EPA-650/2-74-099
October 1974
Environmental Protection Technology Series
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EPA-650/2-74-099
ENVIRONMENTAL CONSIDERATIONS
FOR OIL SHALE DEVELOPMENT
by
N. Conkle, V. Ellzey, and K. Murthy
Battelle Columbus Laboratories
505 King Avenue,
Columbus, Ohio 43201
Contract No. 68-02-1323 (Task 7)
ROAPNo. 21ADD-023
Program Element No. 1AB013
EPA Project Officer: L. Lorenzi, Jr.
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
October 1974
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This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
11
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ABSTRACT
Results of a preliminary literature study of the environmental
considerations in the development of an environmentally acceptable oil
shale industry are presented. The following seven different areas are
Included in the study.
Oil Shale Deposits
Mining, Handling, and Pretreatment Processes
In-Situ Retorting
Ex-Sltu Retorting
Retorted Shale Refuse Disposal
Other Environmental Considerations
Product Treatment and Usage
Research and development needs required to eliminate inadequacies in
the data base necessary to evaluate potential environmental problems
are noted.
The report provides an overview of the anticipated oil shale
industry, including the magnitude of the resources available and the
likely technical and environmental problems to be encountered. Specific
technologies likely to be employed in the mining, oil extraction, and
on-site upgrading processes are also identified. The status of develop-
ment of these technologies and their potential economic, resource, and
environmental impacts upon the oil shale resource regions and the nation
as a whole are also described.
This report was submitted in fulfillment of Task 7 of Contract
68-02-1323 under the sponsorship of the Office of Research and Development,
Environmental Protection Agency.
iii
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MANAGEMENT SUMMARY
This report is the result of a study initiated by the United States
Environmental Protection Agency. The effort was modest (about 2 manmonths)
and the report is not meant to be an exhaustive or in-depth analysis of the
environmental aspects of oil-shale production. In the years ahead shale-oil
is expected to contribute significantly to the US energy supply and will obviously
be a growing industry. This report, then, is a preliminary study which can
be a basis for further efforts to completely define the environmental problems
and help develop an environmentally acceptable shale oil industry. Presented
in Chapter IX is a summary of the research needs to achieve this goal.
Shale Oil Availability
The large quantity of oil-shale reserves and resources available
is a positive component of US energy resources. Estimated reserves constitute
the equivalent of 80 billion barrels of oil and can provide a good supply of
the total oil consumption rate which is currently about 7 billion barrels
per year. Resources the equivalent of 1,800 billion barrels are located
in the Green River formation of several basin areas in Northwestern Colorado,
Northern Utah, and Southwestern Wyoming. This formation ranges in thickness
from a few hundred to about 2,100 meters, underlying an area of roughly
44,000 square kilometers . Although oil shale deposits are found in
numerous areas of the United States, the Green River formation is at present
the only deposit of adequate size and availability to have potential commer-
cial value.
About 70 percent of the reserves and 78 percent of the resources
are located on Federally owned lands. Therefore the extensive development
of the largest amount of the nation's oil shale potential will be contingent
upon the issuance of Federal leasing policies, plus the resolution of title
questions on significant parts of the Federal lands. It is practically
certain that the Federal government will act favorably on these matters if
private companies decide to make the investment decisions required to start
up a full-scale oil shale producing industry.
iv
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Other minerals associated with oil shale could be recovered as
salable by-products resulting from retorting and refining operations. Two
such minerals, dawsonite [NaAl(OH)2CO_] and nahcolite (NaHCO.), could
produce large quantities of alumina and soda ash, respectively.
Mining and In-Situ Oil Recovery
Two major options are under consideration in this phase of oil shale
development: mining followed by surface processing of the oil shale (ex-situ),
and in-situ (or in-place) processing of the oil shale. Of the two options,
only the adit mining (horizontal entrance into a mine) and surface processing
approach is believed to have been advanced to the point where it may be
possible to scale up to commercial production during this decade. Until only
recently, virtually all efforts to develop oil shale technology were directed
toward conventional mining, crushing, and ex-situ retorting.
Oil shale mining by either underground or surface methods differs
very little from conventional coal mining methods. Major advances in under-
ground mining of oil shale were achieved by the Bureau of Mines in its Oil
Shale Program during 1944-1956. The state of technology of underground mining
of oil shale is highly developed. The same cannot be said for surface mining
or in-situ methods of oil recovery, although surface mining methods seem
quite feasible for certain shale deposits. In-situ methods have been studied
and much experimentation has been undertaken by private companies. For the
most part results of their work are not made public. Based upon current
data it is believed that it would take about five more years to develop the
in-situ method to a commercial stage.
Environmental problems resulting from underground mining and in-
situ methods of recovery seem controllable. However, there would be serious
environmental problems if nuclear devices were to be used for underground
fracturing of shale preparatory to underground retorting. These problems
would involve surface subsidence, effect on air and underground water,
safety, and possible radioactivity of the retorted oil brought to the
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surface. Surface mining methods such as open pit mining or strip mining,
eould have an adverse impact. Effects on soils, vegetation, topography,
specific land and cultural features, water quality, air quality,
wildlife habitat, grazing patterns, and recreation would have to be
controlled. Overburden removed for strip mining would have to be replaced
into mined-out areas and revegetated. Open pit mining's environmental
impacts would be essentially the same as for strip mining. When an open
pit mined area was exhausted of shale, spent shale from retorting could
be used to fill the pit followed by soil cover sufficiently to permit
revegetation. The figure on page vii presents the environmental emissions
identified in this study which are associated with exploitation of oil
shale deposits by either conventional or in-situ techniques.
Ore Handling and Pretreatment
Oil-shale ore handling and pretreatment prior to retorting
present, by and large, little difficulty in an overall oil shale-producing
complex.
Environmental impacts from ore dressing for an underground mine
are minimal when performed within the underground operations. For surface
ore dressing, environmental impacts are significant and are intimately
associated with other surface operations. Dust generation from crushing
and allied operations and from the transportation of ore to crushing
facilities would, according to one estimate, result in overall dust losses
of about 1.3 percent of the shale ore handled . This estimate was based
on experience of 15 to 20 years ago by the U.S. Bureau of Mines. Today
there are equipment and methods that could significantly reduce the loss
of airborne particles to the atmosphere. The effect of the product loss
on product cost is difficult to estimate from available data.
Process flow stream dust losses can be collected with conventional
collection equipment, dampened, and disposed of with the spent shale residue
from the retorting plants.
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PAGE NOT
AVAILABLE
DIGITALLY
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Retorting
The retorting process considered most promising on the basis of
ease of environmental effluent control, shale oil extraction efficiency, and
technical advancement is the Oil Shale Corporation's TOSCO II retort. This
system, Involving a horizontal rotary kiln heated by externally fired
ceramic balls, has several specific advantages: (1) low, controlled
temperature retorting allowing a minimum of carbonate decomposition,
(2) production of undiluted, high Btu retort gas - possible because the
heat required for retorting is generated (by combustion) external to the
retort, (3) extremely high shale oil extraction - possible because of the
systems' capability to utilize finely crushed shale, (4) the production of
an additional fuel source in the form of carbonaceous residue remaining on
the spent shale, and (5) many years of active investigation, optimization,
and refinement of the retorting process culminating In the successful,
continuous operation of the largest capacity oil shale retort in the U.S.
A possible variation in the use of TOSCO retorts showing promise
would be the combined use of both TOSCO retorts and some vertical shaft
retort, e.g., Gas Combustion, Union Oil, or Fetroslx retorts. Such a
combination would allow an improved efficiency In the crushing and screening
operations. This is done by using the larger pieces of shale for the
vertical shaft retorts and the fines for the TOSCO retort, thus reducing
both the quantity of fines generated and the required degree of crushing.
In addition to the economic advantages (from reduced equipment require-
ments and energy and water usage) the possibility of air and land pollution
would be lowered. Another possible advantage from a combined operation
would be the use of low Btu retort gas from an internal combustion heated
vertical retort (Gas Combustion or Union Oil retorts) to provide fuel to
heat the ceramic balls for the TOSCO retort. Such an operation could free
the high Btu retort gas from the TOSCO retort, which, because of its high
sulfur concentration,can be economically desulfurized and used as a high
quality, clean burning on-site fuel gas or exported.
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Potential environmental problems resulting from the oil shale
retorting operation include atmospheric emissions of participates, oxides
of sulfur and nitrogen, hydrocarbons, and carbon monoxide. Presently,
data to accurately estimate the quantities of these pollutants are lacking.
However, inspection of the retorting process control mechanisms indicates
that the major environmental problem area will not be in the control of the
retorting operation itself but in the upgrading and utilization of the products
of the retorting operation.
Particulate levels in the product gas stream are expected to be low
because they are removed simultaneously in the oil removal operation.
However, the hydrogen sulfide content in the gas is high and when combusted
is expected to result in unacceptable emission levels of sulfur oxides unless
some form of stack gas desulfurization or pre-combustion treatment for removal
of the sulfur from the gas is undertaken.
Significant quantities of nitrogen oxides could also be emitted
from the combustion process.
Upgrading crude shale oil is another potential environmental problem
area. The oil must be upgraded to a pumpable quality and sulfur and nitrogen
levels must be reduced. The anticipated method for this upgrading operation
is delayed coking and catalytic hydrogenation. Data necessary to accurately
assess the magnitude of the anticipated emissions from these upgrading
operations are presently lacking. Emissions of participates, sulfur,
hydrocarbons, and carbon monoxide are likely. While these operations can
be similar to those currently employed in petroleum refineries, data are
lacking on actual upgrading of shale oil necessary to determine environmental
problem areas. It is emphasized at the risk of repetition that the lack of
data is a serious hindrance to the quantification of pollutants; consequently,
defining the extent of environmental problems of this potentially vast
industry is not easily accomplished.
