evaporates 15 to 25 million gallons of water a day,
whereas a nuclear power plant, because of its lower thermal efficiency,
evaporates about 50 percent more water. However, geothermal plants
that utilize dry steam do not require additional water for cooling.
The natural steam, after passing through the turbine, is condensed
wlthir the circulating cooling water and thus provides additional water
to the cooling towers. Thus, the dry stcan geothermal system should
pose little or no problem of thermal pollution to local water sources.
When the utilization of the geothermal resource is of the closed-cycle
546
-------
design, such as in the pressurized wet steam source or in the proposed
hot-dry rock source, the heat is transferred to a working fluid through
a heat exchancer. The working fluid must be cooled and condensed. This
can be accomplished by using cooling water or air. The latter approach—
using forced-draft, air-cooled condensers—has been specified for the hot
dry rock source(w~2^) in order to avoid thermal pollution of water
bodies and to have freedom in siting. The authors state that "the
economics for this type of geothernial power arc- so favorable. . .that
the additional...generating costs associated with the air-cooling equip-
ment can easily be absorbed".
Wastcwater. The experience at the Geysers seems to indicate that waste-
water is not a problcu for dry steam sources. This results from the
fact that the underground fractional distillation of steam leaves the
majority of the dissolved minerals behind.
However, the surplus water remaining after evaporation in the cooling
towers contains trace chemicals which preclude its discharge into the
local streams. The water would require further treatment, or as at
the Geysers, must be reinjected into the ground in deep wells. This
amounts to about 20 percent of the condensate. For 100 MW of generating
capacity, this amounts to over 1 million galIons/day. One large injec-
tion well can accommodate this flow. Thus, a 1,000 MW plant might re-
quire several large injection wells.
A more difficult problem arises when the geothermal wells produce hot
water, or a steaii/water mixture. In these cases the surplus water
muct be disposed. In GOF.C instances, when these wastes arc high in
mineral content, they cannot be discharged into surface waters. Unless
very well mixed, even ocean discharge could lead to severe local effects
if the plant waste differed substantially from ocean water.
At Cerro Prieto, in Mexico, the waters contain about 2 percent salt
(ocean water contains 3.3 percent salts) . For a geothemal electric
plant located here and of 1,000 1-M size, it has been calculated that
saltwater would be produced at a rate of approximately 150 million
gallons/day, or over 150,000 acre-foot annually. For a 2 percent
brine solution, 12,000 tons/day of salts would result if the water was
evaporated away. For the 20 percent brine found in the Salton Sea
area, 120,000 tons/day of salt would result. This poses a monumental
solid disposal problem, and constitutes a real environmental danger>w~-7'
Thus, the disposal of brines is a serious environmental problem.
The method that appears most promising is disposal into injection wells.
An injection well is drilled to a depth where a porous formation will
accept the water. To avoid contamination of ground waters, these
depths may involve several thousand feet. After overcoming original
well-head pressure, it is often found that the water can be literally
poured down the hole. This method has found wide use for disposal of
oil well brines and industrial wastes. One must take care to avoid
aquifers that connect to areas where the waste will do harm, e.g.,
547
-------
sources of agricultural or potable water. This is not thought to be a
problem in geothermal areas. Should this proposed technique prove
successful a major environmental problem facing geothermal power will
have been eliminated.
Air Pollution Factors.
Air Pollution. Noxious gases are often a by-product of geothermal wells
and hydrogen sulfide O^S) is generally the most prevalent. It exists
in the steam with other gases, most notably carbon dioxide. The r.oncon-
densable gases average 1 percent of the steam flow at the Geysers. (W~30)
Of this, 79 percent is C02, 5 percent methane, 1 percent hydrogen, 3
percent inerts, 5 percent H£S, and 7 percent ammonia.
The above figures indicate that l^S is present in the steam to the amount
of 500 parts per million (ppm) . If a total of 1,000 MW of power were
produced there, this would require 430 million pounds/day of steam. Thus,
215,000 pounds/day of l^S will be released. Other figures (w~31) suggest
that the amount of I^S released at the Geysers would be less, about
100,000 pounds/day.
Using the data from Cerro Prieto, an estimate can be obtained of the
amount of ^S that might be found in a field yielding hot water. It has
been reported(w~32) that H2S is present in the amount of 0.26 percent by
weight in the steam. Other data supplied by the geotherraal project at
the University of California at Ri \erside indicate substantially smaller
amounts, with wide variations between individual wells. If the higher
value is assumed, and a steam rate (20 pounds /kvhr) , a 1,000 MW plant
would Dead to the production of 1,230,000 pounds/day of l^S. This number
exceeds that found in fossil plants burning hi&h sulfur fuel. Thus, it
is seen that noxious gas control is apt to be an essential part of geo-
thermal power production. If necessary, technology is available to pre-
vent the release of these gases if extensive fields are developed.
In addition to l^S , there most certainly could be other chemical species
which would adversely affect the environment if discharged. into the
atmosphere. Some of these might be Radon-222, lead 210, or ammonia.
Other emissions associated with drift from the cooling 'towers , e.g.,
boron, heavy meLals, and fluorides, can degrade the surrounding environ-
ment. Rain water and other natural processes may spread this over a
larger area. The severity of any of these contaminations will be site
dependent and must be weighed separately and carefully. In general,
solutions can be found to prevent this contamination; the most drastic
would be an enclosed system.
Thermal. The significant environmental effect to be expected in routine
operation of a geothermnl. power plant is heat rejection. All power
production cycles using thermal energy reject heat, and the less effici-
ent they are, the greater is the heat rejection. Geothermal steam is
available at low pressure and temperature, when compared with that from
conventional boiler or nuclear plants. Thus, the heat rejection will
548
-------
be higher. This is clearly indicated by the comparative steam rates
(which can be roughly equated to comparative h6aL rejection) for the
Geysers and a modern fossil plont. The rate for Geysers' numbers 3
and 4 plants is given as 18.53 pounds/kwhr, while Moss Landing 6 and 7
is shown as 6.68.
For 100 psi inlet conditions, and a water tower-cooled condenser, ther-
modynamic calculations show that. 3,630 KW of heat are rejected by a
1,000 MJ geothermal electric plant (a 1,000 Ki-J nuclear power plant re-
jects approximately 2,000 MH of heat). Water yielding geothermal fields
can be expected to have heat rejection rates several times this.
If air-cooled condensers are used, the rejected heat will be Jarger
and will go directly to heating the atmosphere. How this heated air
would distribute itr.elf and affect the local climate will require de-
tailed consideration of local conditions. If water cooling towers are
used, the temperature would be affected to a lesser extent, but sub-
stantial quantities of water would be evaporated, thus influencing the
humidity. Considering the heat rejection rate, and for typical cooling
tower performance, up to 50,000 acre-ft/yr of water will be evaporated
by a 1,000 MM plant.
This amount of reject energy is small when compared to the solar heat
input over even ]0's of square miles. Thus, no large-scale environ-
mental effects are expected. However, in the immediate vicinity of a
concentration of several 1,000 MVJ plants, considerable environmental
effects are possible.
Well Blow Out. In any well driving operation involving high pressure
fluids, the possibility of a wcJl blow out must be considered. Such a
blow out affects land, water, and air. For this reason, it is con-
sidered separately.
The classic oil well blow out is one type that can occur. Such a blow
out can release large quantities of brine if it occurred in a water
yielding geothermal field. The release of the brine into waterways
and agriculture areas would cause severe local environmental problems.
Listed in Table W-5 are the typical environmental burdens that might be
experienced with a. 1000 MW geothermal plant.
Energy Systems Development Cost
As indicated, geothermal energy is commercially utilized today on a
small scale. However, a program to expand its utilization on a major
scale has been described on a preliminary basis in September, 1972, by
W. Hickel, et al.(w~23) This program includes the following subject
areas:
549
-------
TABLE W-5. BURDEN-OF ENVIRONMENT 1,000 MW GEOTIIER.MAL PLANT
(Subject to very wide variation with source of
gcotliermal heat and recovery system used.)
Effluent or
Environmental Effect
Quantity
Anticipated
Regulation
Thermal Effects
Air Pollution
Contaminants
Wctcr Pollution
Contaminants
Land Despoilment
Geological Effects
Seismic and
Subsidence
dry steam 4,000 KW
wet steam 10,000 MW
NO _ - No problem
X
SO. - dry steam
Geysers
wet steam
3(10) tons/year
,5
Cerro Frieto 2(10) tons/year
Solid ParLjculate - No problem
Truce chemScal
species
Variable by
0 to
site, tons/year minimize
dry steam 3(10 ) gal/year 0 release
containing 10* ton/year solids
Geysers
wet steam 5(10 ) gal/year
containing 5(10)5 tons/year -
Ccrro Trieto
5(10) tons/year -
Sallon Sea
3,000 - 5,000 acres
Possible problem of
unknown extent. Cost
of monitoring must be
considered.
(a)
None
allowed
Ecological Effects
Social Effects
Noise
Visual Impact
Minor
Great
Great
Minimize
< 100 db
Minimize
(n) Ccrro Pricto will be operating in January 1973. Environmental infor-
mation available after startup and actual operation will be valuable
'for future assessments.
550
-------
Resources Exploration
Resource Assessment
Reservoir Development and Production
Utilization Technology and Economics
Environmental Effects
Institutional and Legal Aspects.
The research needs of each of these subject areas was explored in de-
tail for 2 days by a panel of 8 to 10 recognized experts (total about
60). Thus, the results of these efforts represent the latest opinions
of the most knowledgeable people working in the area. Table W-6 tabu-
lates their recommendations for the 1974 to 1983 decade. Other funding
recommendations could be made but it is felt that the immediacy of these
recommendations, plus the combined knowledge of the assembled experts,
is sufficient to justify its use here. However, this particular aspect
should be studied in more detail in the future.
Compilations of the estimate of R&D costs are shown below.
Estimated Costs for Geothernal R&D Program
R&D Cost Range - $500 million to
$1 billion
R&D Time Range - 5 to 15 years
Estimated Funding Effort and Requirements
(millions' of 1972 dollars)
Expenditure Expenditure Through the Year
to date (for each period)
1972 1975 1980 1985 1990 Beyond 1990
$10 $110 $420 $270 $250 $300
The estimates of the amount of energy that can be developed vary widely.
An estimate number for the United States by the year 2000 is 400,000
megawatts.CM"23i W-33)
Effectiveness and Economic Costs for Pollution Control
A very preliminary estimate of the cost to achieve forecast require-
ments for pollution control is shown in Table W-7. The primary en-
vironmental burden is from waste heat. The low thermal efficiency
0\<20 percent) results in rejection of 4,000 MW of heat for 1,000 MW of
capacity. If it is assumed that such a plant uses the same types of
heat rejection systems as current fission power plants and that the two
types of plants have the same MW capacity, the cost for the waste heat
dissipation system for the geothermal plant then becomes dependent pri-
marily on the thermal efficiency of the plant. For the most probable
range of thermal efficiencies, the relative cost of the waste heat
dissipation systems for a 1,000 MW geothermal plant are as follows:
551
-------
TABLE W-6. PROPOSED GEOTHERMAL RESOURCES RESEARCH PROGRAM
(Xillions of Dollars)
Fiscal Year
1574 1975 1976 1977 1973 1879 193C 1981 1932 1983 Total
Resource Exploration 5.0 8.0 11.0 9.5 6.0 3.5 2.0 1.5 1.5 1.5 49.5
Resource Assessment 15.6 23.4 27.S 29.4 31.2 30.4 30.3 31.3 30.3 24.0 273.7
tn
ro
Reservoir Development
and Production 5.0 13.5 27.0 44.0 48.0 21.5 23.0 13.0 10.5 10.0 215.5
Utilization Technology
end Econonics 9.9
0.9 11.9 11.3 10.5 9.1 9.1 9.1 9.1 9.1 99.5
Environmental Effects 4.2 4.2 3.8 3.6 3.5 3.3 3.3 3.4 3.4 3.3 36.0
Institutional
Considerations 2.0 2.0 1.3 1.3 ^j.Q __0.3_ 0.5 0.5 0.5 0.5 10.S
Totals
41.7 61.0 83.0 • 99.S 100.2 63.3 68.2 58.3 '. 55.3 43.4 684.7
-------
Relative Cost for •,
Thermal Efficiency Waste Heat Dissipation System
10 2.47
15 1.87
20 1.52
25 1.28
33.3 1.00
TABLE W-7. EFFECTIVENESS AND ECONOMIC COSTS (1972 Dollars)
FOR POLLUTION CONTROL WITH RESPECT TO MEETING
EXISTING AND ANTICIPATED REGULATIONS
(Geothermal Power 1,000 MW Plant—Capital Costs Only)
Effectiveness,
percent Cost;, $
Thermal effect
Mr pollution
Water pollution
Land despoilment
Geological effects
Social effects
95.0
99.5
100.0
90.0
90.0
90.0
20,000,000 - 50,000,000
5,000,000
5,000,000
5,000,000
2,000,000
2,000,000
Thermonuclear Fusion
Introduction
It is generally recognized by scientists that controlled fusion will
play a central role in meeting the energy requirements in the near-
term future. This recognition is based on favorable technical factors
and on a consideration of alternative fuel reserves. The technical
outlook was recently reviewed by the Joint Committee on Atomic
Energy(W~34) and progress in theoretical descriptions and confirming
experiments have permitted optimistic projections for scientific feasi-
bility demonstration experiments and subsequent controlled thermonuclear
reactor (CTR) systems. The impetus for fusion which derives from a
consideration of fuel reserves is illustrated in Table W-8. These re-
sults clearly show the relative shortage of fossil and rich-ore ficsile
fuels are the driving force toward CTR.
The basis for fusion power is the energy released in combining light
elements with a. consequent release of nuclear binding energy. At
ordinary temperatures these nuclei are prevented from combining by
electrolystatic repulsion but fusion can be achieved if these nuclei
553
-------
must be heated to temperatures near 50,000,000 C to provide sufficient
thermal energy for fusion reactions to occur at a useful rate. At
these temperatures the nuclei are completely stripped of electrons and
the subsequent electron/ion region is referred to as a plasma.
TABLE 17-8. WORLD ENERGY RESERVES OF "INFINITE FUELS'1^"35 >W~36 >U~
Years at 2.8x10 Btu Per
Energy Source Known Possible
Fossil
Coal 6.8 100
Oil and Natural Gas 1.8 25
Total 8.6 130
Fissile
Rich-Ore Burners 2.7 , 7.1
Low-Grade Ore Burners 1.0(10) 3(10) '
Rich^Ore Breeders 107 340
Low-Grade Ore Breeder 3.4(10) (10)
Total Rich Ore 110 347'
Total Low-Grade Ore 3.5(10) (10)
Fusion „
Deuterium (10):. (10)
Lithium (10) (10)6
.Solar (10)JU (10)
ao
(a) The value of 2.8x10^8 utu is the quantity estimated to rseet pro-
jected world population needs with per capita consumption rate of
United States in 1970.
There arc a number of energy cycles which can potentially be used in
a CTR. Some of the more prominent cycles are shown in Table W-9. In
addition to these cycles, there are other reactions with isotopes of
higher Z number which can undergo fusion.(W-38) Their application is
not as promising, at this time, however, as the reactions displayed in
Table W-9. In Table W-9, the initial reaction, the deuterium-tritium
(D-T) reaction, is the reaction that probably will receive the bulk of
the attention in the early commercial stages of exploitation of the
fusion process because the ignition temperature is lowest. Therefore,
the rest of this discussion will center around this particular energy
cycle. - In the D-T reaction the available energy resides in an ener-
getic neutron; in other cycles the energy can largely be found in
charged particles. It is worth pointing out that any deuterium fueled
554
-------
fusion plant would have all of the reactions given in Table W-9 taking
place to some degree. Therefore, problems identified with the D-T cycle
would exist to some degree in other fuel cycles.
TABLE W-9. PROMINENT CTR ENERGY CYCLES
Reaction Reaction Products Total Energy (Mcv)
23 41
11 2 o
H2 . ,,2 H3 1
l" + l" 1H + 1H
22 31
jlT + Lr 2HeJ + Qn
17.6
4.03
3.27
18.3
Description of the Energy System
Because significantly high-power levels have yet to be demonstrated in
the laboratory, it is premature to discuss the design of a CTR power
plant. However, based upon the available experimental data and some
informed speculations, one can describe some of the main features of a
conceptual power station.
Two distinct methods are being seriously considered for creation of a
controlled thermonuclear reaction. They can be grouped according to the
scheme proposed for confinement of the ion plasmas. In order to create
a controlled thermonuclear reaction, it is necessary that one create a
hot gaseous plasma of the desired reacting constituents (i.e., deuterium
and tritium) and that this plasma be confined for a time period which is
long compared to the fusion reaction time. The two methods which have
been proposed for confinement are the electromagnetic confinement method
and the inertial confinement method.
The electromagnetic confinement method is based upon the observation that
plasma containing energetic ions can, in principle, be shaped by one or
more electromagnetic fields. This method of confinement has received
the bulk of the research effort to date.^ 39> °' Several geometric
configurations have been proposed for developing the required magnetic
fields. The configurations can be broadly classed as the cylinder or
open geometry and the toroidal or closed geometry. In the open geometry
a magnetic field confines the plasma in a long cylinder and magnetic
"mirrors" are placed at the ends of the cylinder to minimize end losses.
