EPA-600/2-75-009
May 1975
OIL SHALE AIR POLLUTION CONTROL
by
Evan E. Hughes
Patricia A. Buder
Carmen V. Fojo
Robert G. Murray
Ronald K. White
Contract No. 68-01-0483
PEMP 02
Program Element 1NB458
Project Officer:
James C. Johnson
Air Technology Branch
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
Prepared for:
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
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ABSTRACT
This study evaluates the air pollution potential of emissions of
particulates, sulfur dioxide, oxides of nitrogen, and-hydrocarbons from
the anticipated development of an oil shale industry. The analysis is
based primarily on the published description of a TOSCO II retorting
process as planned for commercial use by the Colony Development Operation
The technology, processes, plans, projections, and environmental impacts
of oil shale development are reviewed. The results of dispersion model
calculations of concentrations of pollutants in ambient air near oil
shale plants employing TOSCO II and in situ processes are presented.
These calculations for the TOSCO II plant assume that best available
controls are applied to the process planned by Colony. Requirements for
additional control are estimated by comparing calculated ambient air
quality with standards. Options for supplying the additional control
indicated for particulates and sulfur dioxide are identified.
This report was submitted in fulfillment of Contract 68-01-0483 by
Stanford Research Institute under sponsorship of the U.S. Environmental
Protection Agency. Work was completed as of May 1979.
11
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CONTENTS
ABSTRACT iii
LIST OF ILLUSTRATIONS v
LIST OF TABLES vii
UNITS OF MEASURE ix
ACKNOWLEDGMENTS xii
I CONCLUSIONS 1
II RECOMMENDATIONS 3
III INTRODUCTION 5
IV OIL SHALE TECHNOLOGY AND PROCESSES 9
V PLANS AND PROJECTIONS FOR OIL SHALE DEVELOPMENT 23
VI ENVIRONMENTAL EFFECTS OF OIL SHALE DEVELOPMENT 31
VII AIR POLLUTION: EMISSIONS AND AMBIENT AIR QUALITY .... 41
VIII CONTROL REQUIREMENTS FOR AIR POLLUTANTS 77
IX ASSESSMENT OF AIR POLLUTION CONTROL METHODS 87
iii
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ILLUSTRATIONS
1 Processes, Streams, and Emissions for Production
of Oil from Shale .......... .......... 14
2 TOSCO II Plant Configuration .............. 18
3 In Situ Plant Configuration ............... 20
4 Map of Oil Shale Plant Locations ............ 25
5 Annual Frequency Distributions of Wind Direction
at Four Colorado Sites ................. 46
6 Annual Frequency Distributions of Wind Speed
at Four Colorado Sites ................. 48
7 Annual Average Particulate Concentration
for a TOSCO II Oil Shale Plant Using Grand Junction,
Colorado Meteorology .................. 54
o
8 Annual Average Particulate Concentration (|jg/m )
for a TOSCO II Oil Shale Plant Using Salt Lake City,
Utah Meteorology .................... • 55
9 24-Hour Worst Case Average Particulate Concentration
(pg/m3) for a TOSCO II Oil Shale Plant Under Conditions
of Neutral Stability; and a North Wind of 1.5 m/sec ... 56
10 24-Hour Worst Case Average Particulate Concentration
(pg/m3) for a TOSCO II Oil Shale Plant Under Conditions
of Neutral Stability and a West Wind of 1.5 m/sec ... 57
11 Annual Average S02 Concentration (pg/m3) for a TOSCO II
Oil Shale Plant Using Grand Junction, Colorado
Meteorology ....................... 58
o
12 Annual Average SO2 Concentration ( )jg/m ) for a TOSCO II
Oil Shale Plant Using Salt Lake City, Utah Meteorology. . 59
13 24-Hour Worst Case Average S02 Concentration ((jg/m3)
for a TOSCO II Oil Shale Plant Under Conditions of Neutral
Stability and a North Wind of 1.5 m/sec ........ 60
o
14 24-Hour Worst Case Average S02 Concentration (pg/m )
for a TOSCO II Oil Shale Plant Under Conditions of Neutral
Stability and a West Wind of 1.5 m/sec ......... 61
IV
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15 3-Hour Worst Case Average HC Concentration (p,g/m3)
for a TOSCO II Oil Shale Plant Under Conditions of Neutral
Stability and a North Wind of 1.5 m/sec 62
q
16 3-Hour Worst Case Average HC Concentration (p.g/m )
for a TOSCO II Oil Shale Plant Under Conditions
of Neutral Stability and a West Wind of 1.5 m/sec 63
17 Annual Average NO Concentration (^g/m3) for a TOSCO II
A
Oil Shale Plant Using Grand Junction, Colorado
Meteorology 64
o
18 Annual Average NOx Concentration (pg/m ) for TOSCO II
Oil Shale Plant Using Salt Lake City, Utah Meteorology. . 65
19 Simplified Process Diagram—Above-Ground Retorting
Plant 90
20 Ore Preparation System for TOSCO II Plant 92
21 Pyrolysis and Oil Recovery Unit for TOSCO II Plant ... 96
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TABLES
1 Identification of Streams Shown in Figure 1 15
2 Stack Parameters and Emission Rates for a 16,000
m3/D (100,000 B/D) TOSCO II Plant with Emissions
Controlled 17
3 Stack Parameters and Emission Rates for a 16,000
m3/day (100,000 B/D) In Situ Plant 21
4 Shale Oil Plant Locations and Types ..... 24
5 Required Oil Shale Industry Growth Rates to Meet
Selected Goals 28
6 Estimates of Water Use in Oil Shale Production
(m of water per m3 of oil produced) 34
7 Estimates of Air Pollutant Emission Factors in Oil Shale
Production 37
8 Stack Parameters and Emission Rates for a 16,000 m3/D
(100,000 B/D) TOSCO II Plant with Emissions Controlled ... 53
9 Control Requirements Based on Federal Primary and
Colorado Air Quality Standards and Emissions from a
16,000 m3/day (100,000 B/D) TOSCO II Plant, Controlled ... 66
10 Control Requirements Based on Federal Secondary, Class I
and Class II Air Quality Standards and Emissions from a
16,000 m3/day (100,000 B/D) TOSCO II Plant, Controlled ... 67
11 Control Requirements Based on Federal Primary and Colorado
o
Air Quality Standards and Emissions From a 16,000 m /day
(100,000 B/D) In Situ Plant 70
12 Control Requirements Based on Federal Secondary, Class I
and Class II Air Quality Standards and Emissions from a.
16,000 m3/day (100,000 B/D) In Situ Plant 71
13 Estimates of Additional Control Requirements for a
16,000 m3/day (100,000 B/D) TOSCO II Plant Based on
Dispersion Modeling and Various Ambient Air Quality
Standards 79
vi
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14 Emissions from Combustion in the TOSCO II Process
Compared with Federal Standards for Utility Boilers 82
15 Range of Reasonable Requirements for Control Beyond
Best Available for a 16,000 m3/day (100,000 B/D)
TOSCO II Oil Shale Plant 84
16 Ore-Preparation System Emissions for TOSCO II Plant
(16,000 m3/day) 93
17 Typical Fuel Consumption Schedule for TOSCO II Plant*
(16,000 m3/day) 97
*
18 Emission Factors for TOSCO II Plant Planned Fuels 98
19 Pyrolysis and Oil Recovery Unit Emissions for TOSCO
II Plant (16,000 m3/day) . . . ' 99
20 Product-Upgrading System Emissions for TOSCO II Plant
(16,000 m3/day) 100
21 Totals of Emissions for TOSCO II Plant (16,000 m3/day) . . . 101
vn
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UNITS OF MEASURE
Conversion of U.S. units of measure to the metric system is now
proceeding rapidly. Several agencies of state.and federal governments
now call for the use of metric units (e.g., the geothermal group of the
California Division of Oil and Gas). The Environmental Protection Agency
has required the use of metric units in this report.
.SRI has, therefore, employed the International System of Units (SI),
which is based upon the meter, kilogram, and second as the basic measures
of length, mass, and time. Within this system, energy units are derived
combinations of the basic units. The preferred unit for energy is the
joule.
During the period of changeover to metric units, a certain amount of
confusion must be expected—especially since energy is measured in such
various units as Btu, joules, kilocalories, barrels of oil equivalent,
kilowatt hours, therms, and so on. To minimize this confusion, SRI has
expressed energies in joules or multiples of the watt hour and made sparing
use of hybrid units, such as metric ton and the engineering units of the
English system. The prefixes kilo, mega, and tera are sometimes used
in accordance with standard SI practice. The following listing summarizes
the most common conversion factors that readers may want to have
available while reading this report. A list at the end of this section
presents a few conversion factors of special importance in discussion of
oil production and air pollution.
Further information on the International System of Units can be
found in Special Publication 330, National Bureau of Standards,
Department of Commerce.
viii
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Energy
3
1 Btu = 1.055 X 10 joule (J)
-4
1 Btu = 2.929 X 10 kilowatt hour (kWh)
6
1 kWh = 3.600 X 10 .joule (J)
3
1 kcal = 4.186 X 10 joule (J)
Length
-2
1 inch = 2.540 X 10 meter (m)
1 inch = 2.54 centimeter (cm)
1 foot = 0.3048 meter (m)
1 yard = 0.9144 meter (m)
1 mile - 1.609 kilometer (km)
Mass
1 pound = 0.4536 kilogram (kg)
2
1 ton (short) = 9.072 X 10 kilogram (kg)
1 tonne = 1 metric ton (AIT)
3
1 metric ton = 10 kilogram (kg)
Area
1 acre = 0.407 hectare (ha)
3 2
1 acre = 4.047 X 10 square meter (m )
-2 2
1 square foot - 9.290 X 10 square meter (m )
6 2
1 square mile = 2.590 X 10 square meter (m )
r '^~\
1 square mile = 2.59 square kilometer l(km) J
Volume
-2 3
1 cubic foot = 2.832 X 10 cubic meter (m )
-3 3
1 gallon = 3.785 X 10 cubic meter (m )
3
1 barrel (oil) = 0.1590 cubic meter (m )
ix
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Pressure
1 pound per square inch = 6.895 X 10 Pascal (Pa)
5
1 bar = 10 Pascal (Pa)
5
1 atmosphere = 1.013 X 10 Pascal (Pa)
2
1 Pascal = 1.0 newton/m
Equivalents
Factor
-3
10
-2
10
-1
10
1
10
2
10
3
10
6
10
9
10
12
10
Prefix
milli
centi
deci
deka
hecto
kilo
mega
giga
tera
Symbol
m
c
d
da
h
k
M
G
T
Conversions especially important in this report:
• Oil—1 m3 = 6.3 barrels
• Particulate loadings--! mg/m = 0.00043 grains/ft3
3 r>
• Volumetric flow rates—1 m /sec = 2120 ft°/min
Emission factors—1 kg/GJ =2.3 Ib/million Btu
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ACKNOWLEDGMENTS
This study was organized within the Operations Evaluation Department
of SRI. The project leader was Evan E. Hughes. Supervision was exercised
by Edward M. Dickson, Manager of the Resources Program of the department.
Ronald K. White had major responsibility in the study as the author of the
sections of the report dealing with air pollution control technology.
Robert G. Murray of the Chemical Engineering Group contributed the
sections on oil shale technology and the plans of the industry. He also
provided other members of the project team with insights and information
on oil shale processes and plans.
Carmen V. Fojo of the Energy Technology Department reviewed various
sources of information on the environmental effects of oil shale development
and organized a summary of such effects for this report.
Patricia A. Buder of the Atmospheric Sciences Laboratory carried out
the dispersion modeling of air pollution from oil shale production and
wrote the section of the report discussing such results. Support in this
work was provided by Francis L. Ludwig. Walter F. Dabberdt supervised this
aspect of the project.
Elizabath D. Gill of the Literature Research staff of the SRI library
provided support for the project. This work was supervised by Ardra F.
Fitzgerald.
xi
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I CONCLUSIONS
During the next decade a commercial oil shale industry could develop
in western Colorado and eastern Utah and grow to a production capacity
of 80;000 m3/day (500,000 barrels/day) of oil. The TOSCO II retorting
process is likely to be used in most of the first generation plants.
Colony Development Operation has published a detailed environmental
impact analysis of a proposed TOSCO II oil shale plant. A number of
air pollution control systems are included in the proposed plant, but the
level of control is less than that attainable with the best available
control technology.
Application of best available control technology would result in
improved removal of particulates by cyclones, baghouses, and wet scrubbers,
thereby reducing overall particulate emissions to about a third of the
level specified in the Colony publication.
More extensive treating of fuels burned in the plant would constitute
the application of best available control to the emissions of SO^ and
NOX. This would reduce S02 emissions by about 15 percent and NOX
emissions by about 50 percent.
o
Atmospheric dispersion modeling of emissions from a 16,000 m /day
(100,000 B/D) TOSCO II plant having best available controls suggests
that such a plant can avoid violations of federal primary ambient air
quality standards for particulates, sulfur dioxide (SOg), hydrocarbons
(HC), and oxides of nitrogen (NO ).