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Refuse Disposal
The refuse disposal scheme most promising on the basis of
developed technology, economics, and environmental protection is the trans-
port of the cooled and moistened refuse in a system involving minimum
handling, such as truck or covered belt transport, to adjacent canyons or
other topographic depressions where it would be landfilled. Potential
water pollution from runoff from the disposal areas can be safeguarded
by dams, culverts, retaining ponds, and/or diversion ditches. Erosion of
the residue piles will be avoided by stabilization techniques including
special placement of the waste in thin layers maintaining a low angle of
repose to insure frictional stability. Chemical stabilization may also be
used,and eventually vegetative stabilization through import of soil and
fertilization prior to seeding to produce native vegetation can be employed.
Utilization of underground mined out areas as a disposal location
in the distant future appears likely but not until a significant fraction of
the mine's ore has been extracted. Both belt and slurry transportation
methods are considered feasible, however the lack of adequate supplies of
water along with certain technical problems of settling, particle size, etc.,
may preclude the use of slurry systems on an extended scale.
Utilization of the spent shale as a source of valuable raw
materials would be the most favorable method of refuse "disposal".
However, It is not likely in the near future. Several obstacles lie in the
path to large scale extraction of the aluminum and sodium based minerals
from the spent shale. Not the least of these is the lack of a proven and
tested extraction technology. Possibly as significant are the market
uncertainties and the bleak forecasts of limited future markets for the
vast quantities of these minerals. Even alumina may experience diffi-
culties entering into the tough international bauxite market. Capital
investments for alumina extraction processes and associated pollution
control facilities would be many millions of dollars. There is also the
uncertainty regarding long term availability of alumina ore from this source.
xi
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Product Usage
Products from the retorting of oil shale and the necessary on-
site upgrading operations will represent new fuel and chemical supplies.
Basically, three main groups of products will be derived; gaseous fuels, liquid fuels,
and solids. Retort gas and gases created in the cracking of the shale oil
in the hydrogenation operations will primarily serve in-house fuel needs.
These gases, whether desulfurized before or after combustion, are envisioned
to be utilized for electricity and steam generation and as fuel gas in on-site
upgrading processes. Because the entire quantity is anticipated to be consumed
on site, this product'si effect on the nations' total energy requirements should
be negligible.
The liquid product from retorting is generally a viscous, foul
smelling, waxy, high-nitrogen, high-sulfur oil. Direct combustion of this
crude shale oil is not envisioned. Instead, upgrading to pumpable quality
followed by transport to a petroleum refinery for processing is the more
likely route. The upgrading process involving delayed coking and catalytic
hydrogenation produces a desulfurized, denitrified, synthetic crude oil, plus
additional fuel gas and sulfur, ammonia, and green coke as by products.
Although this syncrude has some unusual characteristics compared to petroleum
crude it is expected to be readily acceptable to processing by conventional
techniques. The main products will be gasoline, jet and diesel fuel, and
domestic and industrial heating oils. A variety of refinery by-products
similar to those obtained from petroleum crude oil refining, plus a number
of more unusual products are anticipated. The main products and most of the
by-products from syncrude refining are expected to supplement current industry
fuel and chemical supplies.
The energy needs of the nation will be supplemented by the fuel
products derived from oil shale. However, the significance of shale oil will
naturally depend on the extent of development of the oil shale industry.
Various predictions on the rate and level of anticipated development abound,
ranging from 100,000 to 1 million (MM) bbl/day capacity by 1985. Probably,
the National Petroleum Council's estimate of a maximum capacity of 400,000
bbl/day by 1985 is reasonable. The quantity of oil estimated to be required
xii
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for domestic use by 1985 is 26 MM bbl/day of which 57 percent is anticipated
to be foreign oil. Development of the oil shale industry to the 400,000
bbl/day level would provide just about 2 percent of this requirement, and,
reduce foreign oil requirements by just 3 percent. Because of the limitations
of manpower, equipment, and logistics, the growth of shale oil production
capacity will be limited to 400,000 bbl/day by 1985 with simultaneous construction
resulting in an annual increase in capacity of only 100,000 bbl/day. While
such growth is not anticipated to keep pace with America's energy needs, it
should provide a significant new source of liquid fuels and chemicals.
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TABLE OF CONTENTS
Page
ABSTRACT Ill
MANAGEMENT SUMMARY iv
LIST OF TABLES xvil
LIST OF FIGURES xviii
I. INTRODUCTION 1
II. OIL SHALE DEPOSITS 3
Location, Classification, and Ownership 3
Quality of Shale Oil 8
Associated Minerals 8
Composition of Deposits 9
Requirements and Incentives 10
III. MINING, HANDLING, AND PRETREATING PROCESSES 12
Process Description 12
State of the Art 15
Nature of Products 17
Environmental Impacts 17
IV. IN-SITU METHODS OF OIL RECOVERY 20
Process Description 20
State of the Art 20
Nature of Products 23
Process Efficiency 23
Environmental Considerations 26
V. EX-SITU RETORTING 28
Gas Combustion Process (Type 2) 29
xiv
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TABLE OF CONTENTS
(Continued)
Page
The Union Oil Process (Type 2) 39
Petrosix Process (Type 3) 47
TOSCO Process (Type 4) 54
VI. RETORTED SHALE REFUSE DISPOSAL 62
Factors Affecting the Magnitude of the
Disposal Problem 62
Methods of Disposal of Retorted Shale Refuse 68
Utilization of Spent Shale 71
VII. OTHER ENVIRONMENTAL CONSIDERATIONS 76
Impact on Land and Landscape 76
Impact on Vegetation 76
Impacts on Grazing 80
Noise Impacts 81
General Esthetics and Recreation 82
Economic and Social Development 83
Water Resources and Quality 85
VIII. PRODUCT TREATMENT AND USAGE 90
Gaseous Products 90
Crude Shale Oil Products and By-Products 94
Other By-Products 106
IX. RESEARCH AND DEVELOPMENT NEEDS 108
Shale Mining 108
Ore Handling and Pretreatment 109
Retorting 109
xv
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TABLE OF CONTENTS
(Continued)
Page
Refuse Disposal 110
Produce Usage Ill
X. REFERENCES 112
xvi
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LIST OF TABLES
Page
Table 1. Summary of Oil Shale Resources and Reserves as of 1971 ... 7
Table 2. Characteristics of Oils from In-Situ Retorting 24
Table 3. Characteristics of Gases from In-Situ Retorting 25
Table 4. Properties of Crude Shale Oil Produced by the Gas
Combustion Process 35
Table 5. Properties of Retort Gas from the Gas Combustion Process . . 35
Table 6. Properties of Crude Shale Oil Produced by the Union Oil
Retort "A" Process 43
Table 7. Properties of Shale "Gas" Produced by High Temperature
Internal Combustion Retorting Process 44
Table 8. Properties of Crude Shale Oil Produced by the TOSCO II
Process 56
Table 9. Properties of Retort Gas Produced by Indirect Heated
Retorting Processes 57
Table 10. Physical Properties of Retorted Shale 63
Table 11. Quantity of In-Place and Spent Shales 67
Table 12. Mineral Composition of Minable-Bed Samples from the
Mahogany Zone, Rifle, Colorado 72
Table 13. Land Requirements 77
Table 14. Vegetation Impact Areas - Underground Mine, Surface Mine,
In-Situ 78
Table 15. Acreage Reduction for Grazing 81
Table 16. Water Consumed by Optional Mining Methods for Shale Oil
Production 86
Table 17. Characteristics and Yields of Untreated Retort Gases .... 92
Table 18. Characteristics of Crude Shale Oils 95
Table 19. Typical Properties of Crude Shale Oil and Syncrude 96
Table 20. Products from Shale Oil Processing 103
Table 21. Projected Shale Oil Production 105
xvii
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LIST OF FIGURES
Figure 1.
Figure 2.
Figure 3.
Figure 4.
Figure 5.
Figure 6.
Figure 7.
Figure 8.
Figure 9.
Figure 10.
Figure 11.
Figure 12.
Figure 13.
Figure 14.
Figure 15.
Figure 16.
Distribution of Oil Shale in the Green River Formation:
Source, Relative State of Knowledge and Specific
Products Derived from the Oil Shale Processing Cycle . .
Flow Diagram of 50 , 000-Barr el-Per-Day Underground Oil
Shale Mine and Processing Unit
Crushing, Screening, and Briquetting Plants - Schematic
Schematic Representation of an In-Situ Retorting
Wyoming W-a and W-b In-Situ Recovery - Conceptual
Union Oil Retort
Rock Pump for Union Oil Retort
Demand and Supply for Water: 50 , 000-Barrel-Per-Day
Demand and Supply for Water: 50, 000-Barrel-Per-Day
Underground Mine, Tract C-b
Refining of Shale Oil
Page
4
13
16
19
21
27
30
31
40
41
48
55
88
89
99
102
xviii
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PRELIMINARY LITERATURE STUDY OF ENVIRONMENTAL
CONSIDERATIONS FOR OIL SHALE DEVELOPMENT
I. INTRODUCTION
Large land areas of the United States are known to contain oil-
shale deposits, but those areas In Colorado, Utah, and Wyoming that contain
the shale-rich sedimentary rocks of the Green River Formation offer the
greatest promise for shale oil production in the future. These oil shales
occur beneath 64,750 square kilometers (25,000 square miles) of land area,
and of this area 44,030 square kilometers (17,000 square miles) are
believed to contain oil shale of potential value for commercial development
in the foreseeable future.