In the closed geometry a continuous torus is used as the confining geo-
metry. Both the mirror and torus geometries are distinguished by a
555
-------
number of different conccpLs which involve varying geometrical condi-
tions, magnetic field configurations, and plasma conditions. At the
moment, the most successful approach appears to be the Tokamak varia-
tion of the torus group. In the Tokamak system large currents induced
in the plasma provide strong resistive hnating and supply an important
component of the confining magnetic field. Since the field is gener-
ated by induced currents instead of external windings, a compact fusion
reactor is possible in a toroidal geometry. Successful experiments in
the USSR in 1968 have turned worldwide research attention to Tokamak.
In most considerations of magnetically confined systems the facility
costs force the system toward large generating capacities, typically
10,000 MWt.
Inertial-confinement systems are based on heating the fuel at a rate
which is fast compared to the expansion of the resultant plasma. One
of the fastest developing inerfial-confinement concepts involves laser-
induced microdetonations. (W-35, W-41) Major improvements in design have
made giant pulsed glass lasers available at an acceptable cost. These
are capable of delivering the necessary energy in short bursts (about
10,000 joules in one billionth of a second or less), and are believed
to be adequate for demonstrating feasibility. The relatively low effi-
ciencies typical of glass lasers are a disadvantage that can probably
be overcome either by further development or, to speculate a little,
by devising suitable gas lasers; efficiencies approaching 50 percent
have been reported for carbon monoxide lasers. One strong advantage of
this concept is that it eliminates the need for large superconducting
magnets which are required for the electromagnetic approach. This per-
mits system designs of smaller total generating capacity,, perhaps a
few-hundred MWt.
Both the magnetically-confined and inertially-confined concepts employ-
ing D-T share the need to produce tritium artificially because natural
supplies are insufficient to support the need. Figure W-3 illustrates
this cycle. Lithium is placed in the blanket to jccomplish this goal.
Therefore, the D-T energy cycle can be thought of as a deuterium-lithium
(D-Li) cycle, and, in fact, the viability of this cycle is limited by
the available lithium supply although the known lithium reserves have
been estimated to be adequate for tens of thousands to millions of
years.(W-35, W-37)
The fuel cycle shown in Figure W-3 would, of course, vary somewhat de-
pending upon the final CTR design. However, the major processes have
been identified. Recovery of deuterium (from fresh or seawater) is a
complex but well understood technology by itself. Presumably, the
mining and refining of lithium metal can be readily defined. The re-
covery, handling, and injection of tritium bred in the reactor blanket
is somewhat less well understood, but it is accepted that these functions
are necessary.(W-42)
A number of different energy conversion schemes could be utilized depend-
ing upon the specific characteristics of the plasma and design of the
556
-------
Deuterium
Supply
(From
Water)
Lithium
Mining
Fuel
Manufacture
and Injection
_/• v
Tritium
Processing
Electrical
Energy
CTR
Power
Station
T
Ash
Tritium
Recovery
FIGURE W-3. CONCEPTUAL DEUTERIUM TRITIUM FUEL CYCLE
557
-------
reactor. IL would seem likely that the initial power plants would cm-
ploy conventional steam turbines. A second generation plant could pos-
sibly employ a liquid metal Lopping turbine, as suggested by some in-
vestigators, (W-43) to improve plant thermal efficiencies. If developed,
large-scale gas turbines would be particularly attractive for applica-
tion to CTR power plants. Finally, because a significant fraction of
the energy of some fusion reactions is given off in the form of charged
particles, a direct conversion scheme similar to the operation of a
charged particle accelerator in reverse, appears conceptually possible. '
In this case presumably the unit would have both a direct and an indirect
conversion system with resultant high net thermal efficiency.
Both the magnetically- and inertiall>-confined systems woul'd employ some
form of a pressure vessel to contain the plasma vacuum. Certain exotic
metals capable of high-temperature duty, such as vanadium, molybdenum.
and niobium have been suggested for the structural component of this
vessel. At the present time, there is not sufficient data to make a
clear selection and, in any case, it would appear that the initial plant
would employ steel as the vessel structural material. The more exotic
metals would probably come into play with the development of a second
generation unit.
Based upon the previous discussion, one can develop a rough conceptual
design of a power station based upon the two confinement methods. The
major elements of such a station arc:
o A plasma confinement and heating scheme
e A plasma vacuum vessel
o A moderating and shielding blanket
e A fuel handling and refueling system
o A power conversion unit.
Based upon these elements, Figures W-4 and W-5 display conceptual de-
signs of probable first generation CTR power stations. Figure W-4 shows
an electromagnetic confinement station and Figure W-5 shows an inertial
confinement station.
Detailed cost estimates for cither magnetically-confined or inertially-
confined systems cannot be made because plant engineering cannot pro-
ceed without basic design information. In general, however, among the
crude estimates that have been made, the reactor plant equipment and
nuclear engineering costs for the magnetically-confined systems are
slightly higher than those for breeder reactor systems and these costs .
for the inertially-confined systems are competitive with these systems.
An example of projected costs for a magnetically-confined system
Nuclear Boiler $60-70/kw(e)
' Magnets $30-60/kw(e)
Fuel 0.00035c/kwhr
Other $70-100/kw(c)
«/$200/kw(c)
558
-------
Laser
Beam
Heater
in
Pellet
Injection
Shield
Blanket
Vacuum
Vessel
Plasma
Fuel
Recovery
Steam
^Generator
Electrical
Generator
Steam
Turbine
Condenser
Pellet
Manufacture
Fresh Fuel
FIGURE W-4. CONCEPTUAL DESIGN OF AN INERTIAL CONFINEMENT CTR POWER PLANT
-------
in
s
Steam
/Generator
Electrical
Generator
FIGURE W-5. CONCEPTUAL DESIGN OF AN ELECTRO-MAGNETIC CTR POWER PLANT
-------
Environmental Burden
One principle advantage of a fusion power system over a fossil system
is the total absence of combustion products; this advantage is shared
with fission plants. Another advantage of fusion power is that radio-
active vaste is localized relative to fission plants because no fission
product inventory, or radioactive material reprocessing, is associated
with the operation. The possibility of direct conversion of the highly
charged fusion products into electricity with the attendant advantage of
thermal efficiency has been cited.(W-46) Another noteworthy advantage
of fusion power is the freedom from a nuclear excursion or criticality
accident which is a concern of all fission power systems. This is a
consequence of the physics of operation; fusion entails no "critical"
quantity of fuel and the associated possibility of an "over criticality"
condition.
Although these relative advantages exist, fusion power will have an en-
vironmental impact. Except for the direct conversion concepts, a
conventional thermodynamic cycle is contemplated with the accompanying
problems of thermal effluents. Probably higher temperatures will be em-
ployed with the attendant reduction in waste heat per unit electrical
power, but this is usually a modest savings (perhaps 15 to 20 percent
at best). The fusion plant will likewise have a chemical discharge from
coolant treatment and other metal/chemical discharges. These are not
unique to the system and, therefore, are not discussed further here.
The effluents which are peculiar to a fusion reactor power plant are
summarized in Table W-10.
TABLE W-10. SUMJIARY OF EFFLUENTS FROM D-Li ENERGY CYCLE
Effluent
Source
Release Point
Tritium
Fusion Ash
(2He*, etc.)
Waste H20
Lithium Tailing
Radioactive Waste
Bred in Reactor from
Lithium
Created in Reactor
Deuterium Collection
Mining Process
Neutron Reactions with
Structural Components
or Reactor
Leakage Through Reactor
Wall
Release from Plant
Isotope Separations Plant
(Back to Source)
Refining Process
At Plant Disassembly or
561
-------
Of the effluents created by tlie D-Li energy cycle, tritium lias probably
the largest potential environmental impact. • The D-Li energy cycle would
consume .2 kg of tritium per day per 1000 MWt. The station inventory
has been estimated to be between 1 to 15 kg per day per 1000 MWt;(w'*7)
this is about 1,000 to 100,000 rimes the lithium inventory in a fusion
plant. If the inventory per 1000 Ml.'t is 1 kg, the plant leak rate must
be .0012 percent per day in order to meet existing regulatory standards.
The current technology for leak rates on large systems such as nuclear
power stations is higher by one to two orders of magnitude.(W-39)
As currently envisioned the radioactive waste associated with the D-Li
energy cycle comes primarily from neutron-induced structural activation.
If stainless steel is used the activation rate is expected to be com-
parable to vanadium or molybdenum whose long-term activity has been
estimated to be one-thousandth that of a comparable fission power
plant.(W-47) if niobium is selected ns the base structural material,
radioisotopes of Nb, Y, and Zr will be formed and activity comparable
to a LMFBR can be anticipated. While the opportunities for dispersion
of this material do not exist in a manner comparable fo an LMFBR, it
does represent an ultimate burdan on the environment. A more detailed
evaluation of this is needed.
Small quantities of the ash from the fusion process would be released
from the D-Li fusion cycle. The D-Li cycle will produce and presumably
release about 250 grams of 2!le l Per day Pcr 1000 l-Vrll.
In order to separate the deuterium required for the D-Li cycle, it will
be necessary to use, in a nonconsur.ipLive manner, some 16,000 gpn of
seawater per 1000 MWt of installed capacity to meet the makeup fuel
requirements of the plant.(W-48) By comparison, about 240,000 gpm of
cooling water would be required to disperse this amount of heat.
The lithium mining cycle would produce measurable quantities of efflu-
ents. Perhaps the best way to characterize the mining problem is by
way of comparison to the uranium fuel cycle. Assuming a strategy based
upon total use of both fuels, about one-third as much lithium needs to
be mined as compared to uranium (by weight) provide the same power level.
In terms of inventory, however, the lithium requirement would be several
times that of the uranium. Thus, the lithium mining impact can be ex-
pected to compare to the uranium mining impact.
The potential impact of effluents is summarized in Table W-ll for a
1000 MWc power station employing an operating efficiency of 40 percent.
Many of the results in Table W-ll are speculative and must remain so in
the absence of a designed and operating station.
Development Schedule and Costs for Fusion Power
An estimate of 4.24 billion dollars to bring fusion power to the point
of commercial viability has been made by the R&D Goals Task Force of
the Electric Research Council.(W-49) xi,is figure is broken down by
milestone (or function) in Table W-12 and by year in Table W-13. Also
562
-------
included in Table W-L3 are the Atomic Energy Commission'estimates for
on expanded program and an all-out program are compared with the Electric
Research Council figures through the year 1980.
TABLE W-ll. D-Li ENERGY CYCLE EFFLUENTS 1000 MUe, 40 PERCENT
EFFICIENCY
Effluent . Amount Released Assumptions
Relative
Impact
Compared
' to LWR
Tritium
Heated Effluent
Fusion Ash
Waste Water
Lithium Tailings
Radioactive Waste
.41 Rem/day
5.9xl09 Btu/hr
.63 kg/day
40,000 gpm
35% of uranium
1-5% of LWR
.0005% leak rate; 5
kg inventory
40% thermal efficiency
Total release
Makeup only
Ultimate use
Stainless structure
Comparable
Comparable
Trivial
Trivial
Comparable
Small
TABLE W-12. NUCLEAR FUSION COSTS (BY MILESTONE)
Expended Through FY 1971
Proposed
Demonstration of Feasibility
Physics, Engineering, and Materials
Direct Conversion Prototype
Thermal Prototypes (2)
Demonstration Plants^3'
Total, future
Millions of
1971 Dollars
400
(a) Incremental cost for small plants above equivalent fission capacity
in large plants. If very large (2,000 to 5,000 MW) demonstration
plants are necessary, this figure is too low.
Effectiveness and Economics of Pollution Control
i
At present there are no low cost systems for isolating and storing tri-
tium leaking from a reactor system. The tritium usually appears at a
very low concentration in air or water streams such that concentration
by known methods would be very costly. It is assumed herein that no
attempt is made to isolate tritium escaping from the system.
563
-------
TABLE W-13. NUCLEAR FUSION COSTS BY YEAR ''IN
MILLIONS OF 1971 DOLLARS
AEC Estimates
Year Utility Estimates Expanded Program All-Out Program
1973
1974
1975
1976
1977
1978
1979
1980
1981-1985
1986-1990
1991-1995
1996-2000
60
95
110
135
160
170
215
245
1000
1000
500
500
45
58
65
76
81
83
86
89
—
—
--
--
74
143
190
215
237
.-
__
--
• _
--
--
--
Escape of 2^e creates no environmental problems. It is assumed that
no waste treatment systems are necessary.
No treatment processes are assumed necessary for the wastewater from
deuterium production processes. Normally that water is of equal or
better purity than when it was obtained from its source. In some cases,
though, treatment may be necessary for removal of residual corrosion
inhibitors or process chemicals.
The waste heat from a fusion device must be dissipated either in a
water or air sink in the same manner as for current power plants. The
costs for constructing and operating the waste heat system may be lower
per MHc of capacity than for LWR because the fusion reactor could possi-
bly have a higher thermal efficiency and a higher power level.
There have been no attempts to extract in detail from the overall R&D
costs those associated with environmental quality control. Some paral-
lels might be drawn with fission power sources. In that area it is
recommended that -15 million per year be spent on environmental control
research. This is a few percent of the total budget for research.
There is much in common between fusion and fission so it might be ex-
pected that the additional needs would be lower—say 1 p'ercent of the
total R&D costs. This would mean that an additional 40 million dollars
would be required to meet environmental research needs over the next 20
to 30 years if the total estimated cost of Table W-12 is accepted. Apart
from these estimated research costs a continuing radioactive materials
management cost has been estimated to be 0.03 to 0.05 mill/kwhr.(w-5°)
564
-------
Breeder Reactors
Fission Gas-Cooled Fast Breeder Reactor
The gas-cooled fast breeder reactor,(w~5^» W-55, W-56, W-57) as pre_
sently visualized, will utilize metal-clad refractory fuel in a core
that is cooled by the forced circulation of pressurized gas. The con-
cept involves a wedding of Ll-lFBR fuels technology and gas-cooled thermal-
reactor (AGF and HTGR) component technology. The development of the
GCFBR lags behind that of the LMFBR by five to ten years with only a
relatively low level of current effort. It is doubtful that it will be
a commercially significant source of power until tlie'end of this cen-
tury. The development of large, high-temperature gas turbines would
increase the attractiveness of gas-cooled reactors generally and speed
the development of the GCFBR.
Description of Energy System. Figure W-6 shows a suggested power cycle
for the early 1000 MWe GCFBR1s. A conventional steam cycle is projected
in line with current gas-cooled power plant technology. Core-coolant
exit temperatures are limited by fuel-pin performance limitations which
are in turn directly influenced by the use of stainless steel cladding
on the fuel. The helium is pumped through the core at high flow rates
by means of helium circulators. The heated helium is used to produce
steam in a steam generator and is then recycled to the core. The steam
side of the system contains a conventional turbine for the generation
of electricity.
Potential Environmental Factors. The GCFBR can and will be designed
such that the reactor effluent is well within permissible release limits
to the atmosphere. Because of its relatively high efficiency (^38 per-
cent), thermal effluent will be significantly reduced as compared with
water reactors whose efficiency is only about 30 percent.
The use of helium coolant will result in production of tritium as a re-
sult of neutron reaction with 3He. However, this can be readily removed
by continuous scrubbing of the coolant gas to remove both tritium and
fission-product gases. Disposition of the tritium can be readily accom-
plished because of the small volumes involved. This is not true in
LWR's where the tritium is chemically indistinguishable from hydrogen
and one is confronted with the processing and storage of relatively
large amounts of tritium-contaminated water.
Fission-product contamination of the reactor system will be minimized
in the GCFBR by venting of the fuel to a collection system. Thus, only
minimal release to the coolant will occur in the event of a fuel failure,
Since helium is inert, leaching of fission products from the fuel by the
coolant will not occur as in water and liquid-metal systems. Release
in any event will bo restricted to volatiles. Since only a gas phase
will appear in the complete primary circuit, only a single recovery
system will be required.
565
-------
Tidal Power
Because of the 24-hour, 50-minute Liclal cycle, the availability of en-
ergy from tidal flow in large estuaries gradually shifts throughout the
day. Thus, when large slugs of energy become available .from tidal move-
ment at times of low demand on the system, pumped storage is required
to utilize the tidal output effectively. Hence, recent consideration
of tidal power has included pumping plants as well. (^~->l-) A pumped-
storage facility involves additional capital investment, already a seri-
ous limitation of proposed tidal power plants.
Only one major tidal power plant is in operation today—at the Ranco
River estuary on the coast of France near St. Halo. Rated at 240 MW,
with a 3,000-foot dan impounding 6.4 x 10" cubic feet of water using
two-way bulb turbines, the plant generates 6.24 x 10^ kwhr annually for
an availability of about 30 percent. Power generation costs are high
compared with modern steam plants, amounting to 2 to 3 times the bus-
bar costs of fuel-fired systems because of the high capital charges in-
volved in building a large dam, providing pumped-storage basins to supply
power between tides, and in constructing the turbine pumps.
Environmental Burden
Tidal power has little impact on the environment, mostly involving local
actions resulting from disturbing normal tidal flow patterns. Changes
in salinity, oxygen content, and water level may affect local fisheries,
but no major effect is foreseen on climate or on atmospheric conditions
in general.
R&D Requirements
Little R&D is required, the operation at Ranco River having provided a
"pilot plant" demonstrating both the cost and the feasibility of tidal
power plants. The Pr.sscnunquoddy situation lias been reviewed many .times,
the conclusions being that the cost of the required dam and the pene-
trating facilities cannot be justified. Dam-co'i-struction techniques are
not likely to change unless, some day, nuclear explosives might be util-
ized in some predictable manner. Likewise, bulb turbines as used at
Ranee River and in pumped-storage installations perform satisfactorily.