X
From the same modeling, requirements for controls beyond those
considered to be the best available have been estimated by application
of more strict ambient air quality standards that can reasonably be
1
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expected to apply in the oil shale region. The standards most likely to
apply are those for regions that the state designates as Class II under
the proposed federal standards to prevent significant deterioration of
ambient air quality in unpolluted areas. For particulates and sulfur
dioxide, Class II standards lead to the following requirements for
additional control:
• Particulates: 85 percent additional control required to
meet the 24-hour average Class II standard.
e SOg: 72 percent additional control required to meet the
one-year average Class II standard.
No additional control requirements are indicated for hydrocarbons and
oxides of nitrogen. This conclusion is based on comparison of calculated
concentrations with the federal primary standards for HC and NO .
£i
Photochemical oxidant formation was not included in the dispersion model
use, nor were comparisons made with ambient air quality standards for
oxidant.
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11 RECOMMENDATION S
Additional efforts are needed to assure that the development of an
oil shale industry does not produce significant degradation of air
quality through emissions of particulates, sulfur dioxide, and oxides
of nitrogen. For each of these three pollutants, the problem and
suggested steps toward a solution are specified below:
• Particulates: Appreciable control beyond best available is
required to meet air quality standards applicable in Class II
regions under proposed federal "non-degradation" standards. The
potential contribution of higher stacks and more perfectly
maintained baghouses to the attainment of this additional control
should be determined. The potential for increased control should
be specified on a unit operation basis, guided by additional
dispersion modeling to determine the relative contributions of
various units to the excessive concentration of particulates.
• Sulfur Dioxide (SO2): These emissions from combustion sources
within the oil shale plant must be controlled to a significant
degree beyond the emission levels considered best available
according to new source performance standards for liquid fossil
fuel fired boilers. The additional control is necessary in
order to meet the Class II "non-degradation" standards expected
to apply to ambient air quality in the oil shale region. Flue
gas desulfurization and additional hydrotreating of liquid fuels
burned in the plant are actions that could be taken to meet the
requirement for additional control. No steps to develop new
control technology, other than continued efforts to improve flue
gas desulfurization, are recommended for SC^ emissions from oil
shale plants.
• Oxides of Nitrogen (NOV): No requirement for additional control
yi
has been established by comparison of dispersion modeling of oil
shale plant emissions with ambient air quality standards.
However, because the achievement of emissions consistent with
best available control are likely to require a much lower
nitrogen content in the fuel, some investigation of the feasibility
of much more extensive hydrotreating should be carried out. This
has significance beyond the oil shale plant, because the product
oil, with its high nitrogen content, is a candidate for sale as
a fuel oil rather than a refinery feedstock.
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Some recommendations for further research and development are more
general than those classified by pollutant type above. These are:
• Analysis of the tradeoffs between taller stacks and increased
cleanup of emission or process streams should be made for the
case of oil shale plants.
• Sensitivity analyses of the dispersion modeling and the resulting
control requirements should be carried out.
• Ambient air quality in a region occupied by a number of plants
should be made the basis of a control requirement determination;
the sensitivity of the result to various strategies for
incorporating regional and multiplant considerations should be
determined and evaluated.
• Other oil shale production processes, differing from TOSCO II
primarily in the retorting stage, should be analyzed to the
extent practical in the light of available information, using
the present analysis as a reference case.
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Ill INTRODUCTION
This is a report on Phase II of an SRI project in support of energy
research and development planning in the Office of Research and
Development of the U.S. Environmental Protection Agency. Phase I of this
effort consisted of a survey of the environmental effects of some new
energy technologies and an identification of some research and develop-
ment needs directed toward environmental quality control. An account of
this previous work is presented in the SRI report, "Control of Environ-
mental Impacts from Advanced Energy Sources," published as EPA-600/2-74-
002, dated March 1974. Four advanced energy sources were emphasized in
that report: solar, geothermal, oil shale, and solid wastes.
The present report emphasizes the air pollution control problems
expected from first generation commercial plants for producing oil from
the shale of the Green River Formation found in Colorado, Utah, and
Wyoming. The main conclusions of the study have been summarized in the
two preceding sections (Sections I and II). The following sections
(Sections IV through IX) present the specific analyses that support
these conclusions. The organization of the following sections outlines
SRI's analysis:
Section IV reviews the technology and processes for the production
of shale oil. It builds on the discussion in the previous report (see
Section IV-D and Appendix C of "Control of Environmental Impacts from
Advanced Energy Sources") and focuses on the technology that is nearest
to commercial realization, namely the TOSCO II retorting system. In-situ
retorting is also reviewed.
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Section V presents the announced plans of the companies and
organizations of companies that may build plants for the production of
oil from shale during the next decade. It also discusses projections
of growth of the oil shale industry by three different sources.
Section VI reviews the general environmental impacts of oil shale
development as presented in the previous report and in some other recent
sources. The review covers air, water, and land impacts.
Section VII begins the specific task of quantitatively determining
the air pollution control requirements of the oil shale industry by
presenting the results of some atmospheric dispersion modeling to
determine the concentrations of pollutants in ambient air arising from
omissions from proposed oil shale production facilities. The facilities
are assumed to employ the best available air pollution control technology.
Hence, this modeling is based on a plant with the emission properties
specified in a later section (Section IX) of the report. Control
requirements beyond "best available control" are estimated by comparison
of the calculated air pollutant concentrations with various possible
ambient air quality standards. While the focus is on TOSCO II retorting,
some results are also presented for an in-situ retorting facility.
Section VIII summarizes the control requirements determined by the
air quality modeling approach of Section VII. The control required to
bring TOSCO II combustion operations into compliance with new source
performance standards for emissions from fossil fuel fired boilers is
briefly discussed. The conclusions as to what constitute reasonable
requirements for control beyond the best available are presented in
this section.
Section IX describes the air pollution control planned for the
TOSCO II retort and oil production complex proposed by Colony Development
Operation. Tables and figures are used to describe the production
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processes and their associated controls. Tables describe unit operations
within the total oil production system and present the uncontrolled
emissions, the results of planned controls, and the results of best
available control. Here "best available" is quantified and specifically
defined for each unit operation.
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IV OIL SHALE TECHNOLOGY AND PROCESSES
A. Introduction
As the oil shale situation in the western United States slowly
emerges from pilot plant to commercial production, the problems change
in character. Specific technical problems pertaining to retorting assume
less importance and the problems related to industry requirements assume
greater importance. The necessity for an organization to solve a wide
range of practical problems in order to get a plant on stream tends to
make it favor proven technology and high reliability over more advanced,
potentially more efficient, but untested solutions. Thus, while there
are several different types of retorts at various levels of development,
only two or three of the most advanced designs are likely to be placed
in commercial production.
In addition to a large reserve of adequate quality shale, a suffi-
cient supply of water is an essential prerequisite for a shale enterprise,
Converting oil shale to a salable crude oil and by-products will also re-
quire the following operations:
• Mining of the shale and transporting it to the retorts.
• Separation of valuable hydrocarbons from the mineral
residue.
• Disposal of all residues, effluents and emissions in
an acceptable manner.
• Conversion of the crude shale oil to a transportable
product.
• Transport of the product and by-products to market.
• Disposal of valueless by-products.
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Economies of scale in most of the process steps required in a
commercial shale enterprise are of such importance that a small-sized
operation is economically unattractive. As a result, the industry cannot
start small and make its early mistakes on a small size. This requirement
to be big limits entry into the industry to groups with relatively large
capital resources.
B. Underground Mining and Above-Ground Retorting
The classical method of obtaining and retorting shale is underground
mining followed by above-ground retorting. It has been practiced in
many places around the world for over 100 years. The methods developed
for the U.S. shales differ due to the use of modern mining technology and
due to the special characteristics of the shale. Mining, transporting,
and crushing operations for shale are quite similar to those used in
several rock and mineral industries. The principal difference lies in
the magnitude of the proposed operations.
Retorting, on the other hand, is not quite like any existing industry
operation. It resembles the production of coke from coal, except that
the solid produced (spent shale) is not a valuable product, but is a
liability to be disposed of. It resembles metallurgical ore roasting,
except that the product is combustible. These differences in physical
characteristics and product values place severe restrictions on what is
economically possible in retort design.
Retorting processes can be placed into four classes according to
the method of transferring heat to the shale.
Class I,External Combustion--Heat is transferred to the shale
through a wall. The simplest form of this retort is a Fischer
assay device for measuring the amount of oil that may be re-
covered from a sample of shale. The shale is placed in a
closed container and heated by means of a fire outside the
retort. The retorted gas and liquids are uncontaminated by
10
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air and the sulfur compounds are in a reduced state, e.g.,
hydrogen sulfide rather than sulfur dioxide. Because the
heat source is external to the retort, any fuel may be used.
The emissions from the heat source will depend upon the fuel
used. This type of retort is expensive in terms of capital
and operating costs per unit of produced oil. It is not
likely to be competitive with other types of retorts.
Class II, Internal Combustion—Heat is transferred to the shale
from hot gases generated in the retort by the combustion of
some of the carbon and hydrogen present in the shale. Ex-
amples include the Paraho* retort, the N-T-U retort, and the
gas combustion and Laramie simulated in situ retorts of the
Bureau of Mines. A controlled amount of air and recycle
gas is introduced into the retort and a mixture of product oil
and low heat content (low Btu) gas is recovered. The
advantages of this system are low capital and operating costs
per unit of shale input. Disadvantages are low recovery of
the total energy in the shale and the production of a large
quantity of flue gas containing about 3 MJ/m (80 Btu/scf)
energy content. For example a typical gas combustion
retort plant producing 16,000 m3 (100,000 barrels) per day
of shale oil would also produce about 23 million cubic
meters per day of low heat content gas. Sulfur contained
in this gas would be on the order of 200 tonnes per day.
Class III, Hot Fluid—Heat is transferred to the shale by
passing hot gas that has been heated in an external furnace
through the shale bed. The Petrosix, the Union-SGR, and
one variation of the Paraho are examples of this type of
retort. By circulating high heat content (high Btu) product
gas through the retort, the problems of the Class II retort
are eliminated. The gas has much more value and sulfur
compounds can be removed by amine scrubbing. However, the
capital cost of the equipment required to heat the re-
circulating gas makes this an expensive type of retort.
Additional problems are caused by the tendency of the
external gas heater to accumulate carbon deposits caused by
oil mist in the gas.
*
The Paraho project is committed to developing two different retorts—I,
a gas combustion type and II, a hot gas circulation type.
11
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Class IV, Hot Solid—Heat is transferred by the introduction
of hot solids into the retorting bed. The two best known
examples of this class are the TOSCO II retort in which heat
is transferred by ceramic balls and the Lurgi-Ruhrgas retort
in which heat is transferred by recirculating hot shale ash.
The principle of retorting is to combine raw shale with
enough hot recycle solids to produce retorting temperatures
in the mixture. This class of retort is fairly expensive,
but does recover a high percent of the energy in the shale.
The gas from the retort has a high heat content (high Btu)
and sulfur compounds are in the reduced state.
As shown below in Table 4, most of the first generation commercial
ventures plan to use the TOSCO II retort. This is the only retort that has
been demonstrated in the configuration of the commercial facility. Union
Oil Company plans to use their own retort system and will build a
demonstration unit before proceeding with a commercial plant.
The group on the combined Utah a and b sites may use a Paraho type
of retort if the Paraho demonstration is successful. Superior Oil Company
has not announced the type of retort they plan to use. However, their
process requires that the shale ash not be overheated as would occur in
a gas combustion type of retort.
There is an interaction between the method of retorting and the
sulfur dioxide emissions that has not yet been resolved. Class II retorts
(gas combustion and Paraho I) produce a large quantity of low heating
value (3.7 MJ/m3 or 100 Btu/scf) gas as a by-product that may contain
oxidized sulfur compounds. Class IV retorts (TOSCO II and Union-SGR)
produce gaseous products that are not diluted with air; the gas has a
high heating value (about 30 MJ/m3) and the sulfur is in the reduced state.
In general, it is much less expensive to remove sulfur compounds from
high heating value gas.
Of the three retorts likely to reach commercial production, infor-
mation in the public domain is available only for TOSCO II. Neither
12
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Paraho nor Union have published sufficient details of their processes to
allow calculation of off-gas composition. However, both Paraho and Union,
or any other retort, could meet the sulfur dioxide and hydrocarbon emis-
sion restrictions presently applicable to new fossil-fueled power genera-
tion plants by using stack gas scrubbing. (It may be that such stack gas
scrubbing would be so expensive as to make the retort uncompetitive with
other types of retorts that do not require scrubbers.)
From the above line of reasoning we conclude that overall emissions
from a conventional shale industry may be estimated using TOSCO II emis-
sion rates. Such estimates of emissions have been derived for a typical
production facility based on TOSCO II retorting with subsequent upgrading
of the crude shale oil to a low sulfur fuel oil by delayed coking and
hydrogenation. This facility is described in the next section.