The known Green River Formation deposits include high-grade
shales, in beds at least 100 meters thick and yielding 104 liters per kkg*
(25 or more gallons per short ton) of oil containing about 600 billion
barrels** of oil. Recovery of even 10 percent of this resource would
represent a significant energy source adequate to supplement the Nation's
oil supply for two to three decades, providing economic and environmentally
safe methods of shale oil production are developed.
The Synthetic Liquid Fuels Act of April 5, 1944, as amended,
made possible a large-scale oil shale research and demonstration effort by
the United States Department of the Interior (USDI) Bureau of Mines during
the period 1944-56. This effort was aimed at the creation of new and more
economical mining, retorting, and refining technologies, and also sought
to provide reliable information on the costs of commercial shale-oil
production. Industry has also conducted extensive research on oil-shale
processing.
Commercial shale-oil production, under USDI's most optimistic
estimate, could begin about 1975 at a rate of about 18 million barrels per
year (50,000 barrels per day). The first generation technology available
* kkg - kilo kilograms or 1000 kilograms.
** This represents about 300 percent of all known and probable liquid fuels
reserves of the United States.
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for the initial commercial production would be improved from 1976 to 1980.
This developmental stage will experience incremental annual production
increases of about 18 million barrels every year as the new technologies
are applied so that by 1980, a cumulative productive capacity of more than
100 million barrels per year could be established. More importantly, the
technology probably will have been advanced to the point where larger in-
cremental increases in production could be achieved. The nucleus consisting
of people, supporting services, facilities, and experience needed for this
expanded effort will have been established. After 1980, the second generation
extraction-retorting systems would be expected to permit annual additions to
shale-oil productive capacity of about 37 to 73 million barrels per year
(100,000 to 200,000 barrels per day).
In-situ retorting is still in the process of development. However,
by 1985, cumulative capacity, both in-situ and ex-situ, is estimated between
400,000 and 1 million barrels per day, the latter being the most optimistic
prediction from both private and public lands.
Such an oil-shale development would produce both direct and indirect
changes in the environment of the oil-shale region in each of the three states
where commercial quantities of oil-shale resources exist. Many of the
environmental changes would be of local significance. Others (e.g., air
emissions) would be of an intra- and interregional character and have a
cumulative impact. Impacts would include those on water quality, air quality,
ecosystems, habitats, grazing and agricultural activities, recreation and
aesthetic values, and on the existing social and economic patterns.
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II. OIL SHALE DEPOSITS
Location, Classification, and Ownership
Although oil-shale deposits are found in numerous areas of the
United States, the only deposit of adequate size with potential commercial
value at the present time is the Green River Formation shown in Figure 1.
This formation ranges in thickness from a few hundred to about 2,135 meters
(7,000 feet), underlying 44,030 square kilometers (17,000 square miles) of
several Northwestern basin areas in Colorado, Northern Utah, and Southwestern
Wyoming. Location of thick deposits, mainly dolomitic shales and marlstones,
is shown in the figure. In general, the central parts of the Piceance Basin
in Colorado and the Uinta Basin in Utah contain thick, rich oil shale sequences
which grade to thinner and leaner oil shale at the basin margins. Somewhat
thinner and generally lower-grade deposits in the Green River and Washakie
Basins of Wyoming also show decreases in grade toward the basin margins.
The National Petroleum Council's "Other Energy Resources Subcommittee"
has made estimates of energy availability from oil shale. In their
initial appraisal they surveyed the existing work and literature on oil shale
resources and interpreted these in light of Che reserves which may be recoverable
at varying degrees of commercial attractiveness.
Basic assumptions underlying the NFC estimates were:
(a) Only the Green River Formation shales were commercially
attractive.
(b) Reserves will average 60 percent of the in-place resources
and will be recoverable mainly by underground mining.
(c) Early interest will center on zones of shale at least
10 meters (30 feet) thick and yielding at least 125
liters per kkg (30 gal/ton) of shale oil.
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IDAHO
GREAT
DIVIDE
BASIN
WYOMING
Rock Spring
SAND
WASH
BASIN
Salt Lake City
COLORADO
UINTA BASIN
!:H Naval Oil-Shale
Reserves land3
Naval Oil-Shale
[Reserve 2
Battlement
Mesa
Mill Grand
Mesa
EXPLANATION
Area underlain by the Green
River Formation in which the
oil shale is unappraised or
low grade
Area underlain by oil shale
more than 10 feet thick, which
yields 25 gallons or more oil
per ton of shale
FIGURE 1. DISTRIBUTION OF OIL SHALE IN THE GREEN RIVER
FORMATION: COLORADO, UTAH, AND WYOMING
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Classification of Oil Shale Deposits^ '
In-place oil shale resources can be arranged in four classes each
reflecting the degree of commercial attractiveness. These will be described
below.
Classes 1 and 2. In total, these are the resources satisfying
the basic assumption that early interest will be limited to
deposits at least 10 meters (30 feet) thick and averaging 125
liters per kkg (30 gal/ton) of shale oil. Only the most
accessible and best defined deposits are included. Class 1
is a more restrictive cut of these reserves and indicates that
portion which would average 146 liters per/kkg (35 gal/ton)
over a continuous interval of at least 10 meters (30 feet).
Class 3. These are resources which, although matching Classes
1 and 2 in richness, are more poorly defined and not as favorably
located. They may be considered potential resources and would
be exploitation targets at the exhaustion of Class 1 and Class
2 resources.
Class 4. These resources are lower grade, poorly defined
deposits ranging down to 63 liters per kkg (15 gallons per
short ton) which, although not of current commercial
interest, represent a target when their recovery becomes
feasible. These may also be considered speculative resources.
The Mahogany zone in the Piceance Basin allows distinction between
Class 1 and Class 2 resources.* There the resources averaging 146 liters per
kkg (35 gal/ton) over a minimum 10-meter (30-foot) section were determined
from available assay data from Mahogany core tests. Class 1 resources are
Resources are oil shale deposits that are potentially recoverable. Reserves
are the resources available for processing after mining and as assayed by the
Modified Fischer Assay Method (Report of Investigations No 4477, June, 1949,
USBM, Washington, D.C.).
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estimated at 34 billion barrels. The remaining estimated 83 billion barrel
Mahogany resources are designated Class 2, and contain an average of 125
liters per kkg (30 gal/short ton) and have the same minimum section
thickness. The Uinta Basin has been estimated to contain 12 billion barrels
of Class 2 resources.
Assuming that essentially all of the mineable resources will be
recovered by underground mining, it can be estimated that an average of
60 percent of the resources are recoverable reserves after making an
allowance for pillars, barriers between mines, and unforeseen contin-
gencies. Reserves are known for Class 1 through Class 3 resources only.
Class 4 resources appear mainly speculative at this time, and do not merit
consideration as reserves before perhaps the year 2000. Estimated resources
and reserves (at 60 percent recovery) are summarized in Table 1.
As of 1972, only about 10 percent of the total oil shale resources
shown in Table 1 were classified as reserves and about 10 percent of these
were then considered reasonably prospective before 1985. This is probably
a slightly pessimistic view considering the energy supply situation at
present.
Ownership
An estimate of the ownership division of the Class 1 and Class 2
reserves is provided as follows:
Reserves at 60% Recovery
(Billions of Barrels)
Ownership Class 1 Only Class 1 + Class 2
Private Lands 6 17
Federal Lands - Clear Title 7 37
Federal Lands - Clouded Title* 5 20
Federal Lands - Naval Reserve _2 _3
Total 20 77
* Federal lands with clouded title reflect only pre-1920
unpatented claims.
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Piceance Basin
Uinta Basin
TABLE 1. SUMMARY OF OIL SHALE RESOURCES AND RESERVES AS OF 1971
GREEN RIVER FORMATION - COLORADO, UTAH AND WYOMING^1)
(Billions of Barrels)
Location
Resources
Class Class Class
123
Class
4 Total
Reserves 6 601 Recovery
ClassClassClass
123 Total
Colorado
34
83 167 916 1,200
20
SO 100 170
Colorado G Utah
12
15 294
321
16
Wyoming
4 2S6
260
TOTAL 34
95 186 1,466 1,781
20
57 111 188
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It can be seen that 70 percent of Class 1 reserves and 78 percent of Class 1
plus Class 2 reserves are owned by the Federal Government. Thus, the main
segments of reserves are located on Federally owned lands. Therefore,
extensive development of the largest amount of the Nation's oil shale reserve
awaits the further issuance of Federal leasing policies plus the resolution
of title questions on significant parts of the Federal lands.
Of the 20 billion barrels in the Class 1 reserve category, a con-
siderable fraction situated on private lands is available for development.
Of these private lands, a substantial portion need land exchanges with
adjacent Federal holdings to improve workable developments.
Quality of Shale Oil
The quality of shale oil recovered from the Mahogany zone of
the Green River Formations by ex-situ processes typically ranges as
follows: 19 to 28 degrees API gravity, high pour point (75 to 90 F), high
viscosity (300 Saybolt Universal Seconds at 100 F), 0.75 percent sulfur,
(2)
and about 2.0 percent nitrogen. Shale oil produced by in-situ retorting
has a higher API gravity, a lower pour point (9 F), a lower viscosity (41
SUS @ 100 F) and approximately the same sulfur and nitrogen levels. Shale
oil is unlike crude oil in that it contains relatively larger quantities
of nitrogen and oxygen compounds and unsaturates. The subject of shale oil
quality will be discussed in more detail in later chapters of this report.