Because of the inherent low hydrostatic heads, some turbine development
may be desirable, 0''~52) but no appreciable power generating gains can
be expected through further research.
All of North America is estimated to have some 300,000 MW of tidal en-
ergy. (w~53) T|ie potential for power generation is therefore weak, and
coupled with the high capital cost, tidal power is not considered a
viable source.
For the above reasons, no funding effort appears to be needed.
566
-------
575 .
'Net Plant Output 1000 MWe
Plant Efficiency 38%
(All data are estimated for
purpose of this report only)
FIGURE W-6. SIMPLIFIED POWER-CYCLE DIAGRAM, 1000 MWe GCFBR
Because o'f the higher pressure on the helium side of the steam genera-
tor, there is a potential for leakage to and contamination of the steam
system. While this can be minimized by appropriate maintenance of the
steam generator and cleanup of the helium gas, waste treatment systems
will be required to clean up the steam circuit also in order to prevent
the -possibility of leakage to the atmosphere. However, the potential
would appear to be less than from any LWR.
Fission products not recovered on site will eventually be recovered
during reprocessing. Most fission products and tritium will require
long-term storage to avoid radioactive contamination of the atmosphere.
Fast reactors ara fueled with plutonium which is highly toxic if in-
haled or ingested. Shipment of the virgin fuel will require precautions
similar to that required for its shipment after irradiation.
The great advantage of fast breeder reactors, of course, is in their
negative fuel usage. The GCFBR is anticipated to exhibit a breeding
ratio of at least 1.5, meaning that for each unit of fuel consumed, 1.5
times as much is generated for a 50-percent gain. The fuel is 239pu
and smaller amounts of 241pu an(j tne fertile material from which addi-
tional fuel is bred is ^38ut The goal in fuel performance is to achieve
an electrical power output of at least 10° kwhr/kg of fuel and fertile
material before it must be reprocessed.
Energy Systems Development Costs. A wide range of development efforts
arc required to bring the GCFBR to the stage of commercial feasibility.
However, the most critical involve (1) core-cooling requirements in the
event of less of helium pumping power; (2) improved fuel-pin design, in-
cluding consideration of cladding material, fuel venting, and surface
heat transfer; and (3) design of the necessary pressure vessel.
567
-------
An estimate of required R&D costs and time prior to construction of a
commercial size GCFIJR LOGO f-F.Vo power plant and including construction
of a smaller ( 300 MWe) demonstration plant is given below.
R&D Cost Range $750,000,000
R&D Time Range 20 years.
Fission-Molten Salt Breeder Reactor
The Molten-Salt Breeder Renctor(w"58» W-59) (usr.R) is a thermal reactor
concept operating on the 232jj1_233u £uc^ CyCic uhich is capable of breed-
ing by continuous removal of fission product wastes and 233pa from the
fuel-containing salt. The Pa decays to 233[j which is then returned as
fuel Lo the reactor. Research and development already accomplished on
MSER materials and processes indicate that after the technology has been
extended in a few specific areas, a prototype MSBR could be successfully
constructed and operated.
Molten salts have been under study and development as reactor fuels and
as coolants for over 20 years. Their chemical, physics, and irradia-
tion properties are excellent. The Molten-Salt Reactor Experiment (MSRE)
contributed significantly Lo MSR technology during its 5 years of opera-
tion. 'Research in the processing of molten salt fuels showed that^33pa
and fission products could be separated from salts containing both uran-
ium and thorium by reductive extraction into liquid bismuth. Oak Ridge
National Laboratory (ORNL) has prepared a conceptual design for a 1000
MWe single-fluid molten-salt reactor power plant that indicates such a
plant is technically feasible and economically attractive.
The major remaining areas for development in the MSBR concept are:
1. The chemistry of noble metal fission product behavior
2. Alternate rare earth removal processes
3. Physical and chemical properties of the secondary coolant salt
4. Continuous methods for analytical process control
5. Engineering development of fuel processing equipment for contactor,
fluorinator, electrolyzer, and vacuum distillation
6. Improvement in materials such as radiation-damage resistant graphite,
container materials (Hastelloy N), and container material for simultane-
ous contact of molten Bi and salt at 500 to 700 C
7. Reactor system components such as pumps, heat exchangers, steam
generator, rods and drives, and maintenance procedures.
Description of the Energy Svstpm. The reference MSBR operates on the
_u cycle, with botli fissile and fertile materials incorporated i.n
568
-------
a single molten-salt mixture of the fluorides of lithium', beryllium,
thorium, and uranium. This salt, with the composition LiF-BeP2~ThF4-
UF4 (71.7-16.0-12.0-0.3 mole percent), has a liquidus temperature of
930 F (772 K), has good flow and heat transfer properties, and has a
very low vapor pressure in the operating temperature range. It is also
nonwetting and virtually noncorrosive to graphite and the Hastelloy N
container material.
The 22-foot diameter by 20-foot high reactor vessel contains graphite for
neutron moderation and reflection, with the moderating region divided in-
to zones of different fucl-to-graphito ratios. As the salt flows upward
through the passages in and between the bare graphite bars, fission
energy heaLs it from about 1050 F (839 K) to 1300 F (978 K). Graphite
control rods at the center of the core are moved to displace salt and
thus regulate the nuclear power nnd average temperature, but these rods
do not need to be fast scramming for safety purposes. Long-term reac-
tivity control is by adjustment of the fuel concentration.
The core neutron power density was chosen to give a moderator life of
about four years, based on the irradiation tolerance of currently avail-
able grades of graphite. The specific inventory of the plant, including
the processing system, is 1.47 kg of fissile' material per MWe, the
breeding ratio is 1.06 and the annual fissile yield is 3.3 percent.
The heat-power system has a net thermal efficiency of over 44 percent
which makes a reactor plant of about 2250 MWt ample for a gross electri-
cal output of 1000 lF.
-------
FLOW DIVIDER
^ 'F 360QP
101 10° Ib/hr
JL1U
(G«CSS)
I ' 1
CHEMICAL I
I PROCESSING I
I— 1
FIGURE W-7. SIMPLIFIED FLOW DIAGRAM OF MSBR SYSTEM, (1) Reactor,
(2) Primary heat exchanger, (3).Fuel-salt pump, (4) Coolant-salt pump,
(5) Steam generator, (6) Steam reheater, (7) Reheat steam preheater
(8) Steam turbine-generator, (9) Steam condenser, (10) Feedwater booster
pump, (11),Fuel-salt drain tank, (12) Bubble generator, (13) Gas separator
(14) Entrainment separator, (15) Holdup tank, (16) 47-hr Xe holdup charcoal
bed, (17) Long-delay charcoal bad, (18) Gas cleanup and compressor system
The estimated plant capital costs for a fully developed MSBR, although
differing in breakdown, are about the same as those for a light water
nuclear power station. Fuel-cycle costs are expected to be quite low
and relatively insensitive to the prices of fissile and fertile materi-
als. ...
Potential Environmental Factors. The nature of the MSBR system lends
itself -to the minimizing of the environmental impact of a nuclear power
system. Its high efficiency, for instance, reduces the waste heat that
needs to be dissipated to about 75 percent of the waste heat for a light
water reactor.
In normal operation, the fission gases and tritium are continuously re-
moved from the primary circuit in a form that lends itself readily to
collection and packaging. Thus, even though there may be 20 to 50 times
as much tritium produced as in an equivalent LWR, it is less likely to
be released.as water or water vapor to the environment. The nonvolatile
fission products are also continuously separated in a relatively small
volume and form that is readily packaged and stored. Should salts leak
570
-------
from the system, the tendency will be for them to solidify retaining
the fission products, rat lie r than to evaporate, and disperse the fission
products into the air as a p. LWR. Because of the continuous processing,
the buildup of long-lived fission products is maintained at a minimum.
Thus, a major source of heat in event of an accident is considerably
reduced. By the same token, the fuel inventory is maintained at the
minimum necessary to attain criticality, reducing the potential for an
uncontrolled criticality accident. The primary system operates at low
pressure, and the salt content, is quite inert chemically. Thus, the
primary system contains only sensible heat, as contrasted with the
latent heat of the pressurized water system, and there is no potential
for the metal-water reaction which one finds in the LWR.
i' «
All the above* factors make the MSBR system one whose environmental im-
pact is likely to be considerably less than that of the LWR.
Development Schedule and Cost. An estimate of the required cost and
time for the MSBR system development to be carried through the building
and operation of a demonstration plant (300 MWe) is given below:
R&D Cost Range * $1,000,000,000
R&D Time Range - years from 1972 20 years
Estimated funding effort and requirements to produce a demonstration
plant are:
(Millions of Dollars)
Expenditure Through the Year
Expenditure to (for each period) -
Date. 1972 1975 1980 1985 1990 Key'ond 1990
^$50 $50 $150 $200 $100 ?
The magnitude of energy that can be developed by the year 1990 is esti-
mated at approximately 5 GWe.
Liquid-Metal Fast Breeder Reactor
The Liquid-Metal Fast Breeder Reactor (LMFBR)(w~60• w~6l» W-62> will use
liquid sodium as the coolant and plutonium ('39pu an
-------
loop between the reactor coolant system and the steam, supply system.
Sodium serves as both the primary coolant and the heat transfer medium
in the intermediate loop. Sodium is attractive for both purposes be-
cause of its excellent heat transfer characteristics. An additional
attractive feature of sodium is its high boiling point (892 C at 1 atm),
so that pressurization of the primary coolant system to suppress boiling
is not required.
Reactor
r
f'uel-
• Sleam
FIGURE W-8.
Steam gcneotot
NUCLEAR STEAM-SUPPLY COMPONENTS IN
A LIQUID-METAL-COOLED BREEDER
REACTOR
Potential Environmental Factors. The LMFBR is anticipated to be oper-
able with a 40-percent efficiency. The increased efficiency relative
to a LWR means a decrease by one-third in thermal effluent for an LMFBR
plant of equivalent power. ..
Tritium production in an LMFBR is negligible being restricted to produc-
tion in the fuel by ternary fission and from possible contaminant ^Li in
the sodium coolant by reaction with neutrons. There is no reaction v;ith
sodium to produce tritium.
The LMFBR is potentially capable of zero radioactive effluent release
at the reactor plant site. The primary system will operate at a pres-
sure close to atmospheric with the secondary sodium system at a slightly
higher pressure, both sodium circuits being at a very much lower pressure
than the steam-water system. Thus, the possibility of contamination of
the latter system as a result of leakage from the primary circuit will
be minimal. Consideration is being given to the use of vented fuel pins
that would release fission gases directly to the coolant and thence to
the cover gas system. The recovery for disposition of the fission pro-
ducts from the cover gas and sodium coolant will be required and this
capability is available.
Fission products retained within the fuel will be recovered during re-
processing of the fuel. The fission product volume will be relatively
572
-------
small but will require long-term storage in a controlled area to per-
mit radioactive decay. The storage area will be determined by the ex-
clusion area required rather than the volume of the waste itself.
Because the plutonium fuel is highly toxic, the shipment of fuel to
the reactor plant will require the same safety precautions as are
needed for shipment of the irradiated fuel. Escape of fuel to the
atmosphere during shipment must be avoided.
The breeder, since it creates fuel, has a favorable impact on energy
resources. The LMFBR, depending upon the specific fuel type and
breeder design, will exhibit a breeding ratio of between 1.2 and 1.5,
the lower value probably being typical of early breeders. The ratio
means that for each unit of fuel consumed, 20 to 50 percent more fuel
is generated than is burned. The use of breeder reactors increases
the energy supply from natural uranium by two orders of magnitude.
The electrical energy production in breeder reactors will amount to
10^ kwhr/kg of combined fuel and fertile material before the fuel is
reprocessed. The gross electrical potential per kg of fuel and fertile
material is about 9 x 106 kwhr.
The breeder also has a favorable effect on energy use. Because plu-
tonium serves as the fuel and can be chemically recovered, the use of
gaseous diffusion plants which consume large amounts of energy is not
required, as in the case of uranium as fuel, which requires isotope
separation.
Development Schedule and Cost. The LMFBR has been the subject of de-
velopment since the mid-lS-'iO1 s, although the level of effort has fluc-
tuated considerably. Several experimental reactors, the EBR-I and
EBR-II, and a prototype power plant, the Enrico Fermi plant (220 MWt)
have been constructed and operated. Nevertheless, the LMFBR is still
unproven commercially and the next step will be construction of a 300
MWe commercial power plant with development of the large size components
required for a commercial plant involving a major effort.
The demonstration plant is projected for operation by 1982. The 1000
MWe plant will probably not be operational much before 1990. Thus, the
LMFBR will not be commercially significant in the United States until
the end of this century.
An estimate of the required cost and time for the LMFBR to reach the
point of commercial utilization, which covers principally the period
up to operation of a demonstration plant, is given as:
R&D Cost Range $1,000,000,000
R&D Time Range 15 years.
573
-------
MaEnctohydrodynamics
Magnetohydrodynamics (MHD) is an energy conversion process using the
advanced technology of plasma flow that has potential application to
conventional systems for generating power. When an electrically
conducting gas (plasma) is forced through a duct at high velocity in
the presence of a transverse magnetic field, the electromotive forces
decelerating the gas flow induce an electrical current flow that can
be delivered to external load through electrodes appropriately placed
along the duct.
Adequate electrical conductivity in the plasma for practical power
generation requires both high gas temperature (around 4000 F or 2500 K)
and gas flow seeding with readily ionizable materials such as potassium
or cesium. In a combustion gas system, an advanced combustion process
is required to deliver the hot compressed gas with the added seed to
the HUD nozzle where it is expanded into the MHD duct past the magnetic
field and the electrodes. The work extraction lowers the plasma tem-
perature to the regime of inadequate electrical conductivity at about
3100 F (2000 K) so cither a very large regenerative heat exchange with
the combustion air or delivery of thermal energy to another power ex-
traction cycle, or both, is indicated. Some regenerative heating is
necessary to achieve the ultrahigh combustion temperature without oxy-
gen enrichment but practical base lond systems would feed the MHD ex-
haust into a conventional steam plant which generates the majority of
the electrical power.
Thermodynamically, this high-temperature extraction of work from the
combustion products improves efficiency, reducing both the fuel require-
ments for each kwhr of electrical energy (stretching our natural re-
sources) and the heat rejection for each kwhr of electrical energy
(reducing the thermal pollution loading). The cost of seed material
is such that the stack gases must be treated to recover it, inherently
imposing sophisticated gas cleaning elements in the system so that the
pollution demands are more readily accepted. The high flame tempera-
ture, however, imposes a uniquely severe NOX control burden.
Closed cycle MHD systems using either noble gases or two-phase fluids
also have been investigated. The Rankine cycle fluid systems have shown
themselves to be limited to specialized aerospace application. Brayton
cycle MHD systems have been proposed, in particular for gas-cooled re-
actor systems, but basic incompatibilities seem to virtually eliminate
such systems from any current application.
Open Cycle MHD Reserve Power Generators
The reserve power use of open channel MHD is uniquely important for two
reasons:
1. Its economic and technical operation is radically different from
574
-------
base load MUD systems.
2. It will probably be the first commercial application of MUD, pre-
senting an economically convincing case against a backdrop of disappoint-
ment with the technological progress in base load MHD.
Because the MHD process is inherently a low inertia process standby,
generation for short term power reserves can be shown to be economically
very attractive,(W-63) particularly for individual running times less
than 5 minutes and yearly total running times on the order of 50 hours
(200 days with 4 runs of 4 minutes each). The capital costs control
the economics of this system use so the exhaust would be rejected hot
and untreated and represents an anomally in emission considera.tion and
procedures. The fuel is clean and uses oxygen rather than air so the
major pollution concerns would be the seed (probably KSO^) and the hot
gas.
The desire to get practical operating experiences with any kind of MHD
system will bring significant pressure from the technological community
to implement this system.
Open Cycle MHD Base Load Systems
Worldwide interest seems to have focused on open cycle MHD generators
topping steam systems but conflicting reports of Russian experience
with a gas-fired pilot plant designed to produce 25 MV7 from MHD and 50
MW from the associated steam plant have strengthened a European mood
of pessimism.
Research and Development Needs
A significant amount of applied research and practical development lies
between current technology and successful utilization of MHD.
Coal Combustion. To utilize the large reserves of coal with at least 10
percent ash would require sophisticated combustion systems (probably
multistage) that can provide a clean, pressurized, ultra-high tempera-
ture product. Low energy coal gasification techniques, modified for low
hydrogen content because of the MHD electrical process, is an alternative.
Air preheat development probably should be tied to the combustion system.
Channel Materials. Fundamental experience with both insulator and elec-
trode materials in the high-temperature environment with associaced
electrical current flow and slag and seed contamination is crucial.
Improved predictability of MHD channel performance when scaled to prac-
tical sizes is only truly useful with engineering materials so materials
technology is the driving influence.
Seed Recovery and Gas Cleaning. A fortuitous match between seed frac-
tion and coal sulfur content is viewed by some as important. Potassium
carbonate seed seeks out the sulfur in the combustion products to
575
-------
become potassium sulfate, also an acceptable seed, so when the seed re-
covery process captures about 99 percent of the potassium to avoid an
expensive seed loss, it also has captured the sulfur. Reconversion of
the potassium sulfate to potassium carbonate, beneficiating the sulfur,
is considered straightforward.