C. Shale Oil Production Module
The basic unit used in this study of a shale oil industry is a com-
plete facility for mining oil shale, retorting the shale, disposing of
the spent shale, and upgrading the crude shale oil to 16,000 m /day
(100,000 barrels per day) of low sulfur fuel oil.* A complete description
of these operations as they are proposed by the Colony group may be ob-
j.
tained in Reference 1.' The information obtained from this reference was
scaled to our 16,000 m3/day (100,000 barrels per day) unit size and the
resulting plant flows are shown in Figure 1 and Table 1. The block flow
diagram, Figure I/ shows the major processing units, the major process
flow streams, and all plant inputs and output streams. Table 1 lists the
*
The proposed low sulfur fuel oil is about 0.3 percent sulfur, somewhat
higher than some previous plans for a synthetic crude oil of less than
0.1 percent sulfur content by weight.
References are listed at end of section.
13
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quantity and type of water flow streams 'and atmospheric emissions.
Table 2 lists the physical characteristics of the emission streams and
Figure 2 is a diagram showing typical locations of the stacks in a shale
oil facility.
D. In Situ Retorting
The previous sections discussed conventional oil shale technology
and some plans of groups who intend to enter the industry. This
section considers in situ extraction of oil from shale and its potential
for augmenting the conventional approach. In situ technology is believed
to be several years behind conventional above-ground retorting and there
have been no publicly announced plans for a commercial in situ venture.
Nevertheless, it must be considered a potential method to produce oil
after about 1980 because there may be lower capital and operating costs
as well as less water consumption.
Methods proposed for in situ oil recovery include hot fluid circula-
tion, solvent extraction, and underground combustion. Several procedures
have been proposed for preparing the shale deposit prior to the retorting
operation such as rubblizing, fracturing, leaching out soluble inorganic
components, or draining water from the naturally porous areas. The
method most apt to be developed to commercial practice consists of pre-
paring underground retorting chambers filled with shale rubble using con-
ventional mining methods and then heating the shale by combustion start-
ing at the top of the column. This procedure is similar to that used in
fixed bed retorts such as the N-T-U and the simulated in situ retort
2
located at Laramie Energy Center. Of course the in situ retorts must
be on a much larger scale to be economic.
Garrett Research Division of Occidental Petroleum Corporation has
developed and field tested this method of retorting. The first field
test contained about 3,500 tonnes of shale rubble, and 190 m^
16
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(1,200 barrels) of oil were recovered. At present they are preparing to
test a retort 75 m (250 feet) in height and 30 m (100 feet) square. These
dimensions are in the range of a commercial development of a shale deposit.
Larger retort dimensions, if possible, would result in lower overall costs
as well as a greater recovery of the oil (kerogen) in-place in the shale.
Although the mining and retorting costs for in situ recovery are
estimated to be lower than for conventional shale oil retorting, there
are a great many unknown cost factors that must be established before a
commercial venture can be established. Retort and facility design will
be dependent upon the geology and hydrology of the particular shale de-
posit to be developed. Aquifers above or below the shale bed will re-
quire water control or extensive dewatering. Fractures or porosity in
the shale must be determined and taken into consideration in the retort
development plan. A sequence of retort construction and operation must
be designed to allow use of mine adits and drifts for shale transport and
recycle gas flow under conditions of complete mine safety. These are
just a few examples of the difference between a successful field test of
one retort and a commercial development that could require the integrated
operation of thousands of retorts over the life of a venture. (Figure 3
illustrates this procedure with successive in situ retorts at la, Ib, and Ic.)
Table 3 and Figure 3 characterize possible atmospheric emission
streams from an in situ retorting plant. The major stream consists of
a large quantity of off-gas that must be disposed of by venting to the
atmosphere during retort operation. The retort off-gas composition will
vary somewhat in accordance with several retorting parameters but will
o
probably contain about 1.8 MJ/m (50 Btu/scf) of combustible hydrocarbons
and carbon monoxide as well as some sulfur compounds. The heating value
of this gas may be sufficient to allow recovery of some energy by burning
the gas in a turbine or steam generating system. In any event, the
19
-------
200m
NOTE: STACK NUMBERS REFER TO TABLE 3
NOT TO SCALE
FIGURE 3 IN SITU PLANT CONFIGURATION
20
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carbon monoxide and hydrocarbons will -be removed before venting and the
sulfur compounds converted to sulfur dioxide. It is estimated that a
o
16,000 m /day (100,000 barrels per day) in situ operation would produce
1300 m3/sec (2,670,000 ACFM) of effluent gas from an incinerator at a
temperature of 95°C (200°F). This effluent stream would contain about
440 kg/hr (16 Ib/min) of hydrocarbons and about 4400 kg/hr (160 Ib/min)
of sulfur dioxide. This is roughly equivalent to the quantity of stack
gas emitted from a 1000 MW oil-fired electric generating plant, burning
o
5500 m (35,000 barrels) per day of 1 percent sulfur residual fuel oil.
Another class of important environmental questions center around the
large quantities of burned shale that will be left underground indefinitely,
Shale ash disposal will probably not be as great a program for in situ
operations as it will be for surface retorting. The major problem in both
cases will be to prevent soluble minerals from entering the ground water
or the Colorado River.
REFERENCES
Atlantic Richfield Company, "An Environmental Impact Analysis for
a Shale Oil Complex at Parachute Creek, Colorado," Vol. I, Part I,
Colony Development Operation (1974).
A. E. Harak, A. Long Jr., and H. C. Carpenter, "Preliminary Design
and Operation of a 150-Ton Oil Shale Retort," Quarterly of the
Colorado School of Mines, Vol. 65, No. 4 (October 1970).
R. D. Ridley, "in Situ Processing of Oil Shale," Quarterly of the
Colorado School of Mines, Vol. 69, No. 2 (April 1974).
"The Economics of Commercial Shale Oil Production by the TOSCO II
Process," by R. N. Hall and L. H. Yardumian, The 61st meeting of the
American Institute of Chemical Engineers, Los Angeles, California
(1968).
22
-------
V PLANS AND PROJECTIONS FOR OIL SHALE DEVELOPMENT
The oil shale industry has been "just about to emerge" for the past
25 years. Predictions concerning the first commercial plant were made
more than fifty years ago. However, the discovery of the vast East Texas
oil fields in the early 1930s pushed shale out of the picture until recent
Middle East problems brought it back to economic viability.
Even at present, not all of the economic and social forces in the
United States can be said to be converging in favor of the development
of a shale oil industry. In opposition to the high cost of petroleum
and the desire for U.S. independence from foreign crude oil are the re-
quirements for a nonpolluting shale industry, for little or no disturbance
to the land containing the shale, and for competitive uses for the re-
quired water. The above factors, in addition to the fact that 80 percent
of the shale reserves are publicly owned and subject to the ebb and flow
of the political process, clearly make prediction of industry growth
patterns hazardous.
Nevertheless, there is a considerable momentum built up in favor of
the development of a shale industry; about 400 million dollars are now
committed to that development. The forces for shale oil are stronger
than the forces against shale oil. The question which cannot be answered
at this time is: Can the theoretical techniques devised to create a non-
polluting shale industry be realized, in actual practice? If they can
be realized, or suitable new solutions found, then there will be a long-
term shale industry. If suitable solutions to the air and water problems
cannot be found, then the American people will have to decide how they
wish to proceed.
23
-------
The present situation can be described by placing the economic groups
who have a stake in the shale industry into two categories: (1) those
corporations that have large amounts of money invested in shale and will
lose much if they do not move quickly, and (2) those corporations that
have acquired shale reserves over the years and can afford to wait. These
are rather loose definitions and there are corporations who fit both
categories at the same time. The important difference is that the first
category has made a corporate decision to enter the shale industry.
The corporations in the first category are listed in Table 4. Also
listed are six locations in Colorado and Utah where the probable first
generation of shale oil ventures will be placed. The geographic locations
are shown on the map in Figure 4. Tracts U-a and U-b are shown as one
location since they are adjacent and will probably be developed jointly.
Table 4
SHALE OIL PLANT LOCATIONS AND TYPES
Location, as
Shown in
Figure 3
Probable Estimated
Probable Plant Size Completion
Group
Retort (m 3/day):
Date
C-a
C-b
U-a
U-b
Colony
Union
Superior
Amoco-Gulf
ARCO-Ashland -Shell -TOSCO
Phillips-Sun I
Phillips-Sun-Sohio I
ARCO-Ashland -Shell -TOSCO
Union Oil of California
Superior Oil
TOSCO II
TOSCO II
Paraho
TOSCO II
TOSCO II
Union-SGR
Not known
16,000
16,000
16,000
8,000
16,000
8,000
1981
1982
1983
1979 +
1981
1982
* 3
16,000 m /day is a 100,000 barrel-per-day plant.
In October 1974 Colony announced that the construction of this plant
would be postponed indefinitely, thereby making the completion date
later than 1979.
24
-------
IDAHO
UTAH
WASHAKIE
. BASIN .
,.. . UNIT* BASIN.
SUPERIOR
PICEANCE
REEK BASIN
AREA OF OIL SHALE DEPOSITS
AREA OF NAHCOLITE OR
TRONA DEPOSITS
Grand JuMtton ***"*> MESA
AREA OF O.I m /tonnt OR RICHER
OIL SHALE 3m OR MORE THICK
COLORADO
30 100
SCALE IN KILOMETERS
2OO
FIGURE 4 MAP OF OIL SHALE PLANT LOCATIONS
25
-------
The second category of potential participants in a shale industry
includes those corporations that own adequate shale reserves to support
at least 8,000 m3/day (50,000 barrels per day) of oil production, but have
not announced any plans to develop the reserves. This group could enter
the industry; and some of them might, if the overall economic conditions
for shale development were made more favorable. This group includes:'
Cities Service, Exxon, Getty Oil Corp., Mobil Oil Corp., and Standard
Oil of California.
A third category of companies can be defined as those companies who
own low quality shale reserves on reserves that would require a large
amount of 'blocking up' in order to obtain a compact mining plan.
A fourth category would include companies who have no shale reserves,
but are developing processes that could be the basis of a joint venture.
Occidental Petroleum and the Geokinetics group are in this category.
Both have indicated a willingness to enter the shale industry by their
unsuccessful bids on the federal sh'ale leases. Such groups may also
obtain shale reserves from Utah state lands at some future date.
From a historical point of view, the. U.S. Bureau of Mines has long
advocated an orderly growth of a domestic shale oil industry and has
promoted this concept by supporting research and by the leasing program.
The federal leasing program was originally conceived with this orderly
growth in mind and is progressing along this course. More recently,
however, programs for accelerated oil shale development have been suggested
"Blocking up" occurs when an owner has a sufficient quantity of shale
reserves, i.e., about 2,000 hectares (5,000 acres), but in land too
widely dispersed to design an efficient mining plan. Such an owner
hopes to exchange some remote land for federal land of equal value
close to his principal holding. Superior Oil Co. is trying to do this
for its land. Exxon would probably try to block up its holdings before
putting up a plant.
26
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as part of Project Independence. Early in the project very rapid oil
shale development was contemplated. The original concept1 of complete
independence from foreign oil supplies by 1980 has been abandoned as
impossible—a more realistic goal combining a reduced growth rate for
U.S. energy consumption and a longer transition period is now advocated.2
Table 5 presents the three cases: (1) National Petroleum Council (NPC)
prediction made in 1970,3 (2) original Project Independence1 and, (3)
revised Project Independence,2 as each relate to the growth of an oil
shale industry. The required capital costs for the industry are also
shown.
SRI predicts that the growth of a shale industry will be much closer
to the 1970 NPC prediction than to the revised 1974 Independence numbers,
up to 1985. The announced shale plants, as shown in Table 4, indicate a
production rate of about 80,000 m3/day (500,000 barrels per day) by 1984,
allowing one year for a plant to reach full production. In addition to
this amount of production from conventional mining and retorting, between
16,000 and 32,000 m3/day (100,000 and 200,000 barrels per day) in situ
production could be obtained by 1984. This total production of 80,000-
112,000 m3/day (500,000-700,000 barrels per day) represents the first
generation shale industry.
Growth beyond the first generation will depend upon several factors
that are not presently known. These are listed:
• The salinity of the Colorado River as a result of
increased use of the pure upper source water, spent shale
runoff, and saline water percolation.
• The cost of crude petroleum in the United States and on
the world markets.
• The economic and social costs of shale oil production as
perceived by the voters of the United States.
*
References are listed at end of section.
27
-------
Table 5
REQUIRED OIL SHALE INDUSTRY GROWTH RATES
TO MEET SELECTED GOALS
1970 1973 1974
NPC Original Revised
Year Task Force* Independence! Independence^
Shale oil production
Thousands of m3/day§
Total capital expendi- 1975
tures required for oil
production**
*
Reference 3.
Reference 1.
Reference 2.
1975
1980
1983
1985
1975
1980
1983
1985
0
100
200
400
400
1,500
3,400
6,400
0
500
1,500
400
6,000
22,000
0
500
400
8,000
p
16,000 m3/day is equivalent to 100,000 barrels per day.
**
Millions of dollars, assuming 6% per year cost escalation.
If all of the above factors are positive in the sense that they will not
limit the growth of the shale industry, the industry should continue to
grow at a rate of 32,000 m3/day (200,000 barrels per day) p>er year until
limited by the available water supply. Thus, growth would level off at
about 240,000 m3/day (1,500,000 barrels per day) production by 1990. Be-
yond 1990, an average of 16,000 m3/day (100,000 barrels per day) of new
plant construction will be required each year to replace old facilities.