It is expected that existing petroleum refineries can handle crude shale
oil without major modifications to the refineries.
Associated Minerals
Oil shale consists of largely insoluble solid organic materials
intimately associated with a mixture of minerals including alumina (Al^).
Potential by-products are considered as minor or incidental salable products
-------
resulting from retorting and refining operations and are discussed later
in this report. There is a good possibility of coproduclng alumina and
soda ash in addition to shale oil from the dawsonite- and nahcolite-bearing
oil shale deposits in the north central part of Colorado's Piceance Creek
Basin. Dawsonite [NaAl(OK).CO^] intermingled with oil shale occurs over
an area of 775 square kilometers (300 square miles) in a stratigraphic
section of relatively rich oil shale below the Mahogany zone. The
alumina content in these dawsonite shale beds is low compared to that of
bauxite. However, if satisfactory alumina extraction methods were
developed, the total quantity could be probably more than double the free
world's known supply of alumina. Nahcolite, a naturally occurring
sodium bicarbonate (NaHCCO, is more abundant and more widespread than
(3)
dawsonite in the Ficeance Creek Basin. Depending on production
economics, soda ash could be produced from nahcolite occurring in these
shales either alone or in combination with alumina. However, the
future market for soda ash may not be large enough to accommodate such
large-scale production.
There is great need for research, development, and economic
studies to fully assess the importance of the large mineral deposits
associated with oil shale and environmental studies of the impact of
recovery.
Composition of Deposits
Data on mineral composition of bed samples from the Mahogany
zone, Rifle, Colorado, are reported below. The ash content of raw
shale varied from 59 to 70 percent by weight. The analysis for one of
the ash samples showed: 46 percent silica (SiCO, 4.36 percent ferric
oxide (Fe203), 13 percent alumina (Al^), and 3 percent sodium oxide
(Na~0), with the remainder being magnesium oxide (MgO), potassium
oxide (K.O), and calcium oxide (CaO).
(4)
Spectrographic and chemical analyses have indicated the
presence of trace amounts (about 0.005 percent of each) of arsenic, boron,
barium, chromium, copper, gold, silver, strontium, tellenium, titanium,
-------
10
vanadium, and zinc. It is necessary to investigate whether these will
enter the atmosphere or waterways during processing, and if they do,
whether they are sufficient in quantity to cause environmental damage.
Requirements and Incentives
Requirements for the exploitation of shale oil are listed as
follows:
(a) Environmental protection measures that would be satisfactory
to Federal, state, and local agencies but not so stringent
as to discourage interest by private industry.
(b) Sufficient water supply over the long run so that the
shale oil industry could expand into an extremely large
operation up through the year 2000 and beyond.
(c) Manpower availability for construction of facilities
and continued operation of an industry.
(d) Sound urban construction program to house and support
the new employment which would result from oil shale
development and would have to go forward probably
concurrently with the construction of plants.
(e) The improvement of state and county roads and in some
cases construction of new roads to handle an increased
volume and weight of traffic resulting from increased
industrial activity.
(f) The establishment of increased transportation access to
oil shale areas by the two railroads (the Rio Grande Rail-
road and the Union Pacific Railroad) which now serve the
oil shale areas.
(g) A need for extra pipelines for movement of shale oil from
mining sites to refining centers. Some shale oil may move
west to Salt Lake City and/or Los Angeles; however, it is
-------
11
likely that a good quantity of the oil will move east to
Chicago and other midwestern refining centers. Existing
pipelines would not have the capacity to handle their
regular loads of oil and enlargements would have to be
brought into service to handle the increased quantities
of oil.
Incentives for the exploitation of shale oil can be listed as
follows:
(a) In the face of the present national energy shortage, both
short- and long-term, and the consequent rises in the price
of energy, oil shale development appears more attractive
day by day. Estimated oil shale deposits (equivalent to
600 billion barrels) can provide nearly 100 years supply
of all liquid fuel needs of the U.S.
(b) Development of a Federal oil shale leasing program
stimulating development of oil shale operations.
(c) Present technology, some recently developed, should make
oil-shale mining and oil recovery economically feasible.
Also, if shale-oil recovery begins, technological
improvements would most certainly come about.
(d) The development of an oil-shale industry will eventually
help the nation to become less dependent on imported
sources of fuel.
-------
12
III. MINING. HANDLING. AND PRETREATING PROCESSES
Two major oil-shale recovery options are under consideration for
development: (1) underground mining (by adit or horizontal entry) followed
by surface processing (ex-situ retorting) of the oil shale and (2) in-situ
(or in place) processing. Of the two options, only the surface mining
approach is believed to be advanced enough to enable scale up to commercial
production by 1980. The relative state of knowledge of the various operations
involved in oil-shale processing is shown in Figure 2. The refining
operations shown in Figure 2 would be performed outside of the oil-shale
region at refinery centers located near markets for the final products. It
is apparent from Figure 2 that various technical options are available for
each phase of the operations.
There also is a third option, viz., surface mining - surface
processing. Surface mining, similar to strip mining of coal, has serious
disadvantages. Also, not many of the oil-shale tracts are amenable to
surface mining. Hence, at the present time, this oil shale extraction
method is receiving less attention.
Until recent years, virtually all efforts to develop oil-shale
technology were directed toward conventional mining, crushing, and ex-situ
retorting. Oil-shale processing in this manner requires considerable
materials handling activities. Recently In-situ processing has been
receiving attention and will be discussed in the next chapter.
Process Description
Mining
Neither surface nor underground oil shale mining methods differ
greatly from conventional coal mining methods. Surface mining, usually
termed open-pit or strip mining, requires removal and disposal of whatever
overburden is present, followed by mining of the underlying oil shale in a
quarry-like operation.
-------
(3A) NATURAL
(2C) HYCRAUUC
(2C) ELECTRO -
(2C) OCM. EXPLOSIVE
(3B) NUCLEAR
(2 A) IN-FORMATION \
(3C) NUCLEAR CKMNEYj
(2C) GAS DRIVE
(2C) ARTIFICIAL LIFT
M-SfTV (2*3)
OIL SHALE DEPOSIT
_l, il_
J
CONVENTIONAL (2)
I
FRACTURING
RETORTING
PRODUCT
RECOVERY
MINING
f COMBUSTION (2C)
{ HOT GASES (2A)
L STEAM (3A)
[Room 8 Pillar (i A)
[UNDERGROUNDjCur and Fill(3B)
loPEN PTTC3B) I*K* coving (38)
CRUSHING do
RETORTING
(1C) THERMAL a CHEM. TREATING
REFINING
S8SL-
Stale of knowledge applicable to oil state
I. Reasonably well demonstrated
2. Some experimental knowledge
3 Little known
4 Conceptual
- with knowledge stemming from :
A. Shale experience
B Petroleum or other nJustry
experience
C Both
C^CCMJLST1C«{S^"A>
UNION (IA) VWrosixKA)
TOSCO (I A)
HYDROGEN ATMOSPHERE (3A)
(Alumia (2A)
fUTILIZE( Soda Ash (2A)
(DISPOSE (Mine fill (3B)
Revegetote (2A)
I Dump
BY-PRODUCTSU
(1C)
GASOLINE
DIESEL FUEL
JET FUEL
DISTILLATE FUEL OIL
RESIDUAL FUEL OIL
LIQUEFIED PETROLEUM GAS
AMMONIA (1C)
SULFUR (1C)
AROMATICS(2A)
SPECIALTIES (3A)
COKE (1C)
PITCH (1C)
ASPHALT (1C)
WAX (2A)
FIGURE 2. SOURCE, RELATIVE STATE OF KNOWLEDGE AND SPECIFIC
PRODUCTS DERIVED FROM THE OIL SHALE PROCESSING CYCLE
(5)
-------
14
The greatest amount of actual experience in mining oil shale has
involved underground mining techniques. Major advances in underground
mining of oil shale were achieved by the Bureau of Mines in its oil-shale
program during 1944-1956. The state of technology as reviewed by the
/2 g\
Bureau of Mines in 1970 is quoted as follows :v '
"An underground mining method for oil shale was developed
and demonstrated by the Bureau of Mines at its oil shale
facility near Rifle, Colo., during 1944-56. A "demonstra-
tion mine," sometimes referred to an an underground quarry,
was opened in a 73-foot minable section of the Mahogany
zone to demonstrate the feasibility of room-and-pillar
mining methods, to develop and test equipment, and to
determine whether low mining costs and high recovery were
possible. A two-level operation was adopted: a top
heading, 39 feet high; and a bench, 34 feet high.
Room openings and roof-supporting pillars were both 60-feet
square. An extraction ratio of 75 percent head and side
space thus was sufficient to permit the use of large portable
diesel and electrically driven mining equipment, thereby
obtaining a high output per man-shift. An average of 150
tons per man-shift was achieved for sustained periods during
normal operating tests. Special equipment developed for mining
the high faces included drilling jumbos, a rotary drill for the
benching operations, explosives-loading platforms, scaling rigs,
and a mobile compressor and utility station. An electric shovel
with a 3-cubic-yard dipper was used to load the broken shale.
Diesel-powered dump trucks were used for haulage. Subsequent
shale work by industry has followed in general the mining method
demonstrated by the Bureau, but has incorporated equipment
modernization and improvements in techniques.
If an underground oil shale mining operation were to be under-
taken in the near future, it could be expected to incorporate
improvements over the Bureau's demonstration mine, such as the
following: changing to rotary drilling in the mine heading as
well as in benching; blasting with a more economical explosive,
such as an ammonium nitrate-fuel oil mixture; use of modern
haulage and loading equipment, and other improvements based
on recent advances in quarry and open pit mining engineering.