Increases of NOX emissions to the level of 10,000 ppm are anticipated
because of the high combustion temperature requirements. Satisfactory
NOX control techniques are considered beyond current and near-future
technology.
Pilot-Plant Studies. Because of scaling problems, some authorities
view the Russian work plan favorably as "...a gigantic experimental
breadboard...(which) will give the Soviet Union an optimum experimental
program1.1. (W-64) Such evaluations are more easily rationalized than
justified. In this paper(W-&4) the author is highly critical of esti-
mates of new exploration for sources of nuclear ore but assumes an
assured fact the ability of the technological community to produce the
advancement's to make MUD practical. MUD development success is not an
assured fact. Eventually pilot-plant studies will have to be considered
in continued MUD research.
Other Variations. Nonsteady flow MUD channel systems may change some
of the critical boundary conditions. Explosion driven and other shock
wave systems have been investigated only far enough to illustrate tech-
nical possibility. At the moment these are only interesting side
issues.
Anticipated Funding. The following tabulation is based on estimates in-
cluding a pilot-plant pro«ram^''~6-O at an aggressive optimum level.
Through 1975 1980 1982
(Millions) 45 300 90
In the estimate, practical development would be completed in 1982 after
a gross expenditure of $435 million for a pilot-plant program returning
$20 million from the sale of power. A net cost of $282.5 million is
estimated(w"64) allowing for residual worth of the plant, presumably
as a production facility.
Environmental Burden. Optimistic assumptions^""^, W-65) are that the
bulk of the new installations of fossil fuel plants after 1985 could be
open cycle MHD/stcam plants assuming a slightly increasing role of fossil
fuel as an electrical energy source and the necessity to retire obsolete
plants.
The environmental emissions arc all gains except for NOX which could be
as high as 10,000 ppm in the exhaust. Of the 10 percent ash entering
with the fuel, at least 75 percent(W-63) wj11 have to be removed in the
combustion process before expansion through the MUD dust. Seed added
576
-------
at levels of I atom percent must bfi recovered at bcttcr^than 95 per-
cent efficicncy(N-66) to avoid excessive seed costs.
That process will also collect other particulates in the exhaust.
Subsequent seed treatment will renove the sulfur from the coal in the
exhaust (if it was not already removed in a modified combustion pro-
cess) .
Thermal pollution should gain by an overall thermal efficiency gain
from 40 percent to 50 percent. The heat rejection would be reduced
from 60 percent of the thermal energy input to 50 percent.
Closed Cycle MUD Systems
In these systems, noble gases such as helium are heated, seeded, ex-
panded through the MUD channel system, cooled by giving up heat to the
bottoming steam plant (just as in open cycle), cooled in a regenerative
heat exchanger, compressed, reheated by the regenerative heat exchanger,
and recycled to the primary heat exchanger. The working fluid is sealed
from outside contamination and loss.
The primary technological barrier to such a system is the primary heat
exchanger. Steady flow equilibrium ionization of the plasma requires
too high a gas well temperature for any known practical containment
materials. Consequently, phenomenological variations that induce ioni-
zation at much lower source gas temperatures have been proposed. Non-
equilibrium ionization procedures attempt to force local ionization and
rely on tho decay rimp to hold the electrical conductivity through the
MHD duct extraction section. General results to date indicate that,
even when the gas can be tricked into being adequately conductive, other
practical aspects such as density are almost totally mismatched with
practical needs for the rest of the system.
Some, other concepts with shock vaves(w~67> W-68) have been conceived
and have shown preliminary laboratory feasibility but have not been ex-
tended to even bench-scale systems. Research along these lines could
produce MHD/steam systems for application to high-temperature nuclear
reactors where the gases on both sides of the heat exchanger are rela-
tively noncorrosive. Extension of closed cycle operation to combustion
products seems quite unlikely.
Research Experiments. Significant bench-scale experiments at a rate of
$500,000/year through 1975 could establish the feasibility of such a
system. Reduction to practice, however, would' involve pilot-plant de-
velopment at expenditures probably less than for open cycle systems in
about the same time frnme--pilot-plant operation in the early 1980's.
Environmental Burden. The primary impact would be an improvement in the
heat rejection load of nuclear generation plants. If overall nuclear
cycle efficiency can be increased from 32 percent for a representative
light water reactor(w~65) to tnc neighborhood of 45 percent with an MHD
577
-------
finding new materials capable of high-temperature operation, and at im-
proving the thermoelectric efficiency and general utility of known
thermoelectric materials. Since 1962, the emphasis in thermoelectric-
power generation research has shifted from materials development to hard-
ware development. Improved electrical contacts, improved burners, and
stronger and more chemically stable thermocouples ha\c served to improve
reliability, reduce weight, and bring actual generator efficiencies
closer to theoretically possible values.
Thermoelectric generators have been built and operated satisfactorily
in a variety of situations. They have been operated from heat sources
fueled in many different ways, including butane, gasoline, kerosine,
propane, JP-/i, and fuel-oil burners; radioisotopes; and nuclear reactors.
A large majority of the thermoelectric generators that have been built
have been in the subki]owatt range. Recently the U.S. Atomic Energy
Commission has initiated an Isotope Kilowatt Program which has as its
objective the production of 1 to 10 kw of electrical power for terres-
trial and undersea applications.(W-71) One of the systems being evalu-
ated is a radioisotope thermionic generator (RTG). This program has not
yet progressed to the point where the "best system" has been identified.
Probably the next largest thermoelectric system presently under develop-
ment is the multihundred watt RTG being developed for the space pro-
gram and expected to "fly" in the mid-1970's.(W-72) Presently, the
generator efficiency for the KHW-RTG is expected to be less than a per-
cent. By incorporating a cascading concept, wherein two thermocouples
are in series thermally so that heat rejected by the cold junction of
the first-stage thermocouple is absorbed by the hot junction of the
second-stage thermocouple, somewhat higher efficiencies, perhaps to
nearly 9 percent, can be achieved.
Semiconductors materials used for thermoelectric applications often do
not require the extreme care in preparation that material for devices
such as transistors do. Thus, they may be somewhat less expensive.
Even so the materials cost for thermoelectric elements is still so high
that thermoelectric generators simply cannot compete economically uiLh
other conversion processes. Many experts feel that an order of magni-
tude improvement in figure of merit over those of the best present day
materials would make thermoelectric power generation worthy of con-
sideration for certain applications. There is presently no reason to
believe that a materials breakthrough of this magnitude is likely to
occur in the foreseeable future. Thus, thermoelectric-power genera-
tion is not suitable as an alternative method for large-scale power
generation.
Thermionic Power
A thermionic conwrsion system consists of a heat source, a number of
578
-------
augmented gas-cooled reactor, the cooling energy released per unit of
electrical energy produced is almost halved.
The effectiveness of MHD systems for meeting possible future demands
for reduction of stack particulates and,sulfur oxides should be con-
sidered high. The cost is inherent and buried within MHD development
costs so the best cost to use would be that of MUD development. Oxide
of nitrogen controls may be relatively ineffective. Since no practical
effective technique has yet been demonstrated, it is difficult to anti-
cipate tiie research costs. As an estimate, about 5 percent of the total
pilot-plant program discussed earlier might be appropriate--$20 million
between now and 1982. '
Thermoelectric
A thermoelectric generator is a device in which a closed electrical cir-
cuit is made up by two dissimilar thermoelectric materials and a load.
Current flows around the circuit when a temperature difference exists
between the two ends of the thermoelectric materials. The efficiency
of energy, conversion depends upon the temperature difference (as in any
thermal "engine"), the device geometry, and a factor involving the
material properties alone. The material factors, called the "figures
of merit", Z, is defined as Z = a2 aK , where is the Seebeck coeffi-
cient, a is the electrical conductivity, and K is the thermal conduc-
tivity.
The quest for higher and higher efficiencies focuses on finding mater-
ials with higher values of Z. Since Z depends upon the temperature,
maximum efficiency for a given material occurs within narrow tempera-
ture ranges.
Prior to 1947, only certain metals were known to exhibit relatively high
Seebeck coefficients. Although the cost of these metals was low, the
efficiencies of electrical power generators using them were only 1 per-
cent at best. In 1947, an article which reviewed the state of thermo-
electric-power generation at that time^"0') showed that materials con-
taining bismuth and antimony, tellurium compounds, and lead compounds
could be used to achieve power-generation efficiencies of about 5 per-
cent. During this same period, the gas-controls industry was conduct-
ing research on thermoelectric generators which' could use the heat from
gas burners and pilot lights to generate the power required to operate
blower controls and automatic controls.(W~70)
The rapid growth in knowledge of semiconductor technology, such as:
control of resistivity, control of purity, methods of materials prepara-
tion, which occurred with the advent of the transistor, along with re-
quirements of the space program, led to heavy expenditures on research
in all phases of thermoelectric power generation. From 1058 to 1962,
the U.S. Navy Bureau of Ships sponsored many research programs aimed at
579
-------
thermionic diodes, power conditioning equipment, and ancillary tem-
perature control equipment. Major attractive features of thermionic.
conversion systems are the absence of moving parts (which suggests
potentially long service life), a very desirable power-to-weight ratio,
and a good match between the thermal requirements of the diodes and
the capabilities of fast nuclear reactors. These features have made
thermionic power a good candidate for unattended, remote sites, Most
developmental efforts have been directed toward the realization of
systems for such applications.
The most advanced thermionic power generating systems so far developed
have been assembled in the Soviet Union. They have operated thermionic
reactor systems (TOPAZ I for 1500 hours, and TOPAZ II for 6.,000 hours)
at power generating levels of 5 to 10 kwo.(w~73) At the present time
the only major U.S. thermionic program expects to operate a thermionic
reactor system at 50 to 300 kwo power levels in 1978.Cw~73)
Thermionic converters have as the basis of their operation the Edison
effect, that is, the evaporation of electrons from hot bodies. The
number of electrons which are able to escape by surmounting the poten-
tial barrier at the surface of the emitting body is an exponential
function of the emitter temperature. Thus, on the face of it, the amount
of current produced by the thermionic diode should increase rapidly as
the emitter temperature is raised. This behavior would obtain except
for the fact that the first electrons to enter the space surrounding
the emitter exert, as a result of their like electrical charges, re-
pulsive forces on additional electrons attempting to escape from the
emitter. Through this process a space-charge cloud of electrons is
built up in the space surrounding the emitter and the number of elec-
trons then able to escape becomes comparatively small. In order to pro-
vide the high current densities necessary for reasonable efficiencies,
some means of space-charge compensation must be provided.
It is possible to reduce the spacing between the emitting electrode and
the collecting electrode to a small enough value so that space charge
has very little effect upon diode performance. The spacings required,
however, are extremely small, less than 0.001 inch, and the mechanical
problems involved in such a scheme have led to abandonment of efforts
to produce practical, close-spaced coverters.
The alternative method of space-charge compensation that has been almost
universally adopted is the introduction of positive ions into the inter-
electrode space. The usual source of ions is cesium vapor. The ions
can either be produced by surface ionization when cesium atoms come in
contact with the hot emitter, or by volume ionization which occurs in
the interelectrode space as a result of collisions between energetic
electrons and cesium atoms. In practice it has been found that maxi-
mum diode efficiency is achieved when the ions are created by volume
ionization, that is, when the converter is operating in the so-called
arc mode.
580
-------
As with other energy conversion systems, the efficiency of thermionic
diodes increases as the emitter temperature is -increased. At the pre-
sent technology level there are few materials that can maintain mechani-
cal integrity and hermcticity during atmospheric exposure at tempera-
tures of 1500 C and above. Because of this, the major thermionic devel-
opmental programs have relied upon diode designs wherein the emitter—
i.e., the hottest member—is enclosed in an evacuated space essentially
free from oxygen. VJith such a design one of the obvious ways of pro-
viding the thermal energy to the emitter is to encase nuclear fuel
within the body of the emitter and operate the diode within the core of
a reactor. This concept represents the in-core thermionic power gener-
ator system. All of the continuing major developmental programs are
based upon this concept. ' '
Some attention has been given to out-of-core thermionic systems. A
major accomplishment of these efforts has been the conception and de-
velopment of the heat pipe. These devices have the ability to transport
thermal energy over distances up to several feet with very little ther-
mal loss and to concentrate the thermal flux received over a relatively
large area and discharge it into a much smaller area. Small-scale
fossil-fuel-fired thermionic systems have been developed, some of which
utilize heat pipes and others of which expose the outer shell of the
thermionic diode to the flame. Numerous materials problems remain to
be solved for these systems and at present maximum diode life has been
only a few hundred hours and even then the operating temperatures have
been restricted to values where the conversion efficiency of the diodes
is.only about 10 percent.
One great disadvantage of thermionic converters is that they are low-
voltage high-current devices with typical output voltages of 0.5 to 0.7
volt per cell. Thus, it is necessary to operate a great number of
diodes in series in order to develop normal power-line voltages. Pro-
visions must be made to bypass any cell that might fail in an open cir-
cuit mode and, because thermionic diodes produce direct current power,
a substantial amount of power conditioning equipment will be required
to produce power compatible with existing generating and transmitting
sys terns.
Because of plasma losses, high-temperature materials problems, and lead
losses brought about by the large currents produced in thermionic diodes,
it does not appear that the device efficiency of practical thermionic
diodes is likely to exceed 20 to 25 percent. This conclusion is in dis-
agreement with that reached in Reference W-75 which assumes that even-
tually it will be possible to produce a collector with a work function
of 1.0 eV. Experience has shown that evaporation products from the
emitter deposit on the collector and inevitably lead to higher work
functions after a short period of operation. Projected system effici-
ency of the U.S. system currently under development is of the order of
5 per cent. (W-74_)
The performance characteristics of thermionic diodes probably mean that
581
-------
they will llnd application as primary systems only when long, unattended
service life, high power- to-weight ratio, or silent operation are more
important than operating costs. On the other hand thermionic diodes
have what is perhaps the unique ability to accept thermal energy at
very high temperatures, up to 2000 C, and reject it at 600 C or above.
This ability would appear to make thermionic conversion highly attrac-
tive as a "topping system" for some other primary system, especially if
the heat source is a nuclear reactor.
The U.S. system presently under development is being supported by appro-
priation of a few million dollars annually. The present schedule calls
for operation of a comparatively low power (40 we) deve.lopmen.tal model
in 1978.(W-73, W-74) There has been a great deal of slippage in sche-
duling on this program in the past, and some slippage probably can be
anticipated,in the future in the absence of increased funding. Reali-
zation of the space-oriented thermionic reactor will have little direct
benefit toward development of a topping system for terrestrial applica-
tions. The technology presently exists for producing a thermionic
topping unit. Some of the discontinued space power developmental pro-
grams appear to have laid much of the groundwork for such a system.
Thermionic diodes are not complicated devices and are not difficult to
produce. Thus, they should not require a large capital outlay once a
suitable system has been developed.
It appears that a demonstration in-core reactor system suitable for use
as a topping unit could be developed by a program similar to the one
now in progress for the space power generator. More detailed analysis
of projected reactor characteristics will be necessary before a meaning-
ful prediction of developmental costs can be attempted. By analogy
to the space power program it seems likely that a small demonstration
thermionic reactor capable of driving a conventional generator might be
developed with an outlay of 20 million dollars over a period of 5
years. Out-of-core thermionic diodes, utilizing heat pipes, which
would be suitable for demonstrating the feasibility of an out-of~core
topping concept probably could be developed and evaluated for a small
fraction of this amount.
Since they would be functioning as a topping unit for other generating
systems, the thermionic diodes would not be expected to have any un-
desirable influence upon the environment. Since they would serve to
increase the overall efficiency of the complete installation, their use
should serve to reduce any undesirable aspects of the primary system.
References
W-l. Mathusa, P. P., and Axelrod, H. J., "Can Urban Power Systems Use
Fuel Cells", Electric Light and Power, E/G Edition, pp 57-59,
April, 1972.
582
-------
W-2. Lueckel, W. J., Eklund, L. G., and Law, S. II., "Fuel Cells for
Dispersed Power Generation", IEE Paper T-72-235-5. Presented at
IEEE Meeting, January 30-February 4, 1972, New York.
W-3. Szego, G. C., "The U.S. Energy Problem", Volumes I and II, ITC
Report C 645, InterTechnology Corp., Warrenton, Virginia, November
1971.
W-4. Hammond, Allen L., "Solar Energy: The Largest Resource", Science,
Volume 177, pp 1088-1090, September 22, 1972.
W-5. NASA, "Solar Power for Terrestrial Use, Twenty-Year Development
Plan", Revision Four, MSFC/PD-SA-0, June 8, 1972.
W-6. Lof, George O.G., et al, "World Distribution of Solar Radiation",
Solar Energy, Volume 10, No. 1, pp 27-37, 1966.
W-7. ASHRAE Handbook of Fundamentals, Chapter 22, p 390, 1972.
W-8. Tabor, H., "Use of Solar Energy for Production of Mechanical Power
and Electricity by Means of Piston Engines and Turbines", Solar
Energy Journal, Volume 6, No. 3, pp 89-93, 1962.
W-9. Air Conditioning, Heating & Refrigeration News, May 8 and 29,
1972.
W-10. Tybout, R. A., and Lof, G.O.G., "Solar House Heating", Natural
Resources, Volume 10, pp 263-326, April, 1970.
W-ll. Tabor, H., "Power for Remote Areas", International Science and
Technology, pp 52-59, May, -967.