The physical characteristics of this predicted development (for the
revised Project Independence) are discussed in U.S. Energy Prospects:
An Engineering Viewpoint" (Chapter 6).2 Among the major efforts are:
28
-------
• Bringing into production 250 million tonnes per year of
shale mines.
• Laying, stabilizing, and restoring 17 square kilometers
(5 square miles) of shale ash 13 m (40 feet) deep each
year.
• Developing and conveying 100 million cubic meters
(80,000 acre-feet) per year of new water supplies.
REFERENCES
1. "The Nation's Energy Future," submitted to the President by Dixy
Lee Ray, Chairman, U.S. Atomic Energy Commission (December 1973).
2. "U.S. Energy Prospects: An Engineering Viewpoint," Task Force on
Energy, National Academy of Engineering, Washington, D.C.,
Chapter 6 (1974) .
3. "An Initial Appraisal by the Oil Shale Task Group—1971-1985,"
National Petroleum Council, Washington, D.C., p. 117 (1972).
29
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-------
VI ENVIRONMENTAL EFFECTS OF OIL SHALE DEVELOPMENT
Discussion of the environmental effects of oil shale development
tends to be controversial and could become especially significant. The
controversy is strongest in Colorado, the region of the most promising
oil shale resources, and is most concentrated in Denver, which is the
center of both general population and that special segment of popula-
tion of Federal, State, corporate, and environmentalist personalities
involved in the controversy. The special significance of this discussion
is its role in making the first assessment of environmental impacts of an
industry before the industry exists as a commercial operation.
The environmental impacts themselves are unusually significant due
to the physical and chemical properties of the oil shale. Oil shale is
an alkaline rock containing a relatively small hydrocarbon fraction, the
10 to 15 percent by weight which is the kerogen that can be converted to
a fuel. After extraction of the fuel, the vast majority of the mass of
the shale remains as a waste material. This waste, known as spent shale,
of crushed and retorted rock contains minerals that can be dissolved
easily by rain or snowmelt and is therefore a potential source of increased
salinity in the Colorado River.
Political issues in this case are tied directly to environmental im-
pacts. The quantity and quality of water in the Colorado River have been
the subjects of a number of political and legal arguments. The salinity
of the Colorado has been the subject of a recent agreement between the
United States and Mexico, thus bringing international political overtones
into the environmental impact assessment of oil shale development. Some
details are given below in the discussion of water quality.
31
-------
This section of the report contains a summary of the environmental
effects of oil shale development under the headings of land, air, water,
and aesthetics. Two precautions should be stated here, before the specific
summaries:
(1) The extent to which the different kinds of environmental
impacts can be adequately quantified varies a good deal.
Because this report is directed toward the air pollution
and control aspects of the oil shale industry, most of
the effort at quantification has been made in that area.
These findings are presented in greater detail in subse-
quent sections of the report. In this section, quantita-
tive estimates are made for land, water, and air impacts.
Aesthetic impacts tend to defy quantification and no
attempt is made here to quantify them.
(2) The actual environmental impacts of oil shale development
will be determined by the type of processing that finally
passes the economic and regulatory requirements. The
form of technology that will prove satisfactory in these
respects is not yet determined. Perhaps the most signif-
icant example of this uncertainty is the technology for
in situ processing of oil shale. This technology is under
active study and development. Its use would signifi-
cantly change the environmental impacts. Water use, for
example, will be considerably less with in situ processing.
A. Land Impacts
The amount of rock that must be excavated in order to yield one cubic
meter of shale oil is staggering. Oil shale of 0.125 m3/tonne (30 gal/ton)
Q
will require the mining of 3.8 m oil shale per cubic meter of oil produced.
This much shale will yield 5.2 m3 of spent shale; the volume increases
after crushing and retorting.
*
The land disturbance due to the mine, surface facilities, and
disposal area has been estimated by three sources. The ARCO source
estimates a disturbance of 12.1-12.3 ha per 106 cubic meters of oil
produced.1* The Department of the Interior predicts 12.6-13.7 ha per
million cubic meters of oil.3 SRI has previously estimated the disturbance
32
-------
to be 12.5 ha per million cubic meters of oil.3 The area most likely to
2
be developed in the next 25 years will be about 2,100 km in Colorado
in the Piceance Creek Basin and up to 1,000 km2 in the east side of Uinta
Basin of Utah. The land disturbed will range from 2-8 percent of the
total of about 3,000 km2 of good shale reserve land depending on the
processing method used.3 The production of about 2 x 10^ m3 (12 billion
barrels) of oil would be associated with this land disturbance, assuming
8 percent of 3,000(km)2 and-12.5 ha per 106 m3.
B. Water Impacts
1. Water Use
It is generally believed that available water will limit the
ultimate size of an oil shale industry. All good western shale is in
the upper Colorado River drainage system, the only replenishable source
of water. There is ground water in the shale area, some of it fresh and
some containing up to 60,000 ppm dissolved minerals. At present it is
estimated that 2.2 X 10 cubic meters (180,000 acre feet) per year of
Colorado river water could be made available for shale development. This
quantity of river water, plus the use of ground water at the mine sites,
would allow an overall industry size ranging from 2.4 X 10 to 4 \ 10
cubic meters (1.5 to 2.5 million barrels) per day of shale oil.
The water used per unit of net product will depend upon the
type of mining, retorting, and upgrading used. In situ methods are ex-
pected to require less water than conventional mining and retorting.
Table 6 contains a list of estimated water use per cubic meter of shale
oil produced. The values range from two to almost six cubic meters of
water per cubic meter of shale oil.
*
References are listed at end of section.
33
-------
Table 6
ESTIMATES OF WATER USE IN OIL SHALE PRODUCTION
(m3 of water per m3 of oil produced)
Impact
Impact
Quantity
(ra3/m3)
Ref-erence
Impact
Quantity
(m3/m3)
Underground 4.1
Mine Water
Use
Surface Mine 4.0
Water Use
In Situ 2.1
Water Use
Colorado River Water
Conservation District
Department of the
Interior
Cameron and Jones
Denver Research
Institute
ARCO
Colorado Water
Conservation Board
3.6"
2.70-4.27
(underground)
2.894
3.234
3.90
4.45*-5.57
Sources: "Control of Environmental Impacts From Advanced Energy
Sources," E. E. Hughes, E. M. Dickson, and R. A. Schmidt,
SRI, Menlo Park, California, p. 34 (1974).
3Roland C. Fisher, "Colorado Oil Shale and Water,"
Quarterly of the Colorado School of Mines, Vol. 69,
No. 2, pp. 135-6.
3Department of Interior, Final Environment Statement for
the Prototype Oil Shale Leasing Program, Vol Iy(1973).
4Felix C. Sparks, "Water Prospects for the Emerging Oil
Shale Industry," Quarterly of the Colorado School of
Mines, Vol. 69, No. 2 (April 1974).
ARCO, "An Environmental Impact Analysis for a Shale Oil
Complex at Parachute Creek, Colorado," Vol. I, Colony
Development Operation (1974).
34
-------
2. Water Quality
Current plans call for no effluent from the oil shale plant
into surface water. Process water will be piped into the disposal area
for wetting of the spent shale pile. Runoff from the pile will be held
in a catchment dam below the disposal area. The amount of water piped
from the Colorado River will not be returned. It is estimated that this
consumptive use of water will increase the salinity of the Colorado River
,at Hoover Dam by 0.2 mg/1. By 1981, with a projected 40,000 m3/day
(250,000 B/D) industry, this will have caused a salinity increase of 1.0 mg/1,
Secondary water quality impacts which are not readily predicted
or measured may be more significant. The Mahogany Zone, which will be
the first oil shale layer to be mined, is the barrier or "lid" to the
main aquifer in the area called the leached zone. Mining in this zone
will encourage greater seepage of brackish water from this aquifer through
the Mahogany Zone into the surface waters of the area. Mines to be lo-
cated at the center of the basin, such as tracts C-a and C-b, will have to
q
be dewatered at rates of at least 50 m /hr. In this area, about 70 per-
cent of the water will be of poor quality. This poor quality water will
average about 25,000 mg/1 in dissolved solids, contain mostly sodium and
bicarbonate ions, and have chloride concentrations of 500-2,500 mg/1,
according to a USGS source. This water may not be recycled back to the
plant for use and must be diverted onto the disposal pi'le, reinjected
into lower aquifers, evaporated, or transported to nearby oil shale
operations which need water for disposal and dust control.
The Treaty of 1944 assured Mexico of 1.9 x 109 m3 (1,500,000 acre-
feet) annually of irrigation water from the Colorado River. The river has
become increasingly saline over the years due to dissolving of rock and
the vast irrigation runoff from the southwestern United States. Two
revisions have been made to the treaty, one in 1972 and the other in
August 1974. The last revision calls for a maximum 115 ppm increase in
35
-------
total dissolved solids between Imperial Dam and Morelos Dam. Since
the maximum advisable salinity at Imperial Dam is 1,000 ppm, the United
States may not deliver to Mexico any water more saline than 1,115 ppm,
TDS. In order to accomplish this, a plant will be built upstream from
Morelos Dam to desalinate the Wellton-Mohawk drainage flow which is
the main contributor of salinity in the lower part of the river. This
drainage flow averages 8.6 m /sec (220,000 acre-feet/year) with a salinity
of 3,700 ppm.
C. Air Impacts
Industrialization of the Western shale regions will result in a
decline of the general air quality. The main sources of air pollution
will be vehicular emissions from mining, construction, and transporting
equipment; dust from shale-handling operations; and gases from retorting
and refining units. Other sources of air degradation will be the in-
creased vehicular traffic, residential heating caused by an increase in
population in the area, and emissions from the mine-blasting procedures.
The estimated emissions for an oil shale plant are given in Table 7. The
first two columns show the numbers listed in the previous EPA report.
The third column lists the figures derived from an ARCO primary reference.
The fourth column shows the ARCO emissions as listed in a secondary source
based on ARCO's data. In the fifth column are listed the emissions pre-
dicted by the Department of the Interior. The more recent numbers listed
in the third and fourth columns show a ten times increase in NO emis-
x
sions. This is because the older estimates were based on the use of
natural gas or clean fuel in the retorting operation. Now the estimates
are based on the use of shale oil, which has greater nitrogen content.
36
-------
Table 7
ESTIMATES OF AIR POLLUTANT EMISSION
FACTORS IN OIL SHALE PRODUCTION
2
Emission Factor in kg per m of Oil Product
Table 163
(uncontrolled
Pollutant Table II1 Class IV)
SO 2 11 22.6
NOX 0.68 0.755
Particulates 0.054 1.13
H S — 11.3
Department
of
Tosco II3 Tosco II4 Interior5
2.25 1.91 2.62-3.88
7.45 11.1 0.456-0.685
1.46 1.43 2.52
.. _
Sources:
i",
Control of Environmental Impacts from Advanced Energy
Sources," E. Hughes, E. Dickson, R. Schmidt, SRI, Menlo
Park, California, Table 11 (1974).
2 ibid., Table 16.
SRI calculations based on "An Environmental Impact Analysis
for a Shale Oil Complex at Parachute Creek, Colorado,"
Vol. I, Colony Development Operation (1974).
A
SRI estimate from other sources.
Cited in "Environmental Considerations in Energy Develop-
ment," Appendix D, Battelle Memorial Institute (1973).
D. Aesthetic Impacts
The spectrum of changes caused by the development of a new industry
ranges from those that are easily quantified, such as size of mine tailing
area, to effects that are purely subjective, such as increased monotony
of landscape. For convenience, all environmental changes that contain a
high proportion of subjective evaluation are placed in the aesthetic
37
-------
category. This category includes changes in land use, plant growth,
wildlife, recreational facilities, and cultural and scenic values.
The shale areas have a low population density, on the order of one
person per square kilometer (three per square mile) less than half of
whom live in towns. The population doubles during the few weeks of the
deer-hunting season. Advanced planning of mine and process facility
locations would allow the preservation of the few historic Indian culture
ruins in the area. The quantity of shale residue accumulating in surface
disposal areas will eventually create large plateau areas in a region
that consists of rounded hills and deeply cut canyons.
Mining, transportation, and processing operations will produce
noises similar to those now being experienced in other related industries.
In addition to the usual human discomfort and loss of working efficiency,
industrial noises will adversely affect the wildlife in the immediate
area. For the most part, noise control methods developed for other in-
dustrial and transportation equipment will be satisfactory for the shale
industry. There may be instances where long conveyor systems used between
processing units create enough noise to prevent normal wildlife migration
paths from being used, even though there is no physical barrier.
REFERENCES
1. Atlantic Richfield Company, "An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado," Vol. I, Part I,
Colony Development Operation (1974).
2. Department of the Interior, Final Environment Statement for the
Prototype Oil Shale Leasing Program, Vol. I (1973).
3. R. G. Murray, "Energy from Oil Shale," EPA-600/2-74-002, SRI Project
No. 2714, Stanford Research Institute, Menlo Park, California
(March 1974).
38
-------
4. Department of the Interior, Final Environmental Statement for the
Prototype Oil Shale Leasing Program, Vol. Ill (1973).