Also, in the interest of safety, a retreat system might be
used instead of the advance system that was demonstrated."
Room and pillar mining techniques have been improved through subsequent work
by Union Oil Company (1956-1958), Colorado School of Mines Research Foundation
-------
15
(1964-1967), the Colony Development Corporation (1965-present). In
/2)
considering the future, the Bureau of Mines stated:
"The room-and-pillar mining system is the only one that
has been tested on the oil shales of the Green River
Formation. However, open pit mining, highly developed
for mining other ores, probably will be practical for
oil shale in areas where conditions are favorable.
Among the considerations that would be important in
selecting a suitable site would be the availability
of a satisfactory area for storing the overburden and
the ratio of the overburden to the shale to be mined."
As regards surface mining methods for oil shale, very little informa-
tion is available because so little experience has been gained in this area.
However, these methods should not differ much from the coal strip mining or
hard-rock open pit mining in its major aspects.
Whatever the method of mining, disposal of spent shale after surface
retorting will present problems. Proposed disposal methods are underground
mining with either underground disposal or surface disposal, and surface
mining (strip or open-pit) with backfill.
Orehandling and Pretreatment
A schematic of the underground mining and associate surface
oil shale processing units is provided In Figure 3. As seen, the operation
requires primary, secondary, and sometimes tertiary crushers. Dust from
crushers may be led through hooded systems and collected for proper disposal.
Mine water which Is of very low grade must be treated and properly disposed.
Detailed data on effluents or emissions are not available and are thus
suggested as areas for further research.
State of the Art
The state of the art of shale mining as regards underground mining
is akin to underground coal mining. However, the art of surface ore
handling operations is not very well defined nor advanced. The reasons
are obvious; there has not been sufficient impetus for advancement.
Present energy shortages and associated increases In liquid fuel costs
-------
IS
$
0)
c
v
a.
E
Makeup natural
Oil shale
73.700 tons/cd
Secondary crushing
and sizing plant
Dust from
crushers
and sizing
operations
1.000 tons/cd
Oil shale
72.700 tons/cd
Retort water
150,000 to 350,000 gal/cd
I
I
Retorting
plant
Raw shale oil
53.500 bbl/cd
Oil
upgrading
plant
(refinery)
Upgraded oil
50.000 bbl/cd
Sulfur, 43 tons/cd
Ammonia. 138 tons/cd
Coke, 855 tons/cd
*
Waste water
recovery system
T
Spent shale and dust
58.960 tons/cd
(dry weight)
I
| Refinery waste water
| 100.000 gal/cci
4 Makeup water from
other Plant sources
plus fresh water
as needed
Waste water
recovery system
*• --
Spent shale disposal
in-mme and/or surface
FIGURE 3. FLOW DIAGRAM OF 50,000-BARREL-PER-DAY UNDERGROUND OIL
SHALE MINE AND PROCESSING UNIT
-------
17
have spurred the need for oil-shale industry growth. Consequently, there
is now sufficient incentive for development of modernized methods of surface
treatment of ore. Proper environmental controls should be instituted
after careful deliberations in this area of shale processing.
Nature of Products
The only product from the mining and ore handling operations is the
prepared oil-shale of size and grade suitable for charging to retort for oil
recovery. Some retorts like the TOSCO retort can handle all fines very
efficiently. For such retorts briquetting of fines is not necessary. Greater
than 90 percent of mine-run shale (before crushing) is larger in size than
one-inch. The required size for different retorting methods is not clearly
defined in published data. However, the smaller the size required the greater
the chances of dust emissions during crushing. Some types of retorting can handle
minus -r inch shale while others (TOSCO) need 7-, inch or smaller. The limited
nature of available data does not permit a detailed evaluation of this aspect.
Environmental Impacts
The major environmental impacts resulting from oil-shale
handling and pretreatment are discussed below.
The generation of dust from crushing and associated operations
and from the transportation of ore to the crushing facilities is the
major Impact on air. In the case of an underground mine, the primary
crushing and grinding facilities would almost certainly be located in
the mine as soon as enough space was developed to make it possible.
It has been estimated that in the case of surface processing (crushing
and screening) overall dust losses would be 1.3 percent of the shale
handled. Except for an estimated 16 kilograms (35 pounds) per hour of
dust actually lost to the atmosphere as true airborne particles from a
50,000 barrel/day plant, the dust loss from the process flow streams
would be collected periodically, dampened, and disposed of with spent
shale from the retorting plant.
-------
18
Figure 4 shows some of the surface ore handling operations
necessary prior to charging the oil shale to the retort. Since the
equipment used comprises conventional crushers and screens, control of
fugitive dust from this equipment can be achieved by employing suitable
hooding and dust control techniques. It is estimated that this method
may significantly reduce the 1.3 percent dust emission to less than 0.2
percent.
It is conceivable that with the full scale development of the
oil-shale industry, even the lowest dust emissions could cause health
problems to the immediate populace due to the high mineral content (70
percent) of the dust. This area needs investigation.
-------
Receiving hopper
Primary crushing
3p?0 toh ^^--\^_
H
fc = = ^!' ^
From tertiary^ N.
crusher ) "' ' ' Jt_^
Ji)bU ipn. ]• ;
-3°in. "^-^W
Surge storage
screen
"t
| i Vibratory feeder
k /x^Pnmary crusher Secondary crushing
rMr
^_W' | -105Lfi. 4
* Vibratory feeder I
l_r\J >^ Grizzly bar /
HD DDD^/ screen /x
fsSi**^ /!!^\ Crusher //
\/ [Sr*^ '
I JT /
\_S\_/\_f To retorting plant ZglStph
\ i r
\ / T "0 tph. -3/16in.
^^J L J ''' \ / .' \ /Vib
1 '"v ^, i ^L/
* ,^a yQIDx / OjCr
Tertiary crushing
PSO tph. -4 S in.
1
/\ Vibratory feeder
Lr XJ .^
OH ™' • Grizzly bar screen
/«^\ /^^ ^Crusher
\^ I TO storage
. i i i hopper
' 3j030tph.
^
ratory feeder / \ /
I tpn «,To retorting
Vibratory feeder^ r^T] k' i Briqucttmg Briquettes ; planl
'-W-1 ^ JL, machine , 3,030 tph
C^,
Screening plant Bnquetting plant Mlxer
*LJ
vo
FIGURE 4. CRUSHING, SCREENING, AND BRIQUETTING PLANTS - SCHEMATIC FLOW DIAGRAM
(Two Identical Plants)(5)
-------
20
IV. IN-SITU METHODS OF OIL RECOVERY
In-situ experiments have been conducted by private companies and
the Bureau of Mines for a period of years. ' This process involves under-
ground heating by such means as combustion in the formation, introduction
of hot natural gas, and introduction of superheated steam. However, tech-
nology has not yet developed to warrant prediction of its technical or
economic success.
Process Description
A key problem is the creation of permeability within the shale
matrix. Two major approaches are in the early stages of investigation. One
approach proposes limited fracturing by conventional means (electric,
hydraulic, and chemical explosives) whereas the other proposes massive
fracturing by a nuclear explosion.
A design concept for conventional in-situ retorting based upon
contemporary petroleum technology is shown in Figure 5. The essential steps
include: (1) well drilling, (2) fracturing to permit heat transfer and
movement of liquids and gases, (3) application of heat, and (4) recovery of
products.
Remote control from the surface of the in-situ process with sufficient
accuracy through wellbores is a problem still unsolved. The state of the
art reviews some of these problems.
State of the Art
Sinclair Oil and Gas Company (recently merged into Atlantic
Richfield Company) experimented with conventional in-sltu retorting of oil
shale in 1953 and 1954 at a site near the southern edge of the Piceance
Creek Basin. From these tests it was concluded that communication between
wells could be established through induced and natural fracture systems,
that wells could be ignited successfully although high pressures were
-------
AND RECIRCULATED
GAS INJECTION
EMPERATURE
PROFILE
FIGURE 5. SCHEMATIC REPRESENTATION OF AN IN-SITU RETORTING OPERATION
(5)
-------
22
required to maintain injection rates during the heating period, and that
combustion could be established and maintained in the shale bed. Over
a period of several years in the mid-1960*s, Sinclair conducted field
research on the in-situ process at a site near the center of the Ficeance
Creek Basin where the shale was much deeper and thicker than it was at the
site of the first experiment. The results of this experiment were not
promising; fracturing techniques that were used did not produce sufficient
fa q\
heat transfer surfaces for successful operation. '
Also in the 1960's Equity Oil Company conducted field experiments
on in-situ processing of oil shale in the Piceance Creek Basin. The
process employed the injection of hot natural gas to retort the oil shale
rather than using underground combustion. However, the experiment suffered
large gas losses to the formation.
Several less extensive investigations of the in-situ technique
have been conducted by various oil companies during the last ten years,
but very little has been published concerning the results achieved.
The possibility of utilizing a nuclear explosive to fracture oil
shale in preparation for in-situ retorting has been under consideration
since 1958. A feasibility study for a nuclear experiment was proposed for
the Piceance Creek Basin. Later a similar experiment was proposed for the
(12)
Uinta Basin. Neither of these experiments is being actively considered
at the present time. The lack of firm data precludes further analysis of
this technique at this time. If such a project is proposed on public lands,
it will require a complete environmental analysis, including the preparation
of an environmental impact statement specifically addressed to this subject.
Factors that must be considered, such as ground motion and containment of
radioactivity released from the explosion, have been discussed in detail
in the concept documents referenced above. '
A commercial in-sltu processing system has not been demonstrated
to date, but a number of field-scale experiments involving wellbores from
the surface have been conducted by government and industry during the past
20 years.