W-12. Anderson, J. Hilbert, and Anderson, James H., Jr., "Power From
the Sun by Way of the Sea?", Power, pp 65-66, January, 1965,..and
pp 63-65, February, 1965.
W-13. Anderson, J. H., Jr., "Economic Power and Water From Solar Energy",
ASME Paper 72-KA/Sol-2, November, 1972.
W-14. Runkle, L., "An Evaluation of Technology Needed for Solar Power
for Terrestrial Use", Jet Propulsion Laboratory, SPART report
701-1481, June 23, 1972.
W-15. Farber, Erich A., and Prescott, Ford L., "A 1/4-Horsepower Closed
Cycle Solar Hot Air Engine", ASME paper 64-WA/Sol-5, December,
1964.
W-16. Trayser, David A., and Eibling, James A., "A 50-Watt Portable
Generator Employing a Solar-Powered Stirling Engine", Solar
Energy Journal, Volume 11, Nos. 3 & 4, 1967.
583
-------
W-17. Bealc, W., ct al, "Free Cylinder Stirling Engines for Solar-
Powered Water Pump", ASME Paper 71-WA/Sol-ll, 1971.
W-18. Daniels, F., "Power Production with Assemblies of Small Solar
Engines", ASME Paper 71-WA/Sol-5, 1971.
•
W-19. Glaser, Peter E., "Power from the Sun", Mechanical Engineering,
Volume 91, pp 20-24, March, 1969.
W-20. Walters, Samuel, "Power in the Year 2001, Part 3—Solar Power",
Mechanical Engineering, Volume 93, pp 33-36, November, 1971.
W-21. "Satellites to Relay Solar Energy for Earth Needs", .Product
Engineering, pp 13-14, August 25, 1969.
W-22. Rex, R. W., Geothermal Energy—the Neglected Energy Option,
Bull. Atomic Scientist, pp 52-56, October, 1971.
W-23. Geothermal Energy, A Special Report by Walter J. Hickel, pub-
lished by the University of Alaska, 1972.
W-24. Brown, D. W., Smith, H. C., and Potter, R. M., "A New Method
for Extracting Energy from 'Dry1 Geothermal Reservoirs", LA-DC-
72-1157, Los Alamos Scientific Laboratory, Los Alamos, New
Mexico, p 23, 1972.
W-25. A Feasibility Study of a Plowshare Geothermal Power Plant,
Battelle Northwest Laboratories, Richland, Washington, April,
1971.
W-26. Bowen, R. G., "Electricity fron Geothermal, Nuclear, Coal
Sources", The Ore Bin, Volume 33, No. 11. Publication of Oregon
Department of Geology and Mineral Industries, 1971.
W-27. Hess, Hamilton, "Environmental Priorities, Human Needs and Geo-
thermal Power", in Compendium of First Day Papers presented at
the First Conference of the Geothermal Resources Council,
Geothermal Resources Council, Davis, California, p 77, 1972.
W-28. Brace, W. F., Orange, A. S., and Madden, T. R., J. Geoph. Res.
Volume 70, p 5669, 1965. '
W-29. "Geothermal Wastes and Water Resources of the Salton Sea Area",
California Department of Water Resources, Bull. No. 143-7,
February, 1970.
W-30. Barton, David B., "The Geysers Power Plant—A Dry Steam Geothermal
Facility", First Conference of the Geothermal Resources Council,
Geothermal'Resources Council, Davis, California, p 77, February,
1972.
584
-------
W-31. Bruce, A. W., "Engineering Aspects of a Geotherraal Power Plant",
U. N. Symposium on Geothernial Resources; Pida, Italy, September,
1970.
W-32. Salinos, I. B., "Projects de la Planta Geothermoelectrica Cerro
Pricto", Reunion Nacional de Ingenieria Quimica Aplicada a la
Generacion le Energia Electrica.
W-33. Assessment of Geothermal Energy Resources, Dallas L. Peck,
Department of the Interior, September 25, 1972.
W-34. Joint Committee on Atomic Energy Hearing on Controlled Thermo-
nuclear Research, November 10-11, 1971.
W-35. L. A. Booth, "Central Station Power Generation by Laser-Driven
Fusion", Los Alamos informal report LA4C58-M, Volume 1, February,
1972.
W-36. "The Limits to Growth" by D. H. Meadows, D. L. Meadows, Jorgen
Randcrs, and W. W. Eehrens III, Universe Books, N.Y., 1972.
W-37. W. C. Gough and B. J. Eastlund, "The Prospects of Fusion Power",
Scientific American, February, 1971.
W-38. J. Rand McNally, Jr., Prospects for Alternate Fusion Fuel Cycles
at Ultra-High Temperatures, Oak Ridge National Laboratory, ORNL-
TM-3783, April, 1972.
W-39. II. Postma, "Engineering and Environmental Aspects of Fusion Power
Reactors", Nuclear News, April, 1971.
W-40. D. J. Rose, "On the Feasibility of Power by Nuclear Fusion",
ORNL-TM-2204, 1968.
W-41. Fraas, A. P., "The BLASCON—An Exploding Pellet Fusion Reactor",
USAEC Report ORNL-TM-3231, Oak Ridge National Laboratory, July,
1971.
W-42. Watson, J. S., An Evaluation of Methods for Recovering Tritium
From the Blankets or Coolant Systems of Fusion Reactors, Oak
Ridge National Laboratory, ORKL-TM-39S4, July, 1972.
W-43. Bishop, A. S., "Recent World Developments in Controlled Fusion",
Nuclear Fusion, Volume 10, 1970.
W-44. Fusion for Power, Public Service Electric and Gas Company, 1970.
W-45. Searby, P. J., and Brookes, L. G., Nuclear Fusion Reactor Con-
ference (Proceeding Conf. Culham 1969) BNES, 20, 1970.
585
-------
W-46. Werner, R. W., et al, "Engineering and Economic Aspects of
Mirror Machine Reactors with Direct Conversion", IAEA-CN-28/K-2,
IAEA Conf. on Plasma Physics and Controlled Thermonuclear Fusion
Research, 1971.
W-47. Steiner, D., A Review of the ORNL Fusion Feasibility Studies, Oak
Ridge National Laboratory, ORNL-Til-3222, December, 1970.
W-48. Benedict and Pigford, Nuclear Chemical Engineering, McGraw-Hill
Book Company, Inc., 1960.
W-49. Electric Utility Industry Research and Development Goals Through
the Year 2000, Report of the R&U Goals Task Force to the Electric
Research Council, ERC Pub. No. 1-71, June, 1971.
W-50. Steiner, D., "Emergency Cooling and Radioactive Waste-Disposal
Requirements for Fusion Reactors", IAEA-CN-28/K-11.
W-51. Gray, T. J., and Gashus, 0. K., "Tidal Power", Plenum Press,
N.Y., p 630, 1972.
W-52. U..S. Energy, A Summary Review, Department of Interior, January,
- 1972.
W-53. The U.S. Energy Problem, Volume 1, Summary, National Science
Foundation, November, 1971.
W-54. Melese d'Hospital, G. B., "Factors Affecting the Design of Gas-
Cooled Fast Breeder Reactors", Proc. of the National Topical
Meeting on Fast Reactor Systems, Material and Components, CONF-
680419, April 2-4, 1968.
W-55. Dee, J. B., and Melese d'Hospital, G. B., "Gas-Cooled Fast
Breeder Reactor Designs", Mech. Eng., Volume 28, February, 1942.
W-56. Thomas, W. N., and Simon, R. II., "The 300 MWe Gas-Cooled Fast
Breeder Reactor Demonstration Plant", Volume 33, Proc. of
American Power Conf., 1971.
W-57. Fortescue, P., "Gas-Cooled Fast Breeder Reactor Development",
American Power Conf., Chicago, Illinois, GA-9289, April 22-24-
1969.
W-58. Robertson, R. C., et al, "Conceptual Design Study of a Single-
Fluid Molten-Salt Breeder Reactor, ORNL-4541", June, 1971.
W-59. "Nuclear Applied Technology, Volume 8, February, 1970 (entire
issue)
W-60. "Liquid Metal Fast Breeder Reactor Program Plan", WASH-1108,
LMFBR Program Office, Argonne National Laboratory.
586
-------
W-61. "In Pursuit of the LMFBR", Nuclear News, March, 1970.
W-62 . Proceedings of the Conference on the Constructive Uses of Atomic
Energy, ANS, 1969.
W-63. Bunde, R. , Muntenbruch, H., and Helm, S.-, "The Combustion MUD
Generator as a Reserve Plant in Electricity Supply Systems",
12th Symposium, Engineering Aspects of Magnetohydrodynamics,
Argonnc National Laboratories, March 27-29, 1972.
W-64. Dicks, J. B., "MHD Central Power: A Status Report, Mechanical
Engineering, May, 1972.
i1 -
W-65. Schurf, Sanett, "Energy Research Needs", October, 1971.
W-66. Heywood and Womack, "Open Cycle MHD Power Generation", Pergamon
Press, Oxford, 1969.
W-67. Stingelin, V., "The Non-Steady Flow in a Magnetohydrodynamics
Shock-Wave Generator of Finite Length", Zeitschrift fur
Angewandte Mathematik and Physik, Volume 21, January, 1970.
W-68. Jimevin, et al, "MHD Energy Conversion Using Detonation Condi-
tions", 12th Symposium, Engineering Aspects of Magnetohydro-
dynamics, Argonnc National Laboratories, March 27-29, 1972.
W-69. Telkes, M., "The Efficiency of Thermoelectric Generators",
J. Appl. Phys., Volume 18, pp 1116-1127, 1947.
W-70. Fritts, R., "The Development of Thermoelectric Power Generators",
Proc. IEEE, Volume 51, pp 713-721, 1967.
W-71. Fraas, A. P., and Samuels, G., "Isotope Kilowatt Program
Quarterly Progress Report for Period Ending September 30, 1971.
Oak Ridge National Laboratory Report, November, 1971.
W-72. Hembcr, R. J., Kelley, C. E., and Haley, V. F., "Multi-Hundred
Watt Converter Design Considerations", Proceedings, Intersociety
Energy Conversion Engineering Conference, Las Vegas, Nevada,
September 21-25, 1970, pp 15-1 to 15-7.
W-73. Beard, D. S., and Lynch, J. J., "Thermionic Reactor Program, an
Overview", Conference Proceedings, Seventh Intersociety Energy
Conversion Engineering Conference, San Diego, California, pp
1036-1040, September 25-29, 1972.
W-74. Beard, D. S., "Thermionic Reactor Technology—An Overview", Con-
ference Proceedings 1971 Intersociety Energy Conversion Engineer-
ing Conference, Boston, Massachusetts, August 3-5, 1972, pp 933-
938.
587
-------
W-75. Szcgo, G. C., The U.S. Energy Problem", Volume II, Appendix U,
p U-8.
588
-------
APPENDIX X
MISCELLANEOUS ENERGY SYSTEMS
•
Table of Contents
Pace
Summary 590
Hydrogen Energy 592
Space Heating » . 599
Energy Storage Systems 615
Waste Heat Recovery '.'.... ?. 619
References . • 622
List of Tables
X-l. Energy Consumption for Space Heating in U.S. by
Fuel and Sector 601
X-2. Emissions from Residential and Commercial Space
.Heating and Industrial Steam Generation 601
X-3. . Emissions from Residential and Commercial Space
Heating and Industrial Steam Generation 602
X-4. Inventory of Heating Equipment and Fuels for
Residential Space Heating in the United States. . . . 603
X-5. Efficiencies and Emission Factors Used in Residential
and Commercial Analysis 604
X-6. Residential Case 1 606
X-7. Residential Case II 607
X-8. Residential Case III 608
X-9. Commercial Case I 610
X-10. Commercial Case II 611
X-ll. Emission Factors and Efficiencies Assumed for
Industrial Space Heating 613
X-12. Commercial-Industrial Case 614
List of Figures
X-l. Energy Transmission Costs 594
X-2. Relative Costs of Energy by System 594
589
-------
APPENDIX X
MISCELLANEOUS ENERGY SYSTEMS
Summary
Hydrogen energy (and a fuel cell total energy system utilizing hydro-
gen), space heating and insulation, energy storage, and waste heat
recovery were" examined for their influence on the environment. Gen-
erally, these systems have a favorable environmental burden: the
combustion of hydrogen produces little or no burden; the use of in-
sulation diminishes space-heating fuel emissions and conserves energy
resources; energy storage, particularly as compressed gaseous fuel or
as compressed air for turbine power, decreases the environmental bur-
den; and waste heat recovery, where it is economically practical,
diminishes the thermal pollution of streams and air.
The systems are qualitatively ranked as follows:
e Hydrogen energy
9 Space heating and insulation
e Energy storage
« Waste heat recovery.
Hydrogen is a very versatile fuel which is capable of providing large
quantities of electrical and other forms of energy including synthetic
fuels. Until natural gas supplies or comparative costs make hydrogen
economically, competitive, the incentive to move swiftly toward a
"hydrogen economy" is not present, and, therefore, it is unlikely that
significant energy will be developed from this source through 1990.
The assault on the environment caused by producing hydrogen by coal
gasification and hydrogen utilization to produce steam-electric power
is considered to be less than conventional coal-steam-electric plants.
Nuclear power-water electrolysis-produced hydrogen will have little
more environmental burden than the LW nuclear electric plant itself
except for the inefficiencies of electrolysis and reconversion of the
hydrogen to electricity. An important consideration in utilization
of hydrogen is that it will not contribute undesirable emissions at
the point of utilization either as fuel for fuel-cells or for steam
generation when electrolytically produced hydrogen and oxygen are used
as the energy source.
Space heatinR consumes about 20 percent of the nation's energy. En-
vironmental burden from air pollution emission can be effected by
590
-------
fuels, equipment design, equipment adjustments, and thermal insulation
of the structures.
The analyses presented in this appendix for residential, commercial,
and industrial space heating are based on simplified cases using aver-
age emission factors for different fuel-types in general classes of
equipment. An important consideration that is masked by the use of
averages is the wide difference in emission performance between differ-
ent heating units within a class; in view of this factor, continued R&D
effort is needed to establish criteria for the design, operation, and
maintenance of combustion equipment for minimum emissions.
, j
Improved thermal insulation is one of the most effective, simplest,
economical, and immediate control measures for air pollution emissions
from space heating—and an approach that can be implemented by indi-
vidual home owners.
Hydro-pumped energy storage has proved to be the only practical system
thus far deve'loped to store large quantities of energy recovered from
other systems, but its undesirable utilization of land as reservoirs
is a decided deterrent to its widespread use.
The electrochemical storage of off-peak energy by means of water
electrolysis-fuel cell combinations in which the hydrogen and oxygen
are stored for later use, offer some attractive possibilities. Unlike
hydro-pumped storage, electrochemical storage is not seriously site
restrictive. When used in conjunction with nuclear plants,, electro-
chemical storage of energy would tend to decrease the environmental
burden as compared with pumped storage of fossil fueled plants.
Like natural gas, hydrogen may be stored as compressed gas or by lique-
faction. Though this may be accomplished without serious aesthetic
insult to the environment, the matter of leakage of hydrogen from un-
derground storage and gaseous emissions associated with the combustion
process associated with the compressor prime movers may contribute to
the environmental burden.
Compressed air storage from gas turbine power generating equipment dur-
ing off-peak loads for reuse during peak loads appears to be quite
attractive. The gas turbine will produce only one-third of the com-
bustion products as environmental burden since it is unnecessary to
provide power to the compressor during the period when the compressed
air storage is used. This system has not as yet been utilized exten-
sively, however.
Waste heat is generally regarded as the heat rejected in power cycles,
especially those associated with the generation of electricity. Waste
heat recovery and its utilization to produce useful products, and
thereby unburden the environment, hold very marginal promise economi-
cally. Financial incentives exist in the areas of climate control
591
-------
(particularly in community total energy systems), agriculture, and
aquaculturc. As higher priority is placed on the conservation of
energy resources, a further enhancement of the benefits from waste
heat recovery are to be expected.
Hydrogen Energy
There is little question but what fossil and nuclear-fission fuels
will be the backbone of our energy sources in the United States for
the remainder of this century. Controlled fusion'is touted; as being
the Utopian energy conversion system of the future but its many and
difficult problems do place it quite into the future. As an inter-
mediate fuel, hydrogen has much to offer:
e It can be produced in huge quantities
relatively economically from various
Ct-l \.'J Y-ll
sources'- L> » '
e It may be transported more economically
than electricity(X~4» X"5^
e It is a low environmental pollution energy
resource^"6'
e In contrast to electric energy, it is
readily storable(x"6)
o It may be put to a variety of uses either
as a fuel for producing electricity or as
a chemical base for a spectrum of synthetic
chemical products X~8'.
Hydrogen, like deuterium and tritium for controlled fusion, is a Uto-
pian fuel, but the significant difference is that the technology for
developing the "hydrogen economy" is well in hand.
Hydrogen as a fuel may be produced by gasification of coal, by elec-
trolysis of water, and from methane and some solid wastes. It can be
transported in underground pipelines much as our natural gas is today.
For distances over 150 miles, hydrogen may be transported less expen-
sively than electricity. The combustion of hydrogen emits no unburned
fragments which are undesirable, although, when air is the oxidizcr,
NOX is formed as with any conventional fuel. Aside from being used
as a fuel, hydrogen can be the basic ingredient of many synthetic
chemicals such as methane, metHanoi, ammonia, and ethylene.