5. USGS, Geoh'ydrology of the Piceance Creek Structural Basin Between
the White and Colorado Rivers, NW Colorado, Hydrologic Investiga-
tions Atlas HA-370 (1971).
6. Private communication with Mr. Robert Smith, Colony Development
Operation.
39
-------
-------
VII AIR POLLUTION: EMISSIONS AND AMBIENT AIR QUALITY
A. Background
Concern over possible environmental degradation has been engendered
by the proposed construction of new oil shale processing facilities in
the oil shale regions of Colorado and Utah. Federal and State laws
require review of the environmental impact of proposed sources of air
pollution in view of current air quality standards. If an impact assess-
ment reveals that pollution levels resulting from a new facility will
exceed the standards, adequate control measures must be proposed before
a building permit will be issued. Since the impact assessment is required
during the planning stages of plant development, a rational methodology
must be devised that will utilize appropriate emission and meteorological
data in the prediction of pollutant .concentrations. Simulation modeling
provides the necessary link between the collections of meteorological
and emission data and the picture of air quality that is required for
successful evaluation of control measures; Modeling permits assessment
of the ramifications of projected growth patterns and emission control
procedures.
Somewhat limited studies of the environmental impact of proposed oil
shale recovery schemes have been conducted. One such study was performed
by Engineering Science, Incorporated (ESI) and described in the Department
1*
of Interior s Final Environmental Statement on oil shale. ESI used the
emission estimates then available, various meteorological data, and a
number of assumptions as to stack characteristics and locations in a
*
References are given at the end of this section.
41
-------
mathematical model to predict air quality levels resulting from an oil
shale facility.*
B. Model Description
The model used in the present study for calculation of concentra-
tions from oil shale plants is the Climatological Dispersion Model (CDM),
2
which is a revised form of a model first proposed by-Martin and Tikyart.
3
The CDM has been described in detail by Calder.
The computerized CDM permits calculation of long-period seasonal or
annual average pollutant concentration patterns resulting from stationary
point sources and area sources. The fundamental physical assumption of
the model is that the steady-state spatial distribution of concentration
from a continuously emitting point source is given by the Gaussian plume
formula. It is assumed that meteorological conditions over short periods
of time (of the order of an hour) can be regarded as steady-state, and
that these conditions can be approximated with a constant and spatially
uniform wind speed and with a unique horizontal mean wind direction for
the entire area.
The Gaussian plume formulae are used when there are no restrictions
on diffusion in the vertical direction. When vertical diffusion is
restricted to a finite mixing depth, a uniform vertical concentration
distribution is assumed at greater downwind distances.
*
Note added in review: Subsequent to the Department of Interior's
environmental statement, ESI has extended its work by contributing an
air quality analysis to the Federal Energy Administration's Oil Shale
Task Force for the Project Independence Blueprint, published at the
end of 1974.
42
-------
Equations for the long-term average concentrations due to point and
area sources are weighted according to a frequency function to account
for the variability of meteorological conditions. These empirical
functions express the observed joint frequency of occurrence of various
classes of wind direction, wind speed, and stability. Integration of
the formulae over the area and point sources will describe the concen-
tration that would be observed at a selected location for a certain set
of meteorological conditions. These concentrations, taken together with
the frequency of occurrence of each combination of conditions, produce
the required climatologically averaged spatial distribution of concentra-
tion.
The CDM program formulation used in this study assumes that the land
at the plant site and in the surrounding area is--essentially flat. The
influences of complex terrain have not yet been incorporated into dis-
persion models currently in use.
*
C. Topography of the Oil Shale Region
The principal oil shale deposits considered in this study are
located in the Piceance Creek Basin in Colorado and the Uinta Basin in
Utah.
The Colorado Counties of Rio Blanco, Garfield, and Mesa encompass
the Piceance Creek Basin. The major oil shale area of the Basin lies
on the Roan Plateau, bounded by steep escarpments in all directions.
The land surface of the region has been shaped by erosion into valleys
and ridges oriented in the north and north-easterly directions. The
*
The information contained in this section was extracted from the Final
Environmental Statement for the Prototype Oil-Shale Leasing Program,
Vol. I, Regional Impacts of Oil Shale Development, U.S. Department of
the Interior (1973). This is Reference 1 in the list at the end of
this section.
43
-------
difference in elevation from ridge to valley floor ranges from 62 to 185 m
(200 to 600 feet), and for the most part the valleys are narrow and steep
sided. The northern part of the oil shale area is drained by tributaries
of the White River, while the Colorado River drains the southern part of
the oil shale region. Land elevations above mean sea level (MSL) range
from about 1600 m (5250 ft.) near the White River to about 2800 m (9000 ft.)
on southern ridge crests.
Utah's Uinta Basin is a depression bounded by the Uinta and Wasatch
Mountains, the Roan Cliffs and the cliffs west of the Douglas Creek Arch.
Land features include rough mountains and flat valleys, with deep gulleys
and rock capped ridges. The White and Green Rivers drain the area.
Elevations range from 1400 m (4600 ft.) to more than 2500 m (8000 ft.) MSL.
In general, the oil shale regions of Colorado and Utah contain many
steep-sided valleys that are unsuitable locations for plant sites. In
the past, serious air pollution episodes have occurred in such valley
locations as the Meuse Valley, Belgium in 1930 and at Donora, Pennsylvania,
in 1948. These episodes were a result of restriction by valley walls of
4
mixing of pollutants into the atmosphere. Conclusions from a study
conducted by Battelle, Pacific Northwest Laboratories indicate that oil
shale processing facilities should be located on plateau, rather than
valley, sites to minimize pollution potential. Concentrations in a
valley resulting from a plateau plant site were found to be at least
an order of magnitude lower than the concentrations that would result
from a valley plant site. Therefore, in view of compelling supportive
evidence for the necessity of such location, the diffusion modeling per-
formed in the present study was conducted under the assumption that the
oil shale plants will be located on plateau sites.
44
-------
D. Meteorology of the Oil Shale Region
The Climatological Dispersion Model used to simulate the pollutant
pattern resulting from operation of an oil shale facility was formulated
assuming flat terrain in the modeling area. If an oil shale plant is
located in a narrow valley, the CDM will under-predict pollutant con-
centrations; However, if the facility is located in a plateau or in
a broad valley, as previous studies have strongly recommended and which
has been assumed for the modeling, the dispersion model will adequately
predict concentration patterns. The wind regimes of plateaus and broad
valleys in the oil shale region are undoubtedly influenced by surround-
ing terrain, but the influence is not of sufficient magnitude, as is that
of steep-sided valleys, to justify modification of the CDM to account for
it.
Figures 5 and 6 are illustrations of the influence of topography
on wind direction and speed. The data used in these figures were taken
5
from a report prepared by Dames & Moore for the Colony Development
Operation and from Grand Junction, Colorado, weather records. Stations
1, 2, and 5 are weather stations that were established in the oil shale
area of Colorado to collect data for the above study. Station 1 was
located at the confluence of the Middle Fork and the East Middle Fork
of Parachute Creek at an elevation of 1850 m (6025 ft.) MSL. Station 2
was part way up the valley side of the Middle Fork of Parachute Creek at
an elevation of 1930 m (6270 ft.) MSL. Station 5 was located on top of
the Mesa above the Middle Fork of Parachute Creek. The annual frequency
distributions of wind direction for each station and for Grand Junction
are shown in Figure 5. Since the class intervals of wind direction
reported for the experimental stations differ from the class intervals
reported for Grand Junction, the percent frequency of occurrence per
degree of class interval has been used in the figure. This normalizes
45
-------
1.2
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NOTE: 9.3% OF OBSERVATIONS SHOWED CALM
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46
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(9
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Ul
0.
kl
U
NOTE: 1.2% OF OBSERVATIONS SHOWED
CALM WINDS WHICH ARE NOT
INCLUDED IN HISTOSMAM
005 035 065 095
155
DEGREES FROM NORTH
u
g
g
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DEGREES FROM NORTH
FIOWU 5 (Concluded)
47
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cr
U
Q.
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tr
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30
20
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STATION
40 r
STATION
NOTE: 0.4% OF OBSERVATIONS SHOWED
WIND SPEEDS >»m/«»c
0
SPEED-m/nc
FIGURE 6 ANNUAL FRBQUENCY DISTRIBUTIONS OF WIND
SPEED AT FOUR COLORADO SITES
48
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E
K
u
a.
UJ
U
9 m/!*c
K^
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SPEED - m/MC
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NOTE: 0.6% OF OBSERVATIONS SHOWED
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45
SPEED-
10
PIOVM • (Concluded)
49
-------
the data so that the vertical scales are comparable. The histograms were
drawn so that the class interval with the greatest frequency appears on
the left and subsequent class intervals are taken clockwise from it.
This was done so that the bimodal nature of the'wind direction distribu-
tion would be most apparent for comparison purposes. Stations 1 and 2
show strong channeling of the wind by the valleys, with the orientation
of the maxima reflecting the orientation of the valley. Station 5,
located on the plateau, and Grand Junction, located in a broad valley,
have less pronounced maxima and their patterns are rotated 180° from
those of Stations 1 and 2. It is evident from examination of Figure 5
that the variability of wind direction from station to station in the
oil shale area is at least as great as the variability between Grand
Junction and any station. Grand Junction data best approximates the
wind direction distribution of the mesa site, and the differences between
the two distributions are no greater than those between other sites suit-
able for oil shale processing facilities.
Figure 6 illustrates the wind speed frequency distributions for
the sume locutions cited above. Here the frequencies luwe been plotted
in percent per unit of speed, since lht> speed class intervals differed
for the two data sets. The valley stations show greater frequencies
of oct:urreiice in the low wind spi-t-d classes than do Grand Junction and
the mesa station. Grand Junction has'somewhat more occasions of the
higher wind speed classes Hum Station 5. However, it should be noted
that tlie frequency distributions of Stations 1, 2, and 5 wei'c based on
only 14 months of d;ita, while Grand Junction distributions were based
on I i vi yc-urs of da tu .
Sufficient me-U-orological data for application of the CDM is not
available- for sites within the oil shal< region. Atmospheric stability
seldom varies abruptly within a geographic area, so the use of the
50
-------
stability at Grand Junction is a good approximation. In view of the
previous discussion and since specific sites for the processing facili-
ties and the associated meteorology have not been supplied, the use of
Grand Junction meteorology is justified for obtaining order of magnitude
estimates of pollutant concentrations. A similar argument can be made
for the applicability of Salt Lake City, Utah, data. In order to pro-
duce detailed pollutant patterns for an oil shale development, specific
meteorological and stack data for a proposed site must be used.
E. Dispersion Modeling
1. Cases Adopted
The CDM has been used to predict air pollutant concentrations
3
resulting from 16,000 m /day (100,000 barrel per day) plants using two
different retort processes, the TOSCO II process and an in-situ process.
Concentrations of particulates, SO , HC and NO were calculated over the
^ x
same averaging periods as those for which air quality standards exist.
These periods include annual averages for particulates, SO and NO ;
2 x
24-hour averages for particulates and SO ; and a 3-hour average for HC.
£»
Annual averages were calculated from frequency distributions
of meteorological conditions observed at Grand Junction, Colorado, and
Salt Lake City, Utah. These distributions are the output of the National
*
Climatic Center's STAR computer program. Twenty-four hour averages and
3-hour averages were calculated using the assumption that worst-case
*
U.S. Department of Commerce
National Oceanic and Atmospheric Administration
Environmental Data Service
National Climatic Center
Federal Building
Asheville, N.C. 28801
51
-------
meteorological conditions prevailed. Statistical weather records indicate
that neutral atmospheric stability and a light wind of 1.5 m sec occur
for 24 hours or longer in the oil shale region an average of 15 days per
year. These conditions have been shown to be representative of worst-
case conditions in the oil shale region and do not involve use of Grand
Junction or Salt Lake City meteorological data. The CDM was used to
compute the 24-hour and 3-hour averages, for various wind directions,
assuming 100 percent frequency of occurrence of neutral stability and
1.5 m sec winds. Stack configurations were assumed on the basis of
the best available information. Radical changes in the assumed con-
figurations (see Figures 2 and 3 in Section IV) could result in con-
centrations somewhat different than those presented here.
2. Results for TOSCO II Retorting
Figure 2 (in Section IV) illustrates the configuration of
3
stack locations that have been assumed for a 16,000 m /day (100,000
barrel per day) TOSCO II plant. Table 8 gives the stack characteristics
and emission rates used in model calculations. Isopleths of concentra-
tions for various pollutants and averaging times are shown in Figures 7-
18. Tables 9 and 10 summarize model results for the TOSCO II process and
give background concentrations, air quality standards, and the level of
control required to meet each standard. Background concentrations were
6
taken from the results of monitoring conducted in the Colorado oil shale
region by Colony Development Operation. When computing the required
level of control, background concentrations and concentrations resulting
from oil shale operations have been considered together for the federal
primary and secondary standards and for the Colorado standards. This
has been done by subtracting the background concentration from the stan-
dard and then computing the level of control needed so that the concen-
trations resulting from oil shale facilities do not exceed the remaining
52
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20
i I I l l I i I I 1 I I I I l I I T
15
E
o
10
BACKGROUND. < 15 ^g/m3
fi^fc» PLANT
larff REMOTE STACK
16,000 m3/day PLANT WITH EMISSIONS CONTROLLED
STANDARDS
FEDERAL PRIMARY 75
FEDERAL SECONDARY 60
COLORADO 45
CLASS n 10
CLASS I 5
I l l i i i
10
DISTANCE- kilometers
15
20
FIGURE 7 ANNUAL AVERAGE PARTICULATE CONCENTRATION
FOR A TOSCO D OIL SHALE PLANT USING GRAND JUNCTION,
COLORADO METEOROLOGY
54
-------
20
15
UJ
u
-2.