-------
23
Two major problems encountered from such processing are:
(1) insufficient naturally occurring permeability or failure to artificailly
induce permeability so as to allow passage of gases and liquids, and
(2) inability to remotely control the process with sufficient accuracy
through wellbores from the surface. Besides surface wellbores, other
methods proposed for introducing heat underground include mine shafts,
tunnels, and fractures created by a variety of techniques.
It is obvious that considerable further technological improvements
must be made before industrial-scale, in-situ recovery of shale oil could
become a reality.
Nature of Products
Available information suggests that oils from in-situ retorting
may be somewhat superior in quality to those produced from surface
retorting. Specifically, they appear to have lower pour points, viscosi-
ties, and nitrogen contents. This is illustrated by comparing the data
(13)
shown in Table 2 with data on characteristics of ex-situ recovered
oil as presented in Tables 5 and 7 of Section V. In-situ oil may be
marginally suitable for transporting without upgrading because of the
low pour point; however , no firm conclusions are possible because of
insufficient data.
Gases produced in the gas/oil separation step would have the
(13)
characteristics shown in Table 3. These data indicate that nearly 95
percent of the gas components have no value as fuel. From these scant
data, it can be said that in-situ retorting does not generate gas which
is useful as fuel. However, since the gases will be hot and have some
fuel value, it may be possible to recompress the gases and use it for
in-situ retorting by pumping into formations.
Data on the concentration of dust in gases are not available.
Process Efficiency
Very little data are published on the efficiency of the in-situ
process. If some guesses may be made, since in-situ retorting is so unlike
-------
TABLE 2. CHARACTERISTICS OF OILS FROM IN-SITU RETORTING
(13,27)
Gravity, API
Sulfur, wt %
Nitrogen, wt %
Pour Point, F
Viscosity, SUS @ 100 F
(a)
Bureau of Mines
31.7
0.67
1.35
+5
41.0
Sinclair
30.6
1.28
1.14
+35
—
Equity
-------
25
TABLE 3. CHARACTERISTICS OF GASESFROM IN-SITU RETORTING
Component Concentration, mole percent
Nitrogen 77.2
Oxygen 10.1
Propane 0.2
Carbon Dioxide 9.9
Carbon Monoxide 0.8
(c)
Hydrogen Sulfide NRV '
Butanes NR
Methane 1.2
Ethane 0.6
(a) Heating value approximately 30 Btu/scf. Yield from
operation at level of 50.000.bbl/CD. Upgraded shale
oil approximately 1,485 x 10 scf/CD.
(b) Concentrations reported on a water-free basis.
(c) NR: Not reported.
-------
26
the ex-situ, in that It does not require crushing, grinding, screening and
associated process and pollution control equipment, the overall economic
efficiency should be higher if a cheap means of fracturing and mine retorting
can be found. Nuclear energy may represent this cheap means, but the
adverse environmental consequences of nuclear fracturing are still not
evaluated.
Losses of agents injected to promote underground combustion have
been common. In addition, the recovery of the oil content of the shale will
not be as high as in ex-situ retorting. These factors will hinder full
resource utilization.
In summary, the state of the art of in-situ processing is very
elementary and it is too early to make any judgments.
Environmental Considerations
In-situ recovery of oil does involve considerable above ground
activity. A conceptual scheme for the Wyoming tract in-situ operations, shown
in Figure 6, illustrates the dynamic nature of in-situ processing. It is
estimated that the two tracts would require multiple rows of 100 wells, which
would be drilled on a monthly basis. Five rows of wells (100 each), comprising
restoration, plugging, injecting, producing, and drilling operations, would
consume about 115 acres of active area at any one time. This active area
would progressively move forward as new wells were drilled. It would take
approximately 3 years for restoration to be complete.
Impacts on air and solid waste by in-situ processing cannot be
estimated until the status of development of the processes is such as to
provide data on products, by-products and wastes produced. It will be
necessary to hold direct conversations with developers of in-situ techniques
and visit in-situ testing facilities to obtain first hand understanding of
the problems associated with In-situ processing. From such an understanding
reasonable estimates of environmental impacts can be made and steps taken to
insure minimal adverse environmental impacts.
-------
27
/
O
0
©
0
0
.••-.
0
8
0
0
O —
0 —
®~
O —
0 —
-1U.UUU II.— — *•
« ' /
Restoring — • C; /
Plugging — » 0
Injecting — • ® ^
Producing — • O /
Drilling — O /
n — j. ,
t
o
C3
1
area
..;/!/(? Area undergoing .fy'.'v?'•'.'•;.
/
/
/ /
/
/ /
/
Active area 115 acres
—I
Undeveloped area
Scale, miles
FIGURE 6. WYOMING W-a AND W-b IN-SITU RECOVERY -
CONCEPTUAL DEVELOPMENT APPROACH(5)
-------
28
V. 1-.X-SITU RETORTING
Above ground thermal processes for extracting crude shale oil from
mined shale are divided into four types according to the method of heat
transfer.
Type 1. Indirect heating through the wall of the retorting
vessel. (There are no active processes in this
category.)
Type 2. Direct heating by hot gases through combustion
within the retorting vessel.
- Gas-Combustion Process (Bureau of Mines)
- Union Oil Process (Union Oil Company of California)
Type 3. Heat transfer from an externally-heated carrier
fluid.
- Petrosix (Cameron and Jones Vertical Kiln)
Type 4. Heat transfer from recycled hot solids.
- TOSCO Process (The Oil Shale Corporation).
Each type is analyzed by comment on the following aspects: (a) process
description; (b) state and scale of current development, i.e., pilot plant,
prototype, or commercial scale; (c) products and yield of shale oil produced
and physical properties of the crude oil; (d) thermal, yield, and economic
efficiencies; (e) pollution aspects of the preretorting, retorting, and
post-retorting operations; and (f) expected commercial utilization.
The various retorting procedures for extracting shale oil
generally consist of three steps as follows:
1. Preretorting - consists of operations such as
crushing, screening, brlquetting, and suitable
sizing of oil shale for charging to retorting
units.
2. Retorting - consists of heating the oil shale to
or above the pyrolyzing temperature, approximately
480 C (900 F), separation of oil from the retort
gases, removal of spent oil-shale residue from
the retort and preparing the heat transfer medium for
-------
29
recycle. In some types of retorting, a heat transfer
medium is not employed; instead, low Btu gas from the
retorting step is used for direct firing of the retort.
3. Post-retorting - consists of upgrading of the crude
shale oil obtained in Step 2. Usually thermal and/or
hydrogenation methods are employed for upgrading.
(8)
Heat required for retorting is estimated in one process to be
1.4 million Btu per ton of oil-shale charge. Better heat transfer techniques
can reduce the heat requirement, thus the classification on the basis of
the method of heat transfer employed. A general schematic of a retorting
system is provided in Figure 7.
Gas Combustion Process (Type 2)
Process Description
The Bureau of Mines gas combustion retorting process is charac-
terized by its use of continuous gravity flow of shale and direct gas-to-solids
heat exchange by a heat source from Internal combustion. The essentials of
the process are illustrated in Figure 8. The retort is a vertical, refractory-
lined shaft equipped with shale and gas-handling devices. Crushed and
sized shale, (approximately 0.25 to 3 inches, 0.7 to 7 cm), moves downward
as a bed through the retort vessel, entering through the product cooling
zone where some of the organic matter is decomposed by heat to liberate oil
vapor and gas. A carbonaceous residue from the decomposition reaction remains
as part of the shale particles. The shale next proceeds to the combustion
zone, where sustaining heat for the process is produced by burning the organic
residue on the shale at temperatures of 480-760 C (900-1400 F). A part of
the product gas is returned to the system to provide heat for the retorting
zone. From this hot zone, the shale moves down through the heat recovery
zone where its heat is transferred to the rising stream of recycle gas. The
cooled, spent shale (of approximately the same physical size as the charged
shale) at about 94 C (200 F) is mechanically discharged from the retort at
a controlled rate.
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30
Oil shale from crusher
505 tons/hr
/ °*
f
Feed conveyor
Feed
hopper
Basis: 1 retort
Electrostatic
precipitator
'rRecycled gas
I 1.35 x 106 scf/hr
Air 2.27 x 106 scf/hr
To plant fuel system
4.04 x 106 scf/hr
370 bbl/hr
Recycled gas 5.72 x 10& scf/hr
\. \ Spent shale 410 tons/hr
FIGURE 7. SCHEMATIC FLOW DIAGRAM OF RETORTING SYSTEM
Note C: Compressor
P: Pump
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31
Raw shale
a a
a Product cooling a
zone 0
Product
oil
0 Heat recovery *
a zone *
4 .
<» * '
*'* V
;K
Recycle gas
Product gos
T
Retorted shale
FIGURE 8. BUREAU OF MINES GAS COMBUSTION PROCESS
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32
Recycle gas is injected at the bottom of the vessel and rises through
the spent shale in the heat recovery zone. An air distribution device is
located near the center of the retort where air, diluted with part of the cir-
culating retort gas, is injected. This mixture is heated quickly by contact
with the hot spent shale. In addition, reaction of the oxygen in the gas with
combustibles produces a hot flue gas. The hot flue gases, recycle gases, and
CO. from the decomposition of certain carbonates in the shale rise in contact
with the descending raw shale in the retorting zone, and the solids are
heated enough to effect thermal decomposition of the kerogen in the shale.
In the product cooling zone, the oil in the gas stream is cooled below its
dew point, condenses as a fine mist or fog, and is carried out of the top
of the retort.