The technology for bringing about the hydrogen economy exists. How-
ever, its cost in terms of equivalent energy is higher than natural
gas today but it could well be competitive in the near future.
592
-------
Hydrogen Production
The science of producing hydrogen from the fossil fuels is as old as
the significant demands for hydrogen which began at the turn of the
century. By 1968, the United States was generating more than 2 tril-
lion cubic feet of hydrogen annually, with a growth rate of about 18
percent per year/X~9) jjost was produced from natural gas, petroleum
fractions, and off-gases from refineries. Although coke was used
widely two decades ago for generating hydrogen by the water-gas proc-
ess, little coke is gasified now. A strong trend is evident today to
return to coal as the raw material for hydrogen generation as an inter-
mediate in producing substitute natural gas. Several gasific.ation
schemes are now being investigated intensively, with a number in or
approaching the pilot-plant stage.
The average price of hydrogen in 1968 was $0.25 per thousand cubic
feet, with the selling price in 1970 for 95 percent hydrogen ranging
from $0.20 to $0.60 per thousand cubic feet. The projected costs by
1990 will be'between 22 and 30 cents per 1000 cubic feet.(X~^ Plant
size is important, the cost decreasing rapidly up to capacities in the
range of 20 million cubic feet per day. For lowest costs, plant output
probably should lie between 50 and 250 million cubic feet daily. The
production of hydrogen by electrolysis today costs about four times
that from steam-reformed methane.' "' With the developments going on
at the present time, it is expected that costs for producing hydrogen
by electrolysis can be substantially reduced to the equivalent of 20
kwhr per pound of hydrogen with a capital outlay (for the electrolyzer)
of $50 per pound of hydrogen per day.™"*' Without doubt, the large
quantities of hydrogen required tomorrow will come from fossil fuels.
Electrolytically produced hydrogen from nuclear power may be a potential
source in the future.
The efficiency with which coal can be converted into hydrogen depends
greatly on the gasification system. Essentially all the older schemes
are based on coke. Roughly 85 percent of the heat in the original coal
to the coke oven is recovered as coke or useful by-products, but con-
version of the coke to hydrogen will have an overall thermal efficiency
ranging from about 50 percent to 80 percent. Hence, the overall effi-
ciency from original coal to hydrogen could be as low as 30 percent.
Such systems would be unattractive compared with present central-
station power plants with their 40 percent overall efficiency from coal
to electricity. Fortunately, gasification schemes are now being devel-
oped, such as the fluidized-bcd gasificr, that have the potential for
overall conversion efficiencies from coal to hydrogen of 75 percent
with additional recovery of process heat as useful steam.
Hydrogen Transmission and Distribution
Analyses indicate^~^> *~5) that hydrogen can be transported in pipe-
lines for about one-third the cost of electricity and slightly higher
593
-------
than natural gas. The break-even point is for distances of 150 miles;
above this distance, hydrogen has a distinct cost advantage as shown in
Figure X-l. As the hydrogen pipeline will be underground, aesthetic
problems associated with the electrical transmission towers and lines
will be eliminated entirely. Distribution costs will be 4-1/2 times
less than for electricity and slightly higher than for natural gas.
The relative costs for production, transmission, and distribution for
several energy systems are presented in Figure X-2. It will be noted
that the coal gasification-to-hydrogen system offers the best overall
cost attractions for energy produced and delivered to the utilization
point. The costs for underground electrical transmission are about 90
percent greater than shown in Figure X-2.
Hyd
• 70
^ GO
m
l4«
S>to
n
£>b<0
•£»-
0 >-
•TjSao
** "
w£20
£ °
i§ 10
0
Sower: In
rogen pipeline: cheaper transmission at long distances
— .-•—
./
^f9
Ky'dcog1
J^
^
.•*
•
n tranw^
/&
&£[
.'"''"
/
ion ./
____ . ^, T"**',^^*
o- ^
.••- Vff>
&>
' ^•'•'
<:';-:;.
•;'ii*t^-
* ^^.:?«
. i ••
1^
• v -~.~^-
S^
• •
' ^'•'-:
•£~y ;.;.';.•'.'••
>^^
•
•
iO 100 ISO 2CO 250 300 350
Distance from power station, miles
llitulc or Cji Technology.
FIGURE X-l. ENERGY TRANSMISSION COSTS
Hydrogen Energy Storage
Hydrogen, like natural gas, may be stored either as a liquid in tanks
or as a gas in geologically appropriate spent natural gas wells. By
way of comparison, the largest hydro-pumped storage system covers
several acres and produces 15,000,000 kwhr of electrical energy. For
a 50 percent conversion efficiency, a 90-foot spherical tank will con-
tain the equivalent energy of liquid hydrogen.
Because of the variability of wind and tidal power, electricity pro-
duced from such sources may be converted into hydrogen and stored for
later conversion electricity. The storage of hydrogen is presented in
more detail in the section on Energy Storage in this Appendix.
594
-------
A mm
1 ••
0 J.
Nuclear
Electrie(e)
Coal/Steam
Electric
Electrolytic
Hydrogen
KEY
— iDistribution
ESS — iTransmisiion
C23 — iProduction
FIGURE X-2. RELATIVE COSTS OF ENERGY BY SYSTEM
-------
Environmental Burden (at Coal Gasifer Site)
The gasification plants, as long as it is consistent with water supply
needs,* ' should be located as near as possible to the coal mine
since it will be cheaper to move hydrogen than coal. Thus, any emis-
sion will be far from the urban areas in which energy is needed.
Secondly, gasification plants inherently will emit less pollutants than
power plants for at least three reasons: (1) sulfur in the coal will
be converted to hydrogen sulfide which is easily removed from hydrogen;
(2) no large-scale combustion systems are involved, so the NOX produc-
tion will be somewhat lower for a gasification plant; and (3) since
there is no large volume of flue gas carrying off fly ash, "there will
be no output of particulate matter from the gasifier. Overall, there-
fore, a gasification plant should produce much less environmental burden
than a coal-steam power plant. The gasification environmental burdens
are discussed in the fossil-fuel gasification section of this report.
Nonetheless, the water consumption for the gasifier plant is high and
will have a regionally oriented impact on the environment.
If low-cost nuclear energy becomes available in large quantities with
the location of nuclear reactors in remote sites where thermal pollu-
tion can be tolerated or utilized, hydrogen may be produced by elec-
trolysis and transmitted through pipelines much more efficiently than
electricity transmission, thereby unburdening local community environ-
ments (where the hydrogen is utilized) of nuclear reactor pollutants.
Hydrogen Utilization
Hydrogen is ideally suited for direct conversion into electricity in
fuel cells. With a 53 percent efficiency of converting hydrogen to
electricity at high loads, the overall system efficiency from coal to
hydrogen to electricity would be about 40 percent. The waste heat from
the fuel cells may be utilized for comfort control of living spaces. A
suggested overall total energy system utilizing coal gasification to
hydrogen, its transmission, and its distribution to urban-area fuel-
cell substations is included as a supplement to this section.
Hydrogen could be utilized as a fuel in residences without venting in-
sofar as carbon monoxide or carbon dioxide are concerned. Hydrogen
could serve as an ideal industrial fuel as well as provide atmospheric
protection in the ore and metallurgical processing of metals. Hydrogen
is required in large quantities in converting coal into substitute
natural gas.
There are proposals for using hydrogen for high-speed aircraft engine
fuel. Hydrogen provides a good heat sink and extends the range of air-
craft beyond that associated with JP-type liquid fuels. The projected
costs of the two fuels break even in 1985^"^'. Of course, particu-
late and the gaseous emissions (with the exception of NOX), associated
596
-------
with conventionally fueled aircraft engines will be eliminated by the
use of hydrogen fuel. Liquid hydrogen for aircraft will pose special
problems in handling, but these have been solved satisfactorily in
rocket fueling systems.
There are also proposals to utilize hydrogen fuel for reciprocating
engines,(X-13) gas turbines, and for ground transportation vehicles.*
*A, A—LD/
Safety
One of the most important considerations in utilizing hydrogen is one
of safety.* _' Those who are concerned about safety need to be con-
vinced that hydrogen can be used without the disasterous explosions
that occur with the use of natural gas which is less explosive than
hydrogen. The technology exists for handling hydrogen safely and hydro-
gen rich methane gas has been used in the past in the United States
safely. It is also being used in Italy as a fuel containing 80 percent
hydrogen without difficulty.(x~^' Hydrogen dilution is suggested as a
means for providing safety. Hydrogen enriched natural gas may be a via-
ble means for the transition period from natural gas as hydrogen becomes
the primary fuel.
One scheme, which is discussed in the supplement to this section, uti-
lizes hydrogen in a fuel cell substation so that the hydrogen itself is
not utilized within the residences or buildings being supplied with the
electrical energy. If pure hydrogen is to be used with residences, ex-
plosion-proof switches, motors, and telephones may be necessary and
this could increase construction costs by an estimated 10 percent.
From the foregoing it may be seen that hydrogen is indeed a versatile
fuel and one which will produce a minimum impact on the environment at
its point,of utilization. It has the capability of supplying the large
demands for clean energy which will be needed in the future.
It will allow the use of low-grade coal which will not otherwise be
usable because of environmental considerations**"^' but techniques for
gasifying eastern coal still require development.
R&D Requirements
There are a variety of research needs. Chief among them are the pro-
duction methodologies for low-cost hydrogen,(^-10) hydrogen transmission
techniques, and the development of technical and safety standards for
transporting, distributing, and utilizing hydrogen. There have been
some 40 million dollars expended on coal gasification since 1964. Ex-
penditures of the order of some 200 million may be needed by 1985 with
an extra 100 million for the first production prototype plant.
597
-------
Supplement on Total Energy System
Hydrogen Fuel Coll Total Energy System For Urban Communities. One
application of fuel cells is to produce hydrogen in large quantities
from coal as a typical energy source; to distribute that hydrogen by
pipeline to 1-MW fuel-cell underground substations in urban areas in-
tended to serve 40 homes grouped around the substation; to convert the
hydrogen to electricity in conventional hydrogen-air fuel cells and
distribute low-voltage direct current to the surrounding nearby homes
by hollow copper conductors; and to pipe through those same conductors
hot water provided by thermal losses in the substation systems. In
this way, a large fraction of the chemical energy in the hydrogen can
be converted into useful work with no effect on the environment in the
urban area. Water is the sole reaction product from the fuel cells;
the little waste heat produced in the substation can be utilized in
the nearby homes. Any impact of the total system, then, will come in
the remote area where the hydrogen is produced.
A city of 40,000 homes could be supplied with all its energy require-
ments by a thousand such substations. This equivalent 1,000 MW power
system would consume approximately 4.8 x 10^ cubic feet of H2 per day
at constant full-power output. Production of H2 from coal by the most
promising method should recover 75 percent of the heating value of the
coal as H2« This H2, in turn, should be convertible to electricity
with a system efficiency of at least 53 percent, so that the overall
efficiency from coal to the energy used in the household should be 40
percent. Hence, the total impact on the environment will be comparable
to conventional power generation but with all the environmental prob-
lems occurring at the H£ plant and none in the urban area.
No data are in hand on the emission of pollutants from H2 plants based
on fluidized-bed gasifiers now under development of the kind envisioned
here. Since the gasification step will convert sulfur in coal into
I^S, almost completely quantitative removal of sulfur can be achieved
from the product H2. There will be no emission of NO directly in the
gasification step because no combustion takes place. The power plant
supplying the gasification plant with electricity will emit pollutants
like any conventional power plant. But since the amount of electricity
required to run the gasification plant is not known as yet, the amount
of pollutants emitted cannot be estimated. Roughly, if the electrical
input amounted to 10 percent of the energy output of the gasification
plant, the NOX output would be about 10 tons per 1,000 MW per day. No
appreciable quantity of particulates would be emitted, assuming that
the power plant is equipped with electrostatic precipitators.
Overall thermal losses from coal to energy delivered to each residence
would be about the same as for conventional power plants, since both
systems have an overall thermal efficiency of 40 percent. The heat
losses from the two systems, however, would be distributed differently
with the fuel-cell system delivering most of its waste heat to homes
598
-------
where the thermal energy can be recovered usefully, whereas the central-
station power plant discharges its waste heat into the environment.
The urban fuel-cell substation concept is at a very early stage of
technical development. Present-day hydrogen-oxygen fuel cells are
still much too expensive. Although operating satisfactorily in space
missions and in other exotic applications, fuel' cells need a large R&D
effort to lower electrode costs and cell-assembly methods to meet the
demands of commercial exploitation. In addition, the production of
low-cost H2 from coal and the development of pipelines specifically for
H£ transport will require additional R&D. Much of the basic research
has been done already. Mainly needed now are the developmental work
and systems studies that will result in a practical, low-cost, urban
power system free of any emission of pollutants in the urban area.
Full-scale installations should be feasible by 1985 at the latest.
Estimated Funding Effort and Requirements
($1000)
Expenditure Expenditure for Each 5-Year Period Through
to date, ' Beyond
1972 1975 1980 1985 1990 1990
$3,000 $5,000 $25,COO $25,000 ?
Fuel-cell substations will completely eliminate pollution in urban
areas if their energy source is hydrogen. Even waste heat will be
conserved in the idealized system. As far as the urban area is con-
cerned, pollution control will exceed all existing and anticipated
regulations. Pollution will occur at the remote site where the ^ is
generated, but the amount emitted is expected to be small compared
with emission from power plants of the same output. Roughly, pollu-
tion control of such a gasification plant probably will not cost more
than $10 per kilowatt of generating capability at the fuel-cell
substation.
Space Heating
This module describes the environmental burden of space heating appli-
cations as consumers of energy. The focus here is the air pollution
impact of fossil-fuel combustion for space heating at point of use.
The following considerations should be noted:
(a) Impacts of the energy supply and transportation
are not covered in this module.
599
-------
(b) Equivalent electrical energy requirements for
electrical heating are identified so that
electrical heating may be related to the im-
pact of the electrical energy system, including
that at the point of electrical generation and
up-stream in the fuel supply circuit.
(c) Energy for water heating is not included, nor
is cooling with direct fossil-fuel energy,
which is relatively insignificant in volume.
Classes of space heating. Space heating is considered here in the
following classes (although definitions of fuel user categories differ
for various statistical records).
o Residential - single-family dwellings, small
apartments, etc.
0 Small Commercial - stores, apartments, small
office buildings, etc.
e Large Commercial and Industrial - large office
buildings, institutions, factories, warehouses,
etc.
The burdens of these major classes of space heating are covered by
separate approaches in this analysis.
Perspective of Space Heating in Overall Energy
Consumption and Environmental Burden
Energy Consumption For Space Heating. Space heating is of major sig-
nificance in the ration's energy consumption and is estimated to
account for about 20 percent of U. S. energy consumption, or about
12,000 trillion Btu in 1968.^ ' Water heating accounts for another
4 percent. These applications are broken down by sector as follows (in
percent of U. S. consumption):
Space Heating, % Water Heating, %
Residential 11.0 2.9
Commercial 6.9 1.1
Industrial . 2.1 est . .3 est
Total 20.0 4.3
Table X-l shows a breakdown of energy consumption for space heating in
residential, commercial, and industrial applications by fuel or energy
source. Natural gas and oil share almost equally in dominating the
residential and commercial space heating market, but electrical heating
has grown in importance in recent years. Use of coal for residential
space heating has dropped sharply since World War II but is still sig-
nificant in some geographic areas.
600
-------
TABLE X-l. ENERGY CONSUMPTION FOP. SPACE HEATING
IN U. S. BY FUEL AND SECTOR, 1968x
Ash (Noncombustible
Particulate)
9
1
1
5
12
4
36
nil
<1
12
19
21
45
1
1
17
31
25
(a) Emissions by combustion lor energy conversion processes.
601
-------
The term "thermal pollution" is not really applicable in space heating
because all the heat energy ultimately is absorbed by the atmosphere;
however, heat lost in flue gases is not useful energy.
Table X-3 provides a breakdown by major-fuel classes for emissions on
a tons/year basis covering: (a) residential and commercial space heat-
ing, and (b) industrial steam generation.(x"1'^
TABLE X-3. EMISSIONS FROM RESIDENTIAL AND COMMERCIAL f .
SPACE HEATING AND INDUSTRIAL STEAM GENERATION* '
Emi
ssions, 10 W tons per
Commercial &
Residential
Space Heating
Pollutants
Coal
Oil Gas
Products of
Incomplete Combustion
NOX
Fuel
Combustible Particulate
CO
HC
Contaminants
SOX
Ash
0.
0.
0.
0.
0.
0.
10
43
09
07
85
12
0.
0.
0.
0.
1.
0.
11 0.07
03 <.01
04 n
64 0.38
2 n
08 n
vear
Industrial Steam
Generation
Coal
0
0
0
0
3
0
.57
.12
.06
.93
.71
.66
Oil
0.
0.
0.
0.
1.
0.
04
01
01
33
07
03
GPS
0.08
<.01
0.02
0.65
<.01
n
n, emission considered negligible.