10
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N
\
BACKGROUND. < 15
PLANT
REMOTE STACK
16,000 m mVday PLANT WITH
EMISSIONS CONTROLLED
STANDARDS ( ^g/m )
FEDERAL PRIMARY 75
FEDERAL SECONDARY 60
COLORADO 45
CLASS n 10
CLASS I 5
10
DISTANCE - kilometers
15
20
FIGURE 8 ANNUAL AVERAGE PARTICULATE CONCENTRATION Ug/m3)
FOR A TOSCO n OIL SHALE PLANT USING SALT LAKE CITY,
UTAH METEOROLOGY
55
-------
UJ
o
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Q
13
12
10
N
,200
150
100
BACKGROUND:
PLANT
15
E33
REMOTE STACK
STANDARDS
FEDERAL PRIMARY 260
FEDERAL SECONDARY 150
CLASS H 30
CLASS I 10
16,000 mVday PLANT WITH
EMISSIONS CONTROLLED
9 10 II
DISTANCE - kilometers
12
13
14
15
FIGURE 9 24-HOUR WORST CASE AVERAGE PARTICULATE CONCENTRATION
(/jg/m3) FOR A TOSCO n OIL SHALE PLANT UNDER CONDITIONS
OF NEUTRAL STABILITY AND A NORTH WIND OF 1.5msec'1
56
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I I I I I i I I I
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FEDERAL PRIMARY 80
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CLASS I 2
I I. I I I
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15
FIGURE II ANNUAL AVERAGE S02 CONCENTRATION (Mg/m3 ) FORA
TOSCO E OIL SHALE PLANT USING GRAND JUNCTION,
COLORADO METEOROLOGY
20
58
-------
ao
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15
20
FIGURE 12 ANNUAL AVERAGE S02 CONCENTRATION Ug /m3 ) FOR A TOSCO H OIL
SHALE PLANT USING SALT LAKE CITY, UTAH METEOROLOGY
59
-------
13
12
10
Ul
(U
ai
E 7
o
LjJ
? 6
STANDARDS (/tg/m3)
FEDERAL PRIMARY
CLASS H
CLASS I
365
100
15
BACKGROUND • 26 ^g/m3
PLANT
16,000 mVday PLANT WITH
EMISSIONS CONTROLLED
9 10 II
DISTANCE-kilometers
12
13
14
15
FIGURE 13 24-HOUR WORST CASE AVERAGE S02 CONCENTRATION (Mg/m3)
FOR A TOSCO E OIL SHALE PLANT UNDER CONDITIONS OF
NEUTRAL STABILITY AND A NORTH WIND OF 1.5 msec'1
60
-------
s
S "
o
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61
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13
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tn
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10 -
9 -
§ 7
6 -
2 -
STANLARD
FEDERAL PRIMARY ISO
PLANT
16,000 mVdoy PLANT WITH
EMISSIONS CONTROLLED
/V
10
DISTANCE- kilometers
15
FIGURE 15 3-HOUR WORST CASE AVERAGE HC CONCENTRATION (Mg/m3)
FOR A TOSCO H OIL SHALE PLANT UNDER CONDITIONS OF
NEUTRAL STABILITY AND A NORTH WIND OF 1.5 msec"1
62
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w
o
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63
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20
15
10
CO
Q
STANDARD
FEDERAL PRIMARY 100
PLANT
16,000 mVday PLANT WITH
EMISSIONS CONTROLLED
10
DISTANCE-kilometers
15
20
FIGURE 17 ANNUAL AVERAGE NOX CONCENTRATION ( Mg /m3) FOR A TOSCO Tl OIL
SHALE PLANT USING GRAND JUNCTION, COLORADO METEOROLOGY
64
-------
UJ
5
STANDARD ( /tg/m )
FEDERAL PRIMARY 100
16,000 m3 /day PLANT
EMISSIONS CONTROLLED
DISTANCE-kilometers
FIGURE 18 ANNUAL AVERAGE NOX CONCENTRATION (^g/m3) FOR A
TOSCO I OIL SHALE PLANT USING SALT LAKE CITY, UTAH
METEOROLOGY
65
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portion of the standard. When background concentrations equal or exceed
a standard, the level of control has been specified as 99+ percent. The
Federal Class I and Class II standards are the so-called "non-degradation"
standards; they refer to increases in concentrations and do not involve
background concentrations.
For particulates of the TOSCO II process, uncontrolled emissions
will produce concentrations that exceed all standards listed in Tables 9
and 10, except the federal primary and secondary air quality standards.
Background concentrations for particulates and SO were measured in the
£
Parachute Creek area of the Colorado oil shale region by the Colony
6
Development Operation and analyzed in a report by Dames & Moore. The
median of the 24-hour averages of background concentration of particulates
3
was found to be about 15 |ag/m . The average annual background concentra-
3
tion is expected to be less than 15 M-g/m . The combination of background
concentrations with plant-produced concentrations for those standards for
which this is applicable reveals the necessity for controls slightly in
excess of 35 percent in order to meet the federal primary 24-hour standard.
The Colorado annual standard requires 12 percent control. The federal
24-hour secondary standard can be met with approximately 64 percent control
of plant emissions. Approximately 97 percent control will be needed to
meet the Class I 24-hour standard and 85 percent will be needed to comply
with the Class I annual standard. The Class II 24-hour and annual stan-
dards require 92 percent and 71 percent controls, respectively.
Projected concentrations of SO do not exceed the federal
£
primary air quality standards nor the Class II 24-hour standards.
Dames & Moore found the 24-hour average background concentration of
3
SO to be 26 Hg/m . The annual average is expected to be less than
this amount. The addition of background concentrations to the calcu-
lated concentrations resulting from the plant is not sufficient to
68
-------
exceed the federal primary air quality standards. However, SO concen-
£
trations from the plant exceed the stringent Colorado annual air quality
standard, where 99+ percent control is required, since background concen-
trations alone may exceed the standard. The Federal Class I annual and
24-hour standards can be met with 89 percent and 71 percent control,
respectively. The Class II annual standard requires 72 percent control.
No controls are required for HC and NO , since the concentra-
x
tions of these pollutants are well below all applicable standards.
3. In-situ Process
Figure 3 (in Section IV) shows the stack configuration of
3
a 16,000 m /day (100,000 barrel per day) in situ plant. The incinerator
off gas release point shifts location from la to Ib to Ic during the
20-year life of the plant. Table 3 (in Section IV) lists the stack
characteristics and emission rates used in concentration computations.
The results of modeling the air quality levels of an in situ oil
shale plant are summarized in Tables 11 and 12 from production of 16,000 B/D
and 100,000 B/D respectively. Projected annual and 24-hour average partic-
ulate levels do not exceed federal primary and secondary standards nor
Colorado standards; therefore, no controls are required. The radical
reduction of particulate levels for the in situ process, as compared to the
TOSCO II process, can be attributed to the nature of subsurface retorting
techniques. However, the Class I annual standard requires 29 percent control
and the Class I 24-hour standard requires 76 percent control. The Class II
annual standard requires no control and the Class II 24-hour standard can
be met with 27 percent control.
Sulfur dioxide concentrations do not exceed the federal
primary annual and 24-hour standards, regardless of the location of
the incinerator. However, 99+ percent control is required to meet
Colorado annual standards due to background concentrations, 78 percent
69
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71
-------
control is needed to avoid violation of the Federal Class I annual standard
and 45 percent control is required -to meet the Class II annual standard.
No controls are required for maintenance of the Federal Class I and
Class II 24-hour standards. Concentrations of HC and NO from the
x
in situ plant are well below the federal and Colorado standards, regard-
less of the noted changes in plant configuration.
It should be stressed that a stack's diameter, temperature and
exit velocity have a great deal of influence on the concentrations result-
ing from the stack's emissions. A comparison of TOSCO II process and
in situ process emissions and concentrations exemplify this influence. An
inspection of Tables 2 and 3 (in Section IV) reveals that the total S02
emissions from the in situ plant are approximately three times the total SO
emissions from the TOSCO II plant, while the in situ concentrations are
one-third to one-half of the TOSCO II concentrations. It was found that
most of the in situ plant's SO emissions are released from one stack,
and the large diameter and temperature of that stack allow the pollutant
to be mixed in a layer of sufficient depth so as to result in negligible
ground-level concentrations. Since little contribution to ambient con-
centrations resulted from this stack, the concentrations appearing in
Table 11 were produced by the remaining stacks. It should be noted,
however, that changes in the stack characteristics of this source could
drastically change SO concentrations.
£
4. Complex of Plants
The preceding discussions of- control levels applies to a
single plant using a particu'lar retort process. If more than one plant
is present, the interaction of pollutant dispersion between the plants
must be considered. To evaluate this interaction, the complex of plants,
each with its own production level, stack characteristics and emission
rates, should be modeled together. At the present time, sufficient
72
-------
information on the different oil shale recovery schemes and the planned
configuration of plants is not available for a proper assessment of
resulting pollutant patterns. The information available does not seem
to warrant modeling a plant complex with the fine mesh of receptors
necessary to resolve the pollutant distributions. However, on the basis
of the modeling results for the TOSCO II and in situ plants, some recom-
mendations can be made. The distances of maximum concentration for each
pollutant and the rate at which the concentrations change with distance
are the determining factors for effective plant placement. It is evident
from an examination of the pollutant patterns shown in Figures 7 through 18
that plants situated in fairly close proximity can produce significantly
higher concentrations than those arising from a single plant, particularly
when one plant is directly downwind of another plant. A separation of
20 to 25 kilometers between plants should be sufficient to minimize any
adverse effects arising from the interaction of each plant's pollutants.
The concentrations,discussed above were computed assuming a
3
16,000 m /day (100,000 barrel per day) level of production. For other
production levels, the concentrations should be multiplied by the appro-
priate factor and the required control adjusted accordingly. For example,
concentrations should be reduced by one-half to obtain values for a 8,000
3
m /day (50,000 barrel per day) plant.
F. Recommendations
The above results for the oil shale region were obtained using
a number of assumptions involving plant emission rates and configurations
as given in Tables 2 and 3 and Figures 2 and 3 and the meteorology of
Grand Junction, Colorado, and Salt Lake City, Utah. Changes in any of
these variables could produce important differences in the predicted
concentrations and, therefore, control requirements. Before definitive
73
-------
results can be obtained for a specific oil shale facility, the actual
stack parameters and their emission rates for the proposed or existing
plant should be obtained and sufficient meteorological information on
the actual plant site should be gathered.
REFERENCES
1. Final Environmental Statement for the Prototype Oil-Shale Leasing
Program, Vol. I., Regional Impacts of Oil Shale Development, U.S.
Department of the Interior (1973).
2. D. O. Martin, and J. A. Tikvart, "A General Atmospheric Diffusion
Model for Estimating the Effects on Air Quality of One or More
Sources," Air Pollution Control Association Paper No. 68-148 (1968).
3. K. L. Calder, "A Climatological Model for Multiple Source Urban
Air Pollution," presented at the First Meeting of the NATO Committee
on the Challengers of a Modern Society, Paris, France (26-27 July
1971).
4. Parachute Creek Valley Diffusion Experiments, Battelle Pacific
Northwest Laboratories, September 1972.
5. Climatology at Parachute Creek, Colorado, Dames & Moore, April 1973.
6. An Evaluation of Existing Air Quality Data Obtained at the Parachute
Creek Site of Semi-Works Plant, Dames & Moore, July 1973.
7. Impact on Air Quality from Oil Shale Development, Final Draft, for
U.S. Department of Interior, Engineering Science, Inc., McLean,
Virginia (January 1973).
8. A. D. Busse, and J. R. Zimmerman, "User's Guide for the Climatological
Dispersion Model," Office of Research and Development, Environmental
Protection Agency, Research Triangle Park, North Carolina (1973).
9. Air Quality Data for 1968 from the National Air Surveillance Networks
and Contributing State and Local Networks. Environmental Protection
Agency, Division of Atmospheric Surveillance, Research Triangle Park,
North Carolina (August 1972).
74
-------
10. E. E. Hughes, E. M. Dickson, and R. A. Schmidt, "Control of
Environmental Impacts from Advanced Energy Sources," Contract
No. 68-01-0483, prepared for Office of Research and Development,
Environmental Protection Agency, SRI Project No. 2714, Stanford
Research Institute, Menlo Park, California (1974).
11. Air Quality Data—1972 Annual Statistics, Environmental Protection
Agency, Monitoring and Data Analysis Division, Research Triangle Park,
North Carolina (March 1974).
12. G. A. Briggs, "Plume Rise," U.S. Atomic Energy Commission, Office of
Information Services (1969).