The overhead stream from the retort passes first through oil-
mist separators to recover the shale oil. The oil-lean gas enters a
blower and is divided into three streams. One stream (dilution gas) Is
Injected with air into the center of the retort. A second stream (recycle
gas) enters the bottom of the retort. The remainder (net product gas) is
(2 5)
vented from the system. '
Status of Development
Working under the Synthetic Liquid Fuels Program, the Bureau
of Mines developed the gas combustion retort after an extensive pilot-
plant study of batch-type and moving-bed retorts. The first gas
combustion unit was a 5.4 kkg/day (6 ton/day) pilot plant built in 1950
which was followed by construction of a 22.7 kkg/day (25 ton/day) pilot
plant and a 136 kkg/day (150 ton/day) demonstration plant. These units
were operated on a development and demonstration basis until they were
put on a standby status in 1955.
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33
The Anvil Points facilities were reactivated in 1964 for further
process studies under a lease agreement with the Colorado School of Mines
Research Foundation. Six petroleum companies sponsored this project both
financially and technically. These were Mobil Oil Corporation, Humble Oil
and Refining Company, Pan American Petroleum Corporation, Sinclair Research,
Inc. (Atlantic-Richfield), Continental Oil Company, and Phillips Petroleum
Company. Their operation extended over a period of 3 years from 1964-1967.
They demonstrated that yields in excess of 85 percent of Fischer assay could
be obtained at feed rates of 226 kg/hr (500 Ib/hr) per square foot of bed
cross-sectional area. This was about double the rate previously demonstrated
(14)
by the Bureau of Mines. This expansion in capacity resulted in a large
retort capacity of 326.5 kkg/day (360 ton/day). Commercial production at
(2)
the 50,000 bbl/day level would require 6 individual retorts of 458 kkg/hr
(505 ton/hr) capacity. Therefore the existing state of development is close
to the ultimately required process equipment. The additional research indicated
that a material advance in processing technology had been accomplished. Some
operating problems associated with scale-up are still unresolved, e.g., even
downward flow of shale in large diameter retorts and prevention of channeling
of the rising gases are still problems.
Nature of Products
Oil. Yields from the large 136 kkg/day (150 ton/day) demonstration
unit dropped by about 8 percent below the yields of 94-95 percent obtained
(4)
in the 5.4 kkg/day (6 ton/day) plant. The larger demonstration plant at
shale feed rates up to 326.5 kkg/day (360 ton/day) averaged yields of 82-87
percent. Although examination of the retorted shale indicated that
retorting efficiency was high, a study of product oil indicated that the lower
efficiency was the result of more extensive secondary cracking of the oil
produced in the larger scale unit.
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34
Crude shale oils produced from surface retorts may generally
be classed as low-gravity, moderate-sulfur, high-nitrogen oils compared
to petroleum crudes. Generally shale-oils are more viscous, higher pour
point (congealing temperature) oils than many petroleum crudes. Oils differ
by different retorting methods; properties of the oil produced by the
gas combustion process are noted in Table 4.
Gas. The retort gas produced from the gas combustion process
is diluted with the products of combustion, carbon oxides from the
decomposition of carbonates in the shale, and inert components of the air
introduced to support combustion.
Characteristics and yields of untreated retort gas typical of
this internal combustion process are presented in Table 5.
Spent Shale. The spent oil shale has relatively low carbon
residue (approximately 3 weight percent), and is of approximately the same
size, 0.6 cm (0.25 inches), as the charged shale. Some of the shale,
of course, will be crushed as the shale moves downward through the
retort, and the resulting fines will be entrained with the rising gas
stream and carried off with the product vapors. The large size of spent
shale will facilitate ease in transportation and ultimate disposal and
will require less water for dust control during the disposal operation.
The gas combustion process can be said to have an advantage as far as
spent shale size is concerned.
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35
TABLE 4. PROPERTIES OF CRUDE SHALE OIL PRODUCED BY
THE GAS COMBUSTION PROCESS(5'
Gravity, API 19.7
Sulfur, wt % 0.74
Nitrogen, wt % 2.18
Pour Point, C (F) 28 (80)
... .. Centistokes at 38 C ,, o /or
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36
Process Efficiency
Thermal Efficiency. The gas combustion process internal
temperatures rise above 480 to 760 C (900 to 1400 F) in the area of the
combustion zone. The dolomite (CaCO.'MgCO.) in oil shale begins to
decompose somewhat below 540 C (1050 F) yielding magnesium oxide, carbon
dioxide, and calcite. The calcite (CaCO.) - both that in the oil shale
and that produced by the dolomite decomposition - begins to dissociate
in the range of 620-650 C (1150 to 1200 F). In addition, other compounds,
e.g., nahcolite (NaHCO^), also decompose at these temperatures.
All these reactions are endothermic, and their decomposition places
additional heat demands on the gas combustion process, ultimately
lowering its overall thermal efficiency. Specific values for thermal
efficiency are not presently available.
Product Yield. The yield of oil produced from the small pilot plant
was about 95 percent; the yield on the large 136 kkg/day demonstration size
unit fell to about 87 percent and to 85 percent in the 326.5 kkg/day plant. This
yield relationship extrapolated to commercial scale (50,000 bbl/day) indicates
a further drop to 78 percent of Fisher assay. In addition to the lower oil
yields, the vertical kiln configuration will force lower raw shale utilization.
In order to avoid an excessive pressure drop when forcing the hot gases through
the shale bed, it will be necessary to limit the particle size to 1.3 cm (0.5
inch) or larger. The expansion to commercial scale retorts will increase this
minimum particle size, necessitating the exclusion of fines and an auxiliary
briquetting operation. In either case the inability to accept all sizes of
shale input, especially fines, must be considered an economic weakness of
the gas combustion process.
Coats. The efficiency or inefficiency of the gas combustion
process will ultimately reflect in the capital and operating costs. The
lower yields reported (and predicted) for oil produced and the poor shale
utilization will dictate higher mining expenditures, construction of
larger, more expensive retorting units, and necessitate raw material
wastage or additional auxiliary operations. The dilution of the product
gases with both combustion and decomposition gases will require all or a
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37
very large percentage of the retort gas to be recycled for internal heating
purposes; and gases which are available will be of a somewhat limited use.
Therefore, additional energy sources for other heat-requiring operations
seem to be needed to operate the facility.
Since water is not required for cooling or elsewhere, this process
•will be efficient in the water demand sense. Some water will have to be
imported for use in shale disposal. However, since the crushed and final
retorted size of the shale will be relatively large, the increase in specific
volume of the retorted shale is not excessive; therefore, the water require-
ments and the disposal area necessary will be somewhat minimized.
No estimation of capital or operating costs for retorting facilities
utilizing the gas combustion process is available.
Environmental Considerations
Preretorting. The main influence the gas combustion process will
have on the preretorting facilities will be the input particle size. As
noted earlier, the chunks of oil shale must be larger than a minimum size
of about 1.3 cm (0.5 in.) for efficient operation. The effect will be to
allow the crushing, screening, and conveyance of relatively large pieces of
oil shale to be accomplished with a minimum of air pollution (dust). How-
ever, this same minimum size requirement could lead to the creation of a
solid waste problem (oil shale fines) if the fines are not compacted for
use, since use of fines as such in this process is difficult.
Retorting. The retorting operation produces a gaseous stream
containing the crude shale oil and other gases. This overhead stream has
value as a fuel source; hence, this stream must be economically and adequately
controlled. The particulates in the gases can suitably be removed. Most
of the gas stream is recycled to the retort. Commercial considerations
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38
generally envision the product gas being used as a fuel for generation of
power and process stream. Regardless of the manner in which the retort
gases were burned to utilize their fuel values, sulfur control would be
required to meet air quality standards. In this regard, existing methods
of treatment for gas desulfurization can be investigated. The sulfur con-
centration in the gas combustion process gases are so low that desulfurization
may not prove economical. This aspect needs careful investigation.
From the bottom of the retort, spent oil shale will be discharged.
This discharge will be large (51,700 kkg/day or 57,000 ton/day), hot (94 C,
or 200 F), and likely to be associated with steam and other minor gaseous
emissions. Special provisions will be needed to avoid air pollution while
transporting the spent shale, and its environmental, economic, and technical
aspects will be discussed in greater detail in another section of this report.
Expected Commercial Development
The gas combustion process, although not the most advanced, has
several positive factors supporting possible commercial development. The
Bureau of Mines has operated a large demonstration scale unit. Years of
extensive process development have gone into the refinement of this process.
Such development has not advanced to the degree where reasonably accurate
scale-up to a commercial sized facility, employing multiple units, is
possible. The gas combustion process is the most advanced government
sponsored oil shale retorting process. In addition to Federal support, six
major oil companies have invested significant quantities of time and money
into the further development of this process. As displayed by the current
levels of bidding for Federally owned oil shale tracts ($210.3 million
for the right to experimentally develop the first 2065 hectare* tract)
* About 5000 acres.
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39
significant interest has now been placed by the major oil companies in the
oil shale resources. Plans for a 50,000 to 100,000 bbl/day facility (employing
this and other retorting methods) are now being prepared.
The Union Oil Process (Type 2)
Process Description
The Union Oil Company of California retorting process is characterized
by its use of an under-feed flow of shale, direct gas to solids countercurrent
heat exchange, and heat supply by internal combustion. The essentials of the
process are illustrated in Figure 9. The retort is a vertical, refractory-
lined conically shaped kiln equipped with a unique shale charging device, and
gas handling equipment.