Approaches to Emission Control for Space Heating
Emission controls applicable to residential and commercial space heat-
ing equipment are relatively limited, and not all options are univer-
sally available. Control approaches can be classified as follows:
e Fuel switching
-- shifting to a cleaner burning fuel
(coal to gas, or to electrical heat-
ing if only the point of use is considered)
• Replacement of outmoded and poor operating
equipment with modern units
6 Improve burner adjustment and maintenance
—tuning for efficiency and minimum emissions
as the simplest form of "combustion
modification".
o Reductions in energy requirements for fuel
conservation
-- improved thermal insulation
-- temperature control setback at night
or during unoccupied periods
602
-------
— heat recovery of internal loads
For large commercial and irdustrial boilers, additional emission con-
trols can be applicable in the form of various combustion modifications
or of stack cleanup processes (i.e. cyclones, prccipitators, or scrub-
bers). However, these controls are not practical or economical for the
major portion of the nation's space heating load.
Analysis of Emissions From Residential Heating
Table X-4 shows the fuels and types of residential heating equipment as
determined by the 1970 Census of Housing.(x~18) Nearly 70 percent of
U.S. homes have central systems or built-in systems. For purposes of
this analysis, a "typical" single-family dwelling with a control or
built-in system was assumed, and estimates of the relative air-pollu-
tant emissions impact were made for heating this unit with electricity,
gas, oil, and coal.
TABLE X-4. INVENTORY OF HEATING EQUIPMENT AND FUELS FOR
RESIDENTIAL SPACE HEATING IN THE UNITED STATES
(1970 Census of Housing)
Million Housing Units, Heating Equipment for Year Around
• Housing Units
13.82 Steam or Hot Water
28.77 Warm Air Furnace
3.52 Built in Electric Units •
5.88 Floor Wa]l or Pipeless Furnace
3.30 Room Heaters with Flue
3.95 Room Heaters without Flue
Fireplaces, Stoves, or Portable
Heaters
0.58 None
Million Housing Units, House Heating Fuels for Occupied
Housing Units
35.01 Utility Gas
16.47 Fuel Oil
1.82 Coal or Coke
0.79 Wood
4.88 Electricity
3.81 Bottled, Tank, or LP Gas
0.27 Other
0.40 None
603
-------
"Typical Residences"
A typical single-family residence is assumed here as having 1500 square
feet, built to FHA specification,^"19' and located in Washington, D.C.
(where the climate is similar to that at the center of the U.S. popu-
lation, near St. Louis, Missouri, in degree days).
Cases
Three cases were assumed as follows to reveal the effect of combustion
equipment tuning by frequent and competent servicing, plus the effect
of increasing thermal insulation.
Residential Combustion Thermal
Case Equipment Tuning Insulation
I Average Approx. FHA specs
II Well-tuned Approx. FHA specs
III Well-tuned Approx. FHA specs
and additional
insulation and
storm windows
With emission estimates for the various fuels for these 3 cases, the
impact of different mixes can be estimated on a national basis, in-
cluding fuel-use patterns, service, and degree of insulation.
Efficiencies and Emission Factors
Table X-5 shows the overall seasonal efficiencies and emission factors
used in the estimates. Seasonal efficiencies are based on the ASHRAE
Guide' ' plus Battelle's judgment. Emission factors are based on
EPA published factors^ ' and on Battelle field measurements of
emissions from residential heating units.(X-22)
Analysis of the Three Residential Cases
Table X-6, -7, and -8 provide a summary of the three residential cases.
Summary of the Residential Cases for Particulate
The effect of the three cases on particulate emissions, one of the sig-
nificant pollutants, can be seen as follows:
Particulate Emission,
Case Ib/year
Gas Oil
I Average Adjustment 0.8 2.6
II Well-tuned 0.7 2.4
III Well-tuned plus 0.3 0.9
additional insulation
604
-------
TABLE X-5. EFFICIENCIES AND EMISSION FACTORS USED IN
RESIDENTIAL AND CCTOffiRCIAL ANALYSIS
Fuel
Gas
Gas -
well
Oil
Oil -
well
Coal
Unit
Efficiency,
percent
65
tuned 70
65
tuned 70
50
Emission
Factor
Units
lb/10u
cu ft
Ditto
lb/1000 gal
Ditto
Ib/ton
Pollutant Emission Factors
Particulate
5,(c>
5(c)
2.4(0
2.4(c)
20
CO HC NOX
20 5^0 SQ(Z)
15 4(c> 80
-------
•TABLE X-6. RESIDENTIAL CASE I
Assumptions: 1500 oq ft house in Washington, D. C. built to FHA specifications
(The U.S. Energy Problem, Vol. 1)
Heating unit efficiency: electric 1007.
gas 657.
oil 65%
coal 50%
Energy losses:
electric • 0 3tu/yr
gas & oil - 54.1xl06 Btu/yr
coal • 100.5xlO& Btu/yr s. Pollutants
Energy
Input
Heating unit
Useful energy 100.5x10 Btu/yr
Residence
Total heat loss is about
39 Btu/hr sq ft floor area
Heat losses
4
Transmission
-> 81.2xlO<> Btu/yr
.Total 100.5x10
Btu/yr
>>
Infiltration
19.3x10° Btu/yr
Energy
Pollutants (Ib/yr)
Energy Inout Losses Parti-
Fcrm of Energy Input (Untts/vr) (Btu/yr) culate CO HC KOy. SO?
,34_13__Btu, 29,400 Kw hr/yr « "^
( ^ ' Btu/yr) ° ° 0000
/1000 Btu\
GasC"^nrJ '
Oil
Coal
/JA5.
(,
000 Btul 1070 gal/yr ,
(154.6x106 Btu/yr) 54.1x10° 2.6 8.3 0.7 20.9 40.7
23.3 442
606
-------
TABLE X-7. RESIDENTIAL CASE II
Energy
Input
Assumptions: 1500 sq Cc house in Washington D.C. built to FHA specifications
("The U.S. Energy Problem", Vol I)
Well-tuned heating unit:
Heating unit efficiency: Electric 1007.
Gas 70%
Oil 70%
Coal 50%
Cost of tuning: Electric - $0/yr
Gas $10/yr
Oil $30/yr
Coal Not effective
Energy Loss:
Electric = 0 Btu/yr
Gaa & Oil= 43.1xl06 Btu/yr
Coal » 100.5x10$ Btu/yr
Pollutants
-*
•y
Hcatidg Uait
Useful enorgy
Residence
— »
Heat Losses
Transmission
81.2xl06 Btu/yr
"I Total 100.5x10*
r»-Btu/yr
Infiltration
19 ,3xlO& Btu/yr
Energy Pollutants (Ib/yr)
Losses Parti-
T „ / -Byi ^PUt (Btu/yr) culate CO HC NOZ S02
Form of Energy Input (units/yr) ___
01 *
Electric
3413
j Btu> 29,400 KW hr/yr 0
IS J (lOO.SxlO6 Btu/yr)
flOOO BtuN ^.f*"! cu :c/vyr 43.1xl06 0.7 2.2 0.6 11.5 0.09
V^eu ft / (143.6x10° Btu/yr)
. OOP Btu
Coal
N 990 gal/yr
J (l43.6x!06 Bt
^15.500
2.4 4.3 0.6 19.3 37.6
155 23.3
607
-------
TABLE X-8. RESIDENTIAL CASE III
Assumptions: 1500 sq ft house in Washington, D.C.
Well insulated plus storm windows
CThe U.S. Energy Problem", Vol I)
Storm windows: reduce infiltration losses by 50% at cost of $2000
Insulation: reduces transmission losses by 67% at cost of $890
Heating unit efficiency = electric 100%
gas 707.
oil 70%
coal 50%
Beating unit receives regular service of cost of $30/yr oil
$10/yr gas
Service not shown effective in reducing emissions from coal-fired units
Energy loss:
Electric
Gas & oil
Coal
Energy
Input
0 Btu/yr
15.8xlO& Btu/yr
36.8x10° Btu/yr
Pollutants
s
Heating unit
Useful energy — —
_. 36.8xl06 Btu/yr
•••^Hd.
Heat Losses
Transmission
27.1xl06 Btu/yr
Total 36.8xl06 Btu/yr
Infiltration
9.7xl06 Btu/yr
Form of
Energy Input
Electric
Gas
Oil
Coal
Energy
Pollutants (Ib/yr)
Energy Input Losses Parti-
(Units/yr) (Btu/yr) late CO 11C
10,800 KUhr/yr 0
(36.8x10* Btu/hr
,.,
Btu/hr)
SPi
0
0000
IS.SxlO6 0.3 0.8 0.2 4.2 0.03
608
-------
glazing was assumed to reduce the heat loss to 16 Btu/hr per square
foot.
Analysis of the Commercial Cases
Tables X-9 and -10 provide a summary of the two commercial cases, using
emission factors for well-tuned residential heating equipment from
Table X-5. Efficiencies were assumed to be 75 percent; this is higher
than for residential units because higher efficiencies can normally be
expected from larger equipment. Coal firing was not included in the
commercial cases because it was generally precluded from use in small
commercial buildings due to operating labor and maintenance costs.
For commercial structures, there are additional avenues for energy
savings beyond improved thermal insulation. These include heat re-
covery of internal loads that would otherwise be lost, like refrigera-
tion condenser heat for grocery stores. Where the period of occupancy
is limited, some savings can be achieved by control-point setback dur-
ing unoccupied periods. These savings will depend on individual cases.
Analysis of Emissions From Larae Commercial
and Industrial Space Heating
Large commercial and industrial space heating is almost entirely by
boilers supplying steam or hot-water systems, although these boilers
may also supply steam for other purposes like industrial processes,
absorption, cooling, or on-site power.
Package firetube boilers are most prevalent in sizes up to about 500
boiler horsepower (16 x 10 Btu/hr output), frequently with dual-fuel
capability firing either gas or oil; many are capable of automatic un-
attended operation. Larger sizes are mostly watertube-type boilers and
are available to fire gas, oil, or coal (some with multiple fuel capa-
bility). Coal firing with stokers is more common in the larger sizes
where a fulltime attendant is available.
Basis for Analysis
Table X-ll shows overall efficiencies and emission factors assumed for
space heating using typical commercial-industrial boilers. The emission
factors are based on EPA published factor' *' and Battellc studies on
commercial boilers.(x~22) The analysis for this class of space heating
is based on emissions per 10^ Btu output (or energy deliverable for
space heating). Coal firing was assumed to be with stokers for com-
mercial-industrial boilers, because pulverized coal firing is seldom
used except in very large industrial boilers or in utility boilers.
Analysis of Commercial - Industrial Case
Table X-12 summarizes air-pollution emissions based on the assumptions
609
-------
TABLE X-9. COMMERCIAL CASE I.
Energy Requirements and Emissions
Based on Unit of 1000 sq ft Floor Area
and Washington, D.C. Location
Heating unit efficiency: Electric 1007.
Gas 757.
Oil 757.
Coal - not suitable to this application
Energy loss: Electric • 0 Btu/yr ,
A Gas & Oil = 14.8 x 10 Btu/yr
Energy
In ——
i
Heating
Unit
Heat losses
Pollutants
Useful energy
44.4 x 106 Btu/yr
Commercial Space (1000 sq ft)'
.Transmission I
Infiltration
&Make
I Total ^
[ 44.4 x 106
>n 1 Btu/yr
Up Airj
Total Heat Losses: Assume 26 Btu/hr sq ft at design condition
26
Btu
hr sq ft x 1000 sq ft
.
Form of
Energy
Electric
Gas
Oil
» 44,400,000
Energy Input
Units/yr
13,000 kw hr/yr
(44.4 x 106 Btu/yr)
59.2 x 103 cu ft
(59.2 x 10b Btu/yr)
410 gal/yr
(59.2 x 100 Rtll/vr
65 F
Btu/yr
Energy Loss Pollutants (Ib/yr)
Btu/yr Farciculace CO HC NO
0 0 000
14.8 x 106 0.3 0.9 0.24 4.7
14.8 x 106 1.0 1.8 0.24 8.0
lour/i
"2
0
0.0'
15.6
610
-------
TABLE X-10. COMMERCIAL CASE II
Sane as
Commercial I
Except for Improved Insulation and Infiltration Loss
and Washington, D. C. Location
Energy Loss: Electric » 0 Btu/yr
. 'Gas & oil = 14.8 x 106 Btu/vr
Energy
In
Heating Unit
Commercial Space (1000 sq ft)
Reat Losses
Transmission
Infiltration &
Make up Air
Total
27.3 x 10° Btu/yr
Total Heat Losses: 16 Btu/sq ft * Hr at design condition
« 16 x 1000
65
x 4626 x 24
Form of
Energy
» 27,300,000 Btu/yr
Energy Input, Energy Loss,
Units/yr Btu/yr
Electric 8000 kw hr/yr 0
(27.3 x 106 Btu/yr)
Gas
Oil
36.4 x 103 cu ft 9.1 x 106
(36.4 x 10" Btu/yr)
251 gal/yr 9.1 x
(36.4 x 106 Btu/yr)
Pollutants (Ib/yr)
Farticulate CO KG NO SO
^ X £
0 0000
0.2 0.5 0.15 2.9 0.02
0.6 1.1 0.15 4.9 9.5
611
-------
in Table X-ll for different types of fuels.
It should be noted that there are wide differences between grades of
oil within the residual oil classification (e.g. No. 4, 5. and 6
grades), resulting in wide differences in emissions. (X~"J These
differences are especially observed in the case of particulate and in
NOX where the range of fuel-bound nitrogen is broad. The new "low-
sulfur residual oils" (generally containing 1.0 percent sulfur) which
are replacing conventional No. 6 oils have viscosity and other burning
characteristics which place them toward the lighter grades of residual
oil; their emission performance is also more like a No. 4 or light No.
5 oil.
Emission Controls
Other than by fuel selection, applicable emission controls for this
class of equipment are generally in the area of improved adjustments
of combustion parameters or of combustion modification; combustion
modifications like staged combustion, or flue-gas recirculation are
most effective in NOX control. (It should be noted that individual
differences between different burner and boiler designs are broad, and
attention to equipment design criteria is important to emission per-
formance. Such differences often go unnoticed in compilations of
average emissions used for inventory purposes as in Table X-ll.)
For coal firing, particulate control devices are sometimes installed
in the stack. These include cyclones, electrostatic precipitators,
baghouses, and scrubbers—with the first two types being most preva-
lent; a 75 percent removal efficiency is common and is assumed in the
footnote comment in Table X-12. S02 stack gas control processes are
not yet commercially used for this class of equipment; their introduc-
tion will depend on practicability and costs of the system and probably
will follow their successful use on utility size boilers.
Insulation for Energy Conservation
in Space Heating
Improving thermal performance of building construction by insulation is
one of the simplest and most universally applicable methods of reducing
air pollution by reducing energy requirements for space heating and
cooling. With added impetus in view of the overall energy crisis, this
roach is receiving widespread attention by government agencies^ 9»
and by industrial groups. Architects and engineers are urging
greater consideration to building design that will minimize energy re-
quirements. (X'24» X"25>
Many homes and other buildings have low levels of insulation, or no
special provision for insulation. Even modest additions of insulation
can reduce heat losses for space heating by substantial amounts. The
most economical and effective location for adding insulation is in
612
-------
TABLE X-ll. EMISSION FACTORS AND EFFICIENCIES
ASSUMED FOR INDUSTRIAL SPACE HEATING
Pollutant Emission Factors
Emission
Fuel Efficiency Units Particulate CO HC NOX S02
Gas
Dist. oil
Resid. oil
Stoker Coal
75
75
75
65
lb/10 cu
ft(e)
lb/1000
lb/1000
Bal*
lb/ton(f>
6
2 -
12
13
0.5
0.9
10
0.6
0.2
0.3
0.2
45
20
60
6
0.6
43
157 5b(
57(c)
(a) Based on 0.3% Sulfur in No. 2 oil
(b) Based on 1.0% Sulfur in residual oil
(c) Based on 1.5% Sulfur in coal
(d) Based on 10% Ash in coal
(e) Based on Battelle studies (Reference X-8) except S0£ which is based
on (f)
(f) Based on EPA Emission Factors
ceilings where heat losses can be high and costs of insulation relative-
ly low per unit area.
Insulation is most economically installed during initial construction,
but insulation can be added to almost any home and to many commercial
buildings, especially roof decks. Storm windows or other double glaz-
ing, plus weather stripping, can also be added to existing buildings,
with important savings in heat losses both by conduction and by infil-
tration.
Insulation Standards. In response to President Nixon's energy message
to Congress on February 8, 1972, insulation levels required in the FHA
Minimum Property Standards have been tightened to cut maximum permissi-
ble heat loss by 40 percent.(X-26)
0
In terms of "U"-value (heat loss in Btu/hr-ft^-deg F) an uninsulated
wood frame wall gives a "U"-value of 0.22. This can be reduced to 0.05
with full insulation in the frame wall. The new FHA Standards for
home construction are as follows:
"U"-Value
Ceilings 0.05 to 0.08
Walls 0.07 to 0.17
Floors 0.08 to .24
613
-------
TABLE X-12. COMMERCIAL-INDUSTRIAL CASE
Energy losses
Electric =0 ,
Gas & Oil = 330 x 10 B'CU
Coal = 540 x 10& Btu
Pollutant
Energy In_
Heating Plant
Useful energy
109 Btu
Heated Space
Heat Loss
-> 10 Btu
Calculations on basis on 10 Btu delivered to heated space
Energy in
'(units/10 Btu Energy Losses
Uncontrolled -
Pollutant Emissions (lb/10 Btu delivered)
.Form of
Energy Used
Electrical
Gas
Dlst. Fuel Oil
delivered to (Btu/10 Btu
heater space Delivered)
293,000kwhr 0
(1000 x 106 Btu)
1.33 x 106 eu ft 330 x 106
(1330.x 106 Btu)
9200 gal 330 x 106
(1330. x 106 Btu)
Residual Fuel Oil 9200 gal 330 x 10
(1330. x 106 Btu)
Stoker Coal
118,50^ Ib 540 x 106
Par ticu late CO
0 0
8.0 17.