13. D. B. Turner, "Workbook of Atmospheric Dispersion Estimates," Office
of Air Programs, Environmental Protection Agency, Research Triangle
Park, North Carolina (1970).
75
-------
-------
VIII CONTROL REQUIREMENTS FOR AIR POLLUTANTS
In order to determine whether the emissions of air pollutants* from
the oil shale industry are likely to be excessive and, therefore, to
require more control than appears available with the best current
technology, we have compared the anticipated emissions with two different
types of standards. The first is the ambient air quality standard.
Comparisons with this type of standard have been presented in the preceding
section (Section VII), where emissions from TOSCO II and in situ retorts
were used to calculate ambient concentrations at ground level in the
3
vicinity of a 16,000 m /day (100,000 barrels per day) plant. The second
type of standard that can be used in an estimate of the need for air
pollution control is the emission standard. This section of the report
summarizes the findings of the previous section on ambient air quality
and presents some relevant comparisons of emission standards.
Throughout this section control requirements are expressed in percent,
meaning the percent of the emission that must be removed in order to
achieve an ambient concentration or an emission level lower than the
comparison standard. The control requirement derived here refers to the
degree of control needed in addition to that achievable with best available
control. The following section (Section IX) presents our,findings as to
what constitutes best available control applied to the TOSCO II retorting
system proposed and described by the Colony Development Operation.1* As
defined in Section IX, best available controls lead to emission streams
3
with particulate loadings less than 46 mg/m (0.02 gr/SCF) and emissions
of combustion gases that meet the new source performance standards for
fossil fuel fired boilers. The proposed Colony plant is the basis for
*
Numbers refer to references given at the end of this section.
77
-------
the discussion of control requirements in this report, the only exception
being use of an in situ plant for some of the work reported in the
preceding section (Section VII).
The control requirements derived from dispersion modeling and
comparison with ambient air quality standards are summarized in Table 13.
The multiplicity of possible standards leads to the multiple estimates
of control requirements. The implication of Table 13 and the supporting
work in Section VII is that significant additional control may be needed
to prevent the violation of some of the very strict ambient air quality
o
standards for particulates and SO in the vicinity of a 16,000 m /day
£t
(100,000 barrels per day) oil shale plant using the TOSCO II process.
It should be pointed out that the maximum requirements for additional
control summarized in Table 13 are not necessarily requirements for
improved technology for removing pollutants from emission streams. Some
of the maximum values given in Table 13 are based on maximum concentrations
calculated to occur quite close to some of the relatively low stacks of
the proposed plant. While details of this phenomena are apparent only
through an examination of a number of calculations using different stacks,
stack locations, and stack heights as inputs, the effect is clearly
displayed in some of the figures presenting results of the dispersion
modeling in Section VII. Figures 10 and 14 are significant examples of
this effect and the implications.for deriving control requirements. In
both of these cases, a high concentration of the pollutant occurs next
to a low (only 15 meters high) stack because winds will bring some of the
pollutant to the ground right at the stack. Because this problem can be
solved by use of moderate height stacks (about 50 meters), it should not
be made the basis of a requirement for additional emission stream clean-up.
The same logic does not apply, however, to avoiding excessive ground
level concentrations associated with taller stacks. The implication of
78
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the EPA position limiting the use of tall stacks to control air pollution
from electric power plants would suggest that stacks more than 100 meters
(very approximately) should not be considered acceptable means of air
pollution control for an oil shale plant. The stacks in question here could
be made considerably higher without exceeding likely EPA restrictions on
stack heights deemed suitable for inclusion in an air pollution control
system for such a facility. Further clarification concerning the use of
tall stacks will depend upon the generation of definitive data regarding
sulfates and chemical transformations in the atmosphere.
A comparison of Figure 14 with Tables 9 and 10 will show that the
concentration chosen for calculating the SO2 control requirements is the
level that occurs over 5 km from the plant rather than the very
much higher level (perhaps 900(j,g/m3) that is calculated for a small area
within the plant itself. On the other hand, the maximum particulate
concentration of 377^g/m3 shown in Figure 10 is used as a basis for
deriving control requirements in Tables 9 and 10, despite the fact that it
occurs very close (about 0.5 km) to the plant and must reflect a significant
contribution that could be removed by increasing the height of the lowest
stacks. In this latter case, there is no obvious alternative level of
concentration on which to base a control requirement. The summary table
that concludes this section presents control requirements that reflect
our judgment on this matter.
The estimation of control requirements on the basis of emission
standards must be carried out under the assumption that emission standards
set for other industries can be applied to the oil shale industry. The
sources of significant quantities of emissions from oil shale processing
will be new plants. Therefore, it is appropriate that the emission
standards applied be new source performance standards. In the absence
of such standards for the oil shale industry itself, we have sought
analogies elsewhere. It appears that the developers of oil shale tend to
80
-------
make comparison to the standards for emissions from utility boilers,
and that these comparisons are made on the basis of weight of pollutant
per unit of energy consumed in the process. Such a comparison is presented
in Table 14.
Not all the emissions of the three pollutants are included in Table
14. Only those emissions that are produced in combustion processes are
included, because only these are logically comparable to the fossil fuel
boiler case. This point is especially significant with respect to the
particulate emission because less than a tenth of the total particulate
emissions from a TOSCO II plant having "best controls" are included in
the category of emissions from the combustion process itself. Over 90
percent of the particulate emissions are from processes other than pure
combustion, namely, from the shale handling, shale heating, and ball
cleaning operations shown in Figure 21 and Tables 16 and 19 of Section IX.
The pure combustion processes are those listed in Table 20 as associated
with product upgrading. Therefore, the implication of Table 14 that no
additional control of particulate emissions is required is not inconsistent
with the results of the air quality modeling of Section VII.
The conclusions to be drawn from the comparison of combustion
emission factors in Table 14 are as follows: (1) no additional control
is required on particulate emissions due directly to the combustion of
fuel to fire the retort; (2) about 20 percent additional control is
required in the combustion process to bring the SO emissions into
compliance with analogous emission standards for oil fired fossil fuel
boilers; (3) nearly 95 percent control of NO is required to bring the
X
combustion of fuel oil into compliance with analogous emission standards
for oil fired fossil fuel boilers. The table also suggests that much,
but certainly not all, of this additional control requirement for NO
X
can be met by making maximum use of gas and butane (C4 liquids) fuels
produced along with the shale oil.
81
-------
14
EMISSIONS FROM COMBUSTION IN THE TOSCO II
PROCESS COMPARED WITH FEDERAL STANDARDS FOR UTILITY BOILERS
Pollutant
(and fuel burned*)
Emission Factors in Weight per Energy Consumed
Emission Factor (kg/GJ)
Emission Factor (lb/10 Btu)
TOSCO
Standard
TOSCO II
t
Standard*
Particulates (gas) 0
Particulates (C ) 0
Particulates (oil) 0
S°2
S°2
S°2
NO
X
NO
X
NO
X
(gas)
(oil)
(gas)
(C4)
(oil)
0
0
0
0
0
2
.007
.009
.045
.22
.06
.43
.37
.39
.09
0.
0.
6.
0.
0.
0.
0.
0.
0043
043
043
35
35
087
130
130
0,
0
0,
0
0
1
0
0
4
.017
.02
.11
.51
.14
.00
.85
.91
.85
0.
0.
0.
0.
0.
0.
0.
0.
1
1
1
8
8
2
3
3
The TOSCO II plant can burn any one of three fuels produced from the oil
shale: a fuel gas, a butane fuel (C compounds), or a fuel oil.
Source: Colony Development Operation, Reference 1.
Source: EPA new source performance standards for fossil fuel boilers,
The Federal Register, 23 December 1971.
82
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The findings presented in this section and the preceding one,
Section VII, indicate a wide range of quantitative estimates of control
requirements, depending primarily on the choice of comparison standard.
The table just presented, Table 14, provided an emission standard
comparison for estimating requirements for controls beyond those
planned for Colony's TOSCO II plant. Our estimates for control required
beyond the best available control case presented in the following
section, Section IX, are given in Table 15. These control requirements
are derived from the dispersion modeling (Section VII) applied to the
emissions of the "best available control" case presented in Section IX.
No need for additional control beyond the best available is indicated for
hydrocarbons and oxides of nitrogen. A range of control requirements
is indicated in Table 15 for both particulates and sulfur dioxide.
These are the ranges we consider to be reasonable, as explained below.
The range of estimated control requirements has been narrowed from
the extremes that can be found in the preceding tables of this section
and Section VII by making the following assumptions, which we take to be
reasonable: (1) because the oil shale region now enjoys a minimum of air
pollution, it is unlikely that air quality there will be allowed to be
degraded to the most lenient standard. Hence, the federal primary
ambient air quality standards are ruled out; (2) if a significant oil
j
shale industry is allowed to come into being in western Colorado, the
region will not be classified as one where the most strict non-degradation
standards will be applied. Hence, the Class I federal and the most strict
2
Colorado (i.e. , the 15'pg/m 24-hr. SO ) air quality standards are ruled
out; and (3) to compensate for local effects of unnecessarily low (about
15 m) stacks only concentrations applicable over areas more than one square
kilometer in size and more than one km in distance from the plant are used for
quantifying control requirements. Hence, the calculated maximum con-
o
centration of particulates for the 24-hour worst case is taken as 200^g/m
rather than the 377|j,g/m3 peak used in Tables 9, 10 and 13.
83
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The conclusions in Section I regarding requirements for control of
oil shale air pollution beyond the best available control case are drawn
from Table 15 and the discussion presented in this section to explain
and justify the values adopted in Table 15.
REFERENCE
1. "An Environmental Impact Analysis for a Shale Oil Complex at
Parachute Creek, Colorado," Vol. 1, Part 1, published by Atlantic
Richfield Company as operator for the Colony Development Operation,
Denver, 1974.
85
-------
-------
IX ASSESSMENT OF AIR POLLUTION CONTROL METHODS
A. Introduction
As described in Sections IV and V of this report, the TOSCO II re-
torting process seems likely to dominate the oil shale industry at least
in the early stages of industry growth. This process is the only one for
which emissions figures are available on a unit operation basis. These
considerations have led SRI to adopt this process as representative of
the industry for purposes of estimating emissions. It will be seen that
certain elements of the process will be common to other above-ground re-
torting methods, while other elements are unique to TOSCO II. These
distinctions will be discussed so that an appreciation for the degree
to which conclusions depend on this choice may be" gained.
The data on the TOSCO II process are taken from the Environmental
1*
Impact Analysis published by the Colony Development Operation. The
Atlantic Richfield compa'ny (ARCO) is the operator for the group of com-
panies that comprise Colony. The shale oil complex planned by Colony
incorporates certain control devices and methods that are considered by
the operator to be adequate to ensure that appropriate federal and state
standards are met. No claim is made by the operator that "best control"
is achieved, or that a complex of plants like the Colony operation in the
same vicinity would not violate appropriate standards. The objective in
this section of the study is to ascertain how effective the applied con-
trols are, and to estimate what degree of control may reasonably be ex-
pected in an effort to apply best available control to the system des-
cribed by Colony. The estimate of these limits will help in the assess-
ment of the impact of a developing industry, and will help define the
need for improved control technology.
*References are listed at end of section.
87
-------
A definitive, detailed engineering analysis of all process streams
and potential control methods comparable to the effort extended by the
operator and his contractors responsible for designing controls systems
is far beyond the scope of this study. In any event, important details
of various process steps are considered proprietary and not available for
our examination. In spite of these facts, the available data are ade-
quate for a model and several useful conclusions may be drawn concerning
emissions control. The selection of control methods is intimately bound
to process economics, a particularly proprietary matter. Hence, it is
assumed that the kind of device selected for a particular application is
the appropriate choice, but not necessarily that it is operated at maxi-
mum effectiveness. Where control remains inadequate at maximum effec-
tiveness, further development would be necessary. Where alternative
controls were considered by the operator, these are discussed. In other
words, redesign of the TOSCO II process as implemented by Colony is not
attempted.
For each of the major process steps in the Colony design the
emissions are estimated assuming "best control" is applied. These
judgments are based on familiarity with the types of control equipment
specified by Colony and with the performance that can be expected at
what is judged a reasonable cost. Specific, quantitative estimates
of best control are given in this section for each unit of the process.
Control performance is conservatively estimated in that better perfor-
mance has been achieved in limiting cases. Where improved control is
achieved with cleaner fuels, the assumptions underlying the 'best con-
trol" case are clearly stated. However, it must be emphasized that the
plans for the fuels to be used are only tentative in any case.
In addition to the data in the Environmental Impact Analysis,
2
some data gained in personal communication with representatives of
88
-------
Colony were useful in the study. This assistance is gratefully ack-
nowledged.
B. Description of Process
A detailed description of process streams for the TOSCO II process
is given in Section IV. A modular description is presented here so that
elements common to other retorting methods can be identified and the
emissions for each module can be characterized. A simplified process
diagram for any above-ground retorting plant is given in Figure 19.
In the ore-preparation module shown in Figure 19 the run-of-mine
ore is reduced to a maximum size compatible with the retorting method.