18.4 4.6
110. 8.3
1190 .<*) 593.
HC NO
x
0 0
0.81 60.
1.8 184.
2.8 552.
11.9 356.
so2
0
0.8
396.
1450.
3380.
(a) This emission could be reduced to 300"Ib with control equipment of moderate efficiency.
614
-------
Some industry groups are calling for even tighter standards and are
launching campaigns for increased insulation in new construction and
for installation of added insulation in existing structures.(*-27)
The economic payback in fuel savings is relatively short term (2 to 3
years), and the potential saving in total energy requirements is sub-
stantial.
Energy Conservation and Environment Burden. With "reasonably attain-
able" levels of insulation, energy conservation in residential construc-
tion has been estimated to be 1500 trillion Btu by 1982, or about 14
percent of the projected residential usage for space heating and cool-
ing.
This would be- achieved if (1) 3/4 of new residential units in the dec-
ade have proper thermal treatment, (2) 1/4 of the existing single
family homes arc upgraded in insulation, and (3) 1/8 of all single-
family homes add storm windows and doors. In consumer savings, this
would amount to 17.2 billion dollars over the next decade. Potential
improvements are even greater if more homes are upgraded.
The reduction in air pollution burden of space heating is roughly pro-
portional to energy savings from improved thermal performance.
•
This is an area where there can be effective EPA answers to the citi-
zen's question "What can I do to help in environmental protection?"
Energy Storage Systems
Hydro-Pumped Storage
Pumped storage has turned out to be the only practical way of utiliz-
ing off-peak power at a later peak-demand period. Combination pump-
turbines move water from a low elevation to a higher one during periods
of low demand for electricity, and then utilize this head to provide
electricity whenever demand exceeds normal generating capacity.
Environmental Burdens. The main objection to pumped storage comes from
local residents who dislike the appearance of storage reservoirs where
there may be a difference of 75 to 100 feet in the water level between
full and empty. In some places, as in a Colorado installation, the
upper pool is in a remote area. But, as has occurred in New York,
local residents have succeeded in blocking a pumped-storage system al-
most entirely for aesthetic reasons.
Other than appearance, a pumped storage system can have a minor impact
on the local environment because it forms a huge pond with a variable
shoreline. More importantly, since about 4 kwhr input as pumping power
to a storage pond produces only 3 kwhr output, ^there is a net loss of 1
kwhr for every 3 kwhr recovered. (One source(x~2&) suggests an even
615
-------
poorer efficiency; 3 kwhr of pumping for each 2 kwhr of energy gener-
ated.) If the input energy is provided by a full-powered steam plant,
then the total emission of pollutants increases 33 percent for that
fraction of the energy that is stored. On this basis, for each 1,000
MW day of recovered electricity, the environmental burden would be 1.3
times that of the generating plant.
Restrictions on the further use of pumped storage will be for aesthetic
rather than technical reasons. Presently operating pumped-storage
plants have demonstrated the practicality of this system of energy
storage. The required head between upper and lower pools and the design
of the turbine pumps have been evaluated thoroughly, as well as the eco-
nomic factors influencing the size and the location of pumped-storage
systems. No further R&D is required, the future extent of pumped stor-
age being fixed mostly by geographical considerations and by economic
factors influencing the ratio between base load and swinging load gen-
erating plants.
Electrochemical Storage
Electrochemical storage of off-peak energy might be used in a manner
similar to pumped hydro storage. Conventional storage batteries, ad-
vanced battery concepts, and water electrolysis-fuel cell combinations
(with storage of hydrogen and oxygen gas) are being considered for use
by the electric utility industry. Electrochemical energy storage
could be used at the substation level (10 MW) close to the load centers
with some savings in electrical transmission cost compared to pumped
hydro storage and peaking systems. Capital costs for electrochemical
energy storage would have to be competitive with pumped hydro ($100-
$150/kw) and achieve similar overall efficiency of 65 to 70 percent.
Environmental Burden. The use of electrochemical energy storage would
provide an increase in pollution level at the central station propor-
tional to the inefficiency of energy storage as for pumped hydro
storage. However, the added pollution load (atmospheric, thermal pol-
lution) would be more uniformly distributed over 24 hours. Elimination
of older inefficient fossil-fueled plants might be achieved by increased
use of energy storage. Reduced atmospheric pollution would be realized
by energy storage in combination with nuclear plants that are most
economic at high load factors. Whereas, pumped hydro has limited appli-
cability because of lack of suitable sites that are technically and
environmentally acceptable, there would be no such limitation on the
use of electrochemical energy storage near load centers.
Since there is presently a large installed electric generating capacity
to meet variations in load (~50 percent load factor for the United
States), up to 25 percent of the U. S. capacity could be electrochemical
energy storage if an economical system were available.
616
-------
Hydrogen
A great many comments have been made recently relative to a "hydrogen
economy" and an overview is provided in this Appendix. Here the stor-
age of hydrogen is discussed. Most of these are based on the clean-
burning characteristics of hydrogen where water is the main product of
combustion. But, since air is usually the oxidizcr, appreciable
amounts of NO may also be formed if the hydrogen is burned in conven-
tional equipment. Fuel cells or low-temperature catalytic combustors
will eliminate the NO problem with hydrogen systems, but both of these
energy-conversion devices will require a great deal of development be-
fore they reach large-scale acceptance.
A major advantage of hydrogen is that it can be stored in exactly the
same fashion as natural gas--usually in selected underground forma-
tions from which natural gas has been taken. Like natural gas, or a
tank farm storing residual fuel oil, or even a coal stockpile, such an
underground formation does store energy but in a form which must be
converted into electricity or shaft horsepower or heat. Nothing in
the characteristics of hydrogen make it superior as such an energy
storage system except that it can be produced by electrolysis of water
by off-peak electricity, and hence it has all the attributes of pumped
storage. Electrolysis is, presently, neither low cost nor highly effi-
cient, but if the nuclear power plants of the future must be operated
as base-load stations, then electrolysis may one day look more attrac-
tive economically than it does today.
As far as storage characteristics are concerned, hydrogen h'as two
properties that make it less desirable than natural gas--its low mo-
lecular weight that favors diffusion through underground formations
that can hold natural gas with few losses, and its low calorific value
of only 330 Btu/ft . Hence, volume wise, a storage system based on
hydrogen would have one-third the capacity of the same system with
natural gas. Storage of hydrogen in liquid form almost of necessity
will require the construction of special storage reservoirs because of
the very low temperature of liquid hydrogen,—253 C.
Hydrogen, then, can be stored like other gaseous fuels, and with some
advantages and some disadvantages compared with other energy sources.
Since it provides a highly reactive fuel, relatively easy to convert
into useful forms of energy, hydrogen in some respects is superior to
natural gas, residual fuel oil, and coal, all of which are easier to
store than hydrogen. A major advantage of hydrogen is that it can be
produced readily from off-peak electricity, but at a penalty both in
dollars and in efficiency that may well limit its wide use.
Environmental Burden. The environmental burdens are very similar to
those associated with underground storage of natural gas (Appendix F)
leakage hazards, and combustion pollutants associated with gas com-
pression equipment prime movers.
617
-------
Compressed Gas
Compressing air during off-peak hours, and expanding the air through
energy-recovery systems during maximum demand, is a promising, though
little developed, energy-storage process. Using natural underground
formations appears preferable cost-wise to building pressurized tanks
of the required size.
(X-
A unique system involving a gas-turbine has been described by Harboe
29) in which air stored under pressure in a gas-turbine cycle at one
time utilized later in the combustion/expansion part of the cycle. The
air may be compressed using electricity generated during off-peak hours.
ID this fashion, utilizing this stored air, the gas turbine can produce
as much as three times more power than if it had to drive its compressor
during send-out.
Cost-wise, such air storage systems should be appreciably less expen-
sive than other systems in meeting peak-load demands, where output is
demanded for less than 3000 hours per year. According to Harboe's
analysis, send-out costs for air storage are about the same as for
pumped storage at 3000 hours per year at 6 mills/kwhr. For lesser
operating hours per year, air storage costs remain nearly constant at
about 6 mills while other conversion systems become much more expensive.
Environmental Burden. Effects in the environment attributed to the gas-
turbine part of this storage system would be only a third that if the
gas turbine also compressed its combustion air. The total environmental
emission would depend on the system providing off-peak electricity.
Thermal Storage
No suitable means has yet been developed for storing useful amounts of
thermal energy. Most advances have been made in residential solar-
heated homes, where surplus heat stockpiled in beds of gravel or in
Glauber's salt can provide heat for short periods of sunless days.
Other materials with a high heat of fusion or which undergo a phase
change at useful temperatures have been proposed, but a completely sat-
isfactory system has yet to be devised. For residential heat storage,
huge beds of gravel filling what normally would be basement space have
proved to be most practical for storing heat provided by air circulating
through solar-heated collectors on the roof of a residence.
Little opportunity exists for devising a practical system for convert-
ing such thermal energy into electricity or shaft horsepower, largely
because the Carnot-cycle efficiency will be low for the moderate maxi-
mum temperature of the working fluid reached in most heat cycles.
Utilizing halogenated hydrocarbons or such fluids as butane and propane,
thermal storage to be used later makes more sense, but the costs are
expected to be high. The field of thermal energy storage has been ex-
plored quite thoroughly. In general, it appears to have little promise
618
-------
if the eventual goal is to generate electricity or mechanical output,
Waste Heat Recovery
Because of thermodynamic limits on the efficiency with which heat
energy can be converted to work energy, electrical power generating
stations must create more heat energy than the electric power they
produce. The unused heat must then be disposed of, presumably to a
water body or to the atmosphere. For example, a modern nuclear power
generating station operates with an efficiency of approximately 32
percent. For every unit of electrical energy produced, two units of
heat energy are discarded as waste heat. Although the thermal impact
of this waste heat on the environment can be a significant problem,
the concept of waste heat recovery is not directed at reducing the
effect of waste heat on the environment but rather at making better
use of this great energy resource.
finding uses for waste heat is not as easy as it might first appear.
The temperature of the waste heat from the power plant is often as low
as 80 to 100 F. There are not many processes that can make productive
use of temperatures this low. In a sense finding uses for waste heat
is nearly equivalent to finding means of beating the Second Law of
Thermodynamics. As a result many of the more promising applications
of waste heat are closely associated with biological comfort rather
than mechanical or chemical processes.
Consideration of waste heat recovery should not be restricted to those
processes which can only make use of temperatures in the 80 to 100 F
range; however, waste heat can be rejected from the power station at
higher temperatures in the form of low-grade steam. Although this re-
sults in a poorer-efficiency for electrical power generation, the
benefits from the process and the electrical power generation may in a
combined sense have made better use of the energy resources. On what
basis should a use of waste heat be considered sufficiently productive
to be employed? In the present system, the yardstick is purely finan-
cial. Unfortunately, the present economic system probably places too
low a value on our limited energy resources. If a national energy
policy were to place higher priorities on better utilization of fuel
resources, many more uses of waste heat could be more readily justified
than are possible today using financial criteria.
A number of the uses of waste heat that have been investigated are
presented in the following paragraphs:
Central Heating and Air Conditioning
The use of low-grade steam for heating residences and stores has been
employed in some cities for a number of years. Since the steam can
619
-------
be transported economically for only a few miles, the practical use of
steam for central heating requires proximity of the power station to a
large population. Conversely, the potential environmental effects of
nuclear and fossil fuel plants encourage more remote siting. Air con-
ditioning through the absorption process can also be a practical use
of low-temperature steam. This use can be particularly effective in
reducing electrical power needs in regions controlled by summer demand.
Some investigation has been performed on "new city" concepts inten-
tionally designed around small nuclear power plants in order to provide
heating and air conditioning. An underground reactor in a suburb of
Stockholm, Sweden, is used for residential heating in this manner.
On a smaller scale "total energy systems" should be considered as a
productive use of waste heat for central heating. A completely en-
closed community has been designed for Alaska which is the ultimate
extrapolation of the total energy concept.
Water Treatment
Combined power generating stations and desalination plants have been
given a great deal of attention. Bolsa Island, a proposed nuclear sta-
tion of this type, was eventually dropped because of financial consid-
erations. This use of waste heat does hold promise for the future,
however, either in the production of drinking water or water for irri-
gation. Similarly, the use of waste heat has been suggested for sewage
and waste water treatment. Distillation can be employed to separate
the water from contaminants in the waste water. It has also been sug-
gested that heating of sewage can be used to speed up the biological
processes of waste treatment.
Industrial Processes
Few chemical or mechanical processes can make use of very low-grade
heat. There are, however, applications for process steam extracted at
higher temperatures that should be considered as a use of waste heat.
The Dow Chemical Company will make use of steam extracted from a nucle-
ar power plant under construction in Midland, Michigan, for the produc-
tion of chemicals. A similar arrangement is planned in Germany at the
BASF plant.
Agriculture
Some of the more promising uses of waste heat are in the area of agri-
culture. Waste heat can either be employed to extend the growing
season for plants or to improve production by maintaining temperatures
close to the optimum for growth. Water, used for both irrigation and
heating, can be sprayed over the plants or used to heat the soil through
subsurface pipes. Investigation of these techniques is underway in the
Pacific Northwest. Waste heat can also be employed in the heating and
cooling of greenhouses for the production of high value crops.
620
-------
In a similar fashion the heating of animal shelters has been suggested
as a means of decreasing feed consumption and increasing productivity.
The effects of climate control on poultry and swine productivity have
been studied and the results indicate that significant improvements
can be achieved. To be practical, however, farms would have to be lo-
cated within close proximity to the power stations. Furthermore, even
if all of the swine and poultry in the country were to be grown in this
fashion it would represent a usage of only a few percent of the avail-
able waste heat from electrical power production.
Aquaculture
Aquaculture represents another promising application of waste heat.
Growth rates for many fish, crustaceans and shellfish are quite temper-
ature dependent and productivity can be greatly improved by maintaining
temperature control. There are a number of successful commercial demon-
strations of aquaculture which include catfish, trout, shrimp, and
oyster production. A classic example of the use of waste heat is pro-
vided by the commercial production of oysters in Long Island Sound in
the effluent of the Long Island Lighting Company. This example also
shows the potential conflict between aquaculture and preservation of a
natural environment. Recent state environmental protection laws limit
power plant effluent temperatures to below the temperatures of value in
promoting oyster production. Once again degradation of the natural en-
vironment must be weighed against the productive usage of energy.
Miscellaneous Waste Heat Recovery Uses
A number of diverse uses can be identified for waste heat. Often these
uses involve a very small fraction of the available energy or have very
restricted application. For example, it has been suggested that waste
heat be employed in clearing snow from city streets or the runways of
airports. Low-temperature steam also has been proposed as the motive
force for urban mass transportation systems.
In conclusion, waste heat recovery as a means .of better utilizing our
energy resources does hold some promise particularly in the areas of
heating and air conditioning, agriculture and aquaculture. There are
only a few examples where a clear financial incentive exists to exploit
this energy resource in today's economy. A more realistic assessment
of the value of our fuel resources to future generations would, how-
ever, indicate the need for more efficient use -of these resources and
would enhance the benefits to be gained from waste heat recovery.
621
-------
References
X-l. "Hydrogen Fuel Use Cells for New Source", Chemical and Engineer-
ing News, pg 16, July 3, 1972.
X-2. Linden, H. R., "The Hydrogen Economy". J. of Fuel and Heat Tech-
nology, p 17, November, 1971.
X-3. Gregory, D. P., and Wurm, J., "Production Distribution of Hydro-
gen as a Universal Fuel", Proc. 7th Intersociety Energy Conver-
sion Conference, September, 1972.
X-4. "Hydrogen: Likely Fuel of the Future", Chemical and Engineering
News, p 16, June 26, 1972.
X-5. Martin, F. A., "The Safe Distribution and Handling of Hydrogen
for Commercial Applications", Proc. 7th Intersociety Energy Con-
version Conference, September, 1972.
X-6. Gregory, D. P., "Energy from the Ocean", American Gas Association
Monthly, June, 1972.
X-7. Linden, H. R., "Is Our Environment Really Doomed?", American Gas
Association Monthly, Vol 53, No. 6, p 16, June, 1971.
X-8. "Hydrogen Fuel Economy: Wide Ranging Changes", Chemical and
Engineering News, p 27, July 10, 1972.
X-9. Meadows, P., DeCarlo, J. A., "Hydrogen", U. S. BuMines Bulletin
650, 1970, p 97-109.
X-10. Goldbergcr, W. H., "The Union Carbide Coal Gasification Process,
Status of the Development Program", Fourth Synthetic Gas Sym-
posium, Chicago, October 31, 1972.
X-ll. Ertel, C. M., & Metcalf, J. T., "New Fuels-Old Coal", Mechanical
Engineering, March, 1972, p 25.
X-12. Witcofski, R. D., "Potentials and Problems of Hydrogen Fueled
Supersonics and Hypersonic Aircraft", Proc. 7th Intersociety
Energy Conversion Conference, September, 1972, p 1359.
X-13. Weil, K. H., "The Hydrogen I. D. Engine - Its Origins and Future
in the Emerging Energy Transportation-Environment System", Proc.
7th Intersociety Energy Conversion Conference, September, 1972.
622
-------
|