A sufficient quantity of ore in the various stages of preparation is
placed in storage to guard against interruptions in mine output or
crushing equipment failures. The only emission of consequence here is
dust--fugitive dust from the transport and storage of the ore and dust
generated in the crushing operation. The magnitude of these emissions
depends in part on the fineness of the feed required by.the oil shale
plant, but may be unprecedented in magnitude lecause of the vast quantitj
of material to be handled.
In the retorting module shown in Figure 19 the ore is converted
to a useful hydrocarbon product plus a shale ash to be discarded. The
emissions to the atmosphere from this module vary greatly in kind de-
pending on the retorting method. Products of combustion are always
present, and these may be mixed with process constituents in some re-
torts. Control problems in this module may be unique to oil shale
processing or to specific retorts. In the TOSCO II process, for
example, flue gases are loaded with dust and hydrocarbons from direct
contact with the shale. Control problems are compounded by the large
quantities of effluent to be treated. Most of the fuel consumed in a
89
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plant is consumed in this module. Finally, shale ash disposal presents
dust control problems for any retort.
In the product-upgrading module shown in Figure 19, the hydrocarbon
product from the retort is further processed into a more useful form.
Emissions in this module consist of combustion products plus sulfur
dioxide resulting from removal of sulfur compounds from the process
streams. None of these emissions is unique to oil shale processing.
C. Emissions and Controls
The emissions estimated and controls planned by the Colony Develop-
ment Operation for a TOSCO II plant are now considered in some detail.
3
The Colony plant would produce 8,000 m /day (50,000 barrels/day) of
product. The present estimates are made for a hypothetical plant twice
that size.
The ore-preparation system is indicated schematically in Figure 20.
The primary crusher reduces the ore to a maximum size of about 23 cm
(9 in), and this is further reduced in the final crusher to less than
1.25 cm (1/2 in). Dust control at these sites and at the fine ore
storage facility is maintained with a baghouse. Estimates of emissions
and control performance are given in Table 16.
The estimates of "Emissions Without Control Devices" were not
given directly by Colony, but were deduced by SRI from the values given
for disposal of dust from these control points and from the stated flow
rates. The "Emissions Remaining With Planned Control" shown are as given by
Colony. From these values the "Device Efficiency" shown is calculated.
3
SRI estimates that a dust loading not exceeding 46 mg/m (.02 gr/ACF)
is an achievement reasonable to expect in a well maintained baghouse.
Higher performance might be achieved, but this conservative estimate
serves as a base to calculate the "Emissions Remaining With Best Control"
91
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and "Efficiency With Best Control. The resulting values for efficiency
appear quite reasonable.
Various sources of fugitive dust remain in the ore-preparation
system planned by Colony, even after the provision for enclosures
surrounding transport and processing equipment. The most important
potential source is the stockpile of coarse ore from the primary
crusher. Control is maintained with water sprays, and the planned
site is selected to minimize the surface area exposed to the wind.
The magnitude of this problem will depend directly on the detailed
topography of the stockpile, which is constantly changing in normal
operation, and the persistence in applying a water spray. In the
absence of detailed assumptions, estimates have little meaning.
However, it seems reasonable to assert that sufficient spraying can
be applied to effectively suppress dust levels below those resulting
from the sources listed in Table 16.
The pyrolysis and oil recovery unit for the TOSCO II process is
shown schematically in Figure 21. This unit is analogous to the re-
torting module in Figure 19. The majority of each type of pollutant
emitted from a TOSCO II plant is emitted from this unit. About two-
thirds of all combustion takes place here, and the shale is further
crushed very finely in the pyrolysis drum.
Colony plans to use only process fuels for combustion. Three
distinct fuels will be used—fuel gas, C liquids (butanes and butenes),
and a distillate fuel oil. All the fuel gas and C liquids produced
will be consumed. The remaining needs will be made up with the fuel
oil. A complicated fuel system provides various combinations of fuels
to furnaces equipped with multiple burners. The proportions will be
highly variable during normal plant operation. A typical consumption
schedule for the plant is given in Table 17 and is the basis for
94
-------
emission rates presented below in Tables 19, 20, and 21.
The fuel gas and C liquids are treated in the gas recovery and
treating unit to remove hydrogen sulfide. The fuel oil could be gas
oil or naptha (see Fractionator in Figure 21) or a blend of the two.
Colony plans to use gas oil before upgrading and removal of moderate
sulfur and high nitrogen content. The maximum emission rates for these
three fuels as specified by Colony are given in Table 18, along with the
federal performance standards tor new power plants for comparison.
Estimates of emissions from the pyrolysis and oil recovery unit using
these fuels are given in Table 19. The raw shale preheat system consumes
nearly all the fuel supplied to this unit. Hot flue gases from the ball
heater contact the raw crushed shale directly,in a fluidized bed, adding
particulate and hydrocarbon loads to the combustion products. An
incinerator reheats the flue gases and reduces the hydrocarbons volatilized
in the fluidized bed. The ball circulation system uses flue gases from
the steam super-heater to remove residual, processed-shale dust. Dust
removal is accomplished with dry cyclones followed by venturi wet scrubbers.
The processed-shale moisturizing system emits only particulates in the form
of processed-shale dust, controlled with a venturi wet scrubber.
The values given for particulate emission in Table 19 were deduced or
calculated as in Table 16. An exception is the Emissions Remaining 7/ith
Planned Control of particulates in the raw shale preheat system. The
emission rate and loading values given by Colony seemed to be inconsistent.
The loading value, consistent with SRI estimates of performance reasonably
to be expected, was accepted and used to calculate an emission rate nearly
o
double the Colony value. This same loading value, 46 mg/m (.02 gr/ACF),
is the basis for the SRI estimate of Emissions Remaining 'Vith Best Control
for the other scrubbers in this unit.
95
-------
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101
-------
The basic control method for SO planned by Colony consists of the
£t
use of treated fuels. Flue-gas desulfurization was considered by Colony
and judged to be more expensive and less reliable. Colony has indicated
that if the emissions of SO must be reduced for the plant, a treated
2t
fuel would be used to replace the planned fuel oil in the proportion
necessary to meet requirements. The cost for this was estimated at
"approximately one-eighth of a barrel of low sulfur fuel oil product
. . . per barrel of 'treated' fuel oil burned." The characteristics of
such a treated fuel oil were not specified; however, both SO and NO
^ x
emissions could be reduced by additional hydrogenation of the fuel oil.
This hydrogenation would remove sulfur as H S and nitrogen as NH . In
^ «3
practice the nitrogen is harder to remove than the sulfur, so that re-
ducing the relatively high nitrogen content in the fuel oil to lower
levels would result in even greater reduction of the sulfur level.
However, for purposes of defining best available control, SRI has
assumed that the treated fuel oil cbuld meet the federal performance
standards for oil fired boilers shown in Table 18. The substitution
of this treated fuel oil results in the SO and NO Emissions Remaining
2 x
With Best Control shown in Table 19. It is seen that the NO emission
x
is substantially reduced with this substitution. The SO emission
£t ^
must be regarded as an upper limit, since hydrotreatment is more effec-
ti.ve on sulfur as described above.
A major cost consideration for Colony regarding flue-gas desul-
furization is related to the large (125 to 150 percent) excess-air
firing in the shale preheat system where nearly all the fuel oil is
combusted. This practice, done for process reasons, results in much
larger quantities of effluent to be treated and correspondingly larger
102
-------
capital and operating costs. Nonetheless, should greater control of
SO emissions be required to meet a standard, flue-gas desulfurization
£t
is certainly an option to be considered and compared in cost with addi-
tional hydrotreatment. Flue-gas desulfurization equipment appears to
be capable of meeting the additional control requirement shown in
3
Section VIII and in Table 21 above.
Estimates of emissions from the remainder of a TOSCO II plant are
given in Table 20. These units comprise the product-upgrading module
shown in Figure 19, and would be similar for any retort producing a
similar product. Emissions result from the combustion of treated fuels,
as examined above, and from the operation of the sulfur plant. The
performance of the specified tail-gas treating plants is considered to
be a reasonable estimate.
Finally, Table 21 shows the totals of emissions of each type listed
in Tables 16, 19, and 20. This table is intended to be an indication of
overall performance showing planned controls and, with reasonable assump-
tions, limits of best available control using the same basic scheme.
D. Estimates for Other Retorting Schemes
The emissions estimates for ore-preparation modules would be similar
to those given in Table 16 for any retorting method requiring a maximum
size of 1.25 cm (1/2 in). Furthermore, it is seen that the emission
rates, for both primary and final crusher are approximately the same
in spite of the size difference. A reasonable estimate for any retort
accepting a large-size feed of about 20 cm (8 in) would be that for the
primary crusher, and for a retort requiring a substantially smaller size
the total for both crushers would be a reasonable estimate. The estimate
for ore storage could be used for either case.
103
-------
Emissions from a retorting module could differ significantly from
the estimates in Table 19. Particulate and hydrocarbon emissions from
the raw shale preheat system and ball stack system result from the
W
specific design of TOSCO II. These could be absent in other retorts,
except for relatively insignificant particulate emissions from the
combustion. The estimate for the processed-shale moisturizer should
serve as an upper limit for other retorts where the shale has not been
so finely crushed.
Estimates of SO and NO emissions in the retorting and product-
^ X
upgrading modules depend primarily on the sulfur and bound-nitrogen
content in the process fuels and the total quantities combusted. Under
present conditions, hydrotreating the process fuels is the likely con-
trol method due to the nature of the plant and respective costs. Again,
if further reduction of SO emissions is required after hydrotreatment,
2t
flue-gas desulfurization could be applied. Unlike the operation planned
by Colony, process restrictions may not exist to make flue-gas desul-
furization more difficult. Even other TOSCO II installations could
differ with regard to the fuels planned, especially for the shale-
preheat system.
The emission of SO from the sulfur plant depends primarily on the
total output of low-sulfur product, but is small relative to combustion
emissions.
104
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REFERENCES
Atlantic Richfield Company, An Environmental Impact Analysis for
a Shale Oil Complex at Parachute Creek, Colorado," Vol. 1, Part I,
Colony Development Operation (1974),
Private communication, Robert E. Smith, Atlantic Richfield Company
(Colony Development Operation).
Proceedings: Flue-Gas Desulfurization Symposium—1973, EPA-650/
2-73-038, December 1973.
105
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SECURITY CLASSIFICATION Of THIS PACE (Wtait Ottm
REPORT DOCUMENTATION PAGE
READ INSTRUCTIONS
BEFORE COMPLETING FORM
I REPORT NUMBER
EPA-600/2-75-009
2. OOVT ACCESSION NO,
RECIPIENTS CATALOG NUMBER
4 TITLE (an* Sufcflll*)
OIL SHALE AIR POLLUTION CONTROL
I. TYPE OF REPORT • PERIOD COVERED
FINAjL
PERFORMING ORG. REPORT NUMBER
Project 2714
E. E. Hughes, P. A. Buder, C. V. Fojo,
R. G. Murray, R. K. White
CONTRACT Oft CHANT NUMBER/*.)
68-01-0483
9. PERFORMING ORGANIZATION NAME AND AOORESJ
Stanford Research Institute
Menlo Park, California 94025
10. PROGRAM ELEMENT. PROJECT, TASK
AREA • WORK UNIT NUMBERS
1NBH58 PEMP 02
II. CONTROLLING OFFICE NAME AND ADDRESS
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
II. REPORT DATE
(date sent to publication)
IS. NUMBER OF PAGES
105
14 MONITORING AGENCY NAME ft ADORESftfff tffffwwtt
Cwtfr*flln4 Office)
IB. SECURITY CLASS, (ol lltlt
UNCLASSIFIED
1S«. OECLASSIFICATION/OOWNGRADINO
)•. DISTRIBUTION STATEMENT (•! tfil* JUpwrlJ
Unlimited
17. DISTRIBUTION STATEMENT (•! If)* •fecfrMl «H(*rW In •!••» M. II HIHrml Hum
IS SUPPLEMENTARY NOTES
(continued from No. 20)
Colony. Requirements for additional control are estimated by comparing calculated ambient air
quality with standards. Options for supplying the additional control Indicated for particulates
and sulfur dioxide are identified.
KEY WORDS rC«rttaw «n
oil shale
TOSCO II retort
air pollution
dispersion modeling
•14* If *•*•••«? tnt Mmrf fr ftp fel«cfc i
control technology
control requirement
Colony Development Operation
environmental impacts
0 ABSTRACT CCcntlnu* *n IWMTIM »I4» H n*c***a/r «Ml l«M«lf^ »r M*«*
This study evaluates the air pollution potential of emissions of particulates, sulfur
ioxide, oxides of nitrogen, and hydrocarbons from the anticipated development of an oil shale
ndustry. The analysis is based primarily on the published description of a TOSCO II retorting
rocess as planned for commercial use by the Colony Development Operation. The technology,
recesses, plans, projections, and environmental impacts of oil shale development are reviewed.
The results of dispersion model calculations of concentrations of pollutants in ambient air near
11 shale plants employing TOSCO II and in situ processes are presented. These calculations for
he TOSCO II plant assume that best available controls are applied to the process planned by
(continued under No. 18)
1 JAN TJ
1473
EDITION OF I NOV •• IS OBSOLETE
SECURITY CLASSIFICATION OF THIS PAGE (•»••« OM« *nr*r*«
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