Crushed, sized, and screened shale of a maximum size of 12.7 cm
(5 in.) and a minimum of about 0.3 cm (0.1 in.) are fed from the bottom of
the retort by means of a "rock pump". Hot gases and air are pulled downward
through the shale bed by suction blowers. No water is required by this
retorting process.
The actual mechanism of the retorting process is described below.
The processes occurring in the kiln's retorting section may be divided into
three zones. In the top zone, heat exchange between incoming air and hot
clinker leaving the unit is effected. In the lower portion of this top zone,
the carbon residue on the spent shale is burned, producing flue gas with a
temperature near 1093 C (2000 F). This flue gas is drawn downward into the
retorting zone, where the shale is heated to retorting temperature and oil
vapors and gas are evolved. The mixture of shale oil vapors and flue gases
progresses downward into the condensation zone, where the incoming raw shale
is heated and the retort products are cooled and the oil is condensed.
The unique difference between the Union Oil process and the gas
combustion, process (both use internal combustion retorts) is the method in
which the raw shale is charged to the system. Operation of this unique feed
mechanism facilitated by the rock pump is illustrated in Figure 10. In Step 1
a hydraulically-operated piston retracts and the feeder cylinder fills with
-------
• CHUTE CARRIES AWAY
SHALE ASH AS IT
SPILLS OUT TOP
OIL AND GAS TO
RECOVERY EQUIPMENT
OSCILLATING "ROCK PUMP
PUSHES OIL SHALE UP
THROUGH RETORT
ZONE IN WHICH HOT
GASES HEAT SHALE
TO CONVERT "KEROGEN"
TO OIL
T /-CRUSHED OIL SHALE
/ FED IN BY CONVEYOR
FIGURE 9. UNION OIL RETORT
(5)
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41
rtCB CTI.MM*
STEP I
STEP
STEP 3
STEP
FIGURE 10. ROCK PUMP FOR UNION OIL RETORT
(5)
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42
raw shale from the feed hopper. In Step 2 the feeder unit is rotated to
a vertical position under the retort by means of the oscillating cylinder.
In Step 3 the piston is extended forcing the shale into the retort, and
(Step 4) remaining in the extended position, the piston is rotated back
to the feed hopper ready to repeat the operation.
Status of Development
The Union Oil retort design was developed during the late 1940's
by construction of a 1.8 kkg/day (2 ton/day) plant followed by a 27 kkg/day
(30 ton/day) pilot plant. In 1956 a demonstration plant was built on the
company's oil shale properties in Parachute Creek, Colorado.
A further increase in experimental capacity was completed in March,
1957. The original demonstration plant retort, having a feeder piston diameter
of 1.7 m (5.5 feet), was designed for a capacity of 326 kkg/day (360 ton/day).
Further development and demonstration of the facility through August, 1958
allowed throughput rates to be increased to as high as 1088 kkg/day (1200
ton/day). Operation at rates near this level was obtained on an automatic
control basis for continuous periods up to six weeks.
The research facility was closed in 1958, but by that time Union
Oil was sufficiently satisfied with the success of the experiments. Published
reports in 1959 stated that^ '
"We (Union Oil) have firmly established the retorting
technology to design and operate a single retort with a
throughput capacity of up to 1700 tons of oil shale rock
per day. Further, we believe that a single retort with a
capacity of 3,000 tons/day is a reasonable extrapolation."
Individual retorting units having capacities of 9070 kkg/day (10,000)
tons/day) or larger are envisioned to be the appropriate size for commercial
scale retorting plants. Therefore, the existing scale of development was
about one sixth the expected commercial size. No reports of recent develop-
ment (after 1959) of this technology have been released. However, the company,
again active in the oil shale development area, has announced that larger
equipment could be designed and constructed whenever the energy demand and
economic conditions warrant it.
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43
Nature of Products
Oil. Yield of oil extracted from oil shale has not been reported
for this large-scale UOC plant. However, the yield may be estimated as
5-10 percent below the 102 percent obtained in the original investigation.
Properties of the shale oil from the original Union process are noted in
Table 6.
TABLE 6. PROPERTIES OF CRUDE SHALE OIL PRODUCED BY
THE UNION OIL RETORT "A" PROCESS^5)
Gravity, API 20.7
Sulfur, wt % 0.77
Nitrogen, wt % 2.01
Pour Point, C (F) 32 (90)
iM=™o-s*. Centistokes at 38 C /a ,,,.,,.
Viscosity,p) 48 (223)
Gas. The retort gas produced from this process, like that of the
gas combustion process, is diluted with the products of combustion, carbon
oxides from the decomposition of carbonates in the shale, and inert
components of the air introduced to support combustion.
Characteristics and yields of untreated retort gas typical of
internal combustion processes produced at higher temperatures such as the
Union Oil process are presented in Table 7.
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44
TABLE 7. PROPERTIES OF SHALE "GAS" PRODUCED BY HIGH TEMPERATURE
INTERNAL COMBUSTION RETORTING PROCESS(5)
Composition Volume %
Nitrogen 60.1
Carbon monoxide 4.7
Carbon dioxide 29.7
Hydrogen sulfide 0.1
Hydrogen 2.2
Hydrocarbons 3.2
Gross heating value 747 (83)
kcal/scm
(Btu/scf 1
Molecular weight 32
Yield, scm/bbl oil 582 (20,560)
(scf/bbl oil)
Not noted here is the lower concentration of entrained fines in
the exiting gas stream. This reduction is one of the advantages of the
countercurrent flow design of this retort. The hot gas stream is drawn
through the shale bed which acts as a filter to remove entrained solids.
Spent Shale. Spent shale from the Union Oil retorting process will
be similar to the retorted shale from the gas combustion process, both in
size distribution and most physical properties but will have only a negligible
quantity of residual carbon. The relatively large size of the shale utilized
combined with the agglomerates produced by the very high temperatures obtained
in the retorting operation produce large chunks of spent shale, which should
allow for ease in transport and disposal, and should require only moderate
quantities of water for dust control and disposal.
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45
Process Efficiency
Little direct data on the efficiency of the Union Oil Retort process
have been published. However, through examination of the process requirements,
certain important facts can be deduced.
Thermal Efficiency. The countercurrent flow of hot and cold material
employed in this process is believed to provide a more effective heat transfer
path than the countercurrent gas combustion process. The entire heat require-
ments of this process are obtained by the combustion of the carbonaceous
matter retained on the retorted shale, thus saving the diluted product gas
for power generation and other onsite requirements. Therefore, the basic
heat transfer design of the Union Oil retort is considered superior to
the gas combustion process.
The decomposition of the inorganic carbonates will be nearly
complete in the combustion zone where the reaction temperatures are high
(2000 F). Since this high temperature is not sustained in the retorting
zone, the shale oil quality should not be significantly affected.
Product Yield. No data have been published on the yield of shale
oil from the large-scale UOC units. However, since initial data showed a
102* percent yield, estimated commercial scale yields of 90-100 percent seem
reasonable. These yields are superior to the gas combustion process yields.
Costs. The greater mechanical requirements of this process (i.e.,
the rock pump) could significantly raise the capital investment requirements
by necessitating larger, stronger retort structures to withstand the internal
pressures generated by the shale oil rock pump and more sophisticated retorts
to support the greater mechanical complexity. In addition, the pumping of the
shale feed could result in higher operating costs from increased abrasion,
necessitating frequent and costly refractory replacements, and from additional
maintenance costs of the pump itself. The expected higher yields may possibly
offset some of these cost increases.
* Yields calculated on the basis of Fisher assays frequently exceed 100 percent.
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46
The process is internally fuel sufficient since no auxiliary fuels
are required, but the charging operation will require much greater quantities
of energy than a simple gravity feed configuration. The process produces
a large quantity of dilute shale gas which can be converted into energy for
this and other purposes. No data are available to accurately evaluate this
power requirement/gas production tradeoff. However, it is believed that
significant quantities of outside power will be required to operate this
facility.
Like the gas combustion process, the Union Oil retort does not
require water for cooling or for incorporation with the reaction mixture.
Other sources of water additional to that generated by the process will be
required for retorted shale disposal. However, since spent shale generated
by the Union Oil process consists of large agglomerated chunks - not fine
particles which require wetting before disposal, the requirement for water
for proper disposal and for disposal land reclamation can be somewhat minimized.
Capital or operating cost data for retorting facilities utilizing
the Union Oil process are not available in published literature.
Environmental Considerations
Preretorting. Serious air pollution, primarily dust, can be
avoided in this retorting process due to the relatively large feed shale size
distribution. Extensive crushing and grinding will be minimized. Shale
fines, particles less than 0.3 cm (0.1 in.), will have to be compacted into
acceptable size particles or disposed of carefully with the retorted oil
shale.
Retorting. The pollution aspects of the Union Oil retort process
will be very similar to those of the gas combustion process. The process stream
containing the product oil and low Btu gas will necessarily be adequately
controlled to recover the product shale oil and the valuable fuel gases. The
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47
combustion of these gases for power generation will require control to
remove the sulfur oxides, most likely by standard treatment of the stack gases
following combustion.
Retorted shale produced by this process will require disposal. The
hot, steaming mass will need to be adequately controlled by proper conveyance
methods while the shale is cooling. The large average particle size of the
spent shale will allow easy transport of the clinker-like, carbon free shale
to the ultimate disposal site without significant dust generation.
Expected Commercial Development
The Union Oil process, while not being actively investigated at the
present time, does have several technological advantages and good potential
for commercial exploitation. The Union Oil Company has demonstrated a
capability of successful operation of a 1088 kkg/day (1200 tons/day) plant
which is 4 times the demonstrated capacity of the gas combustion process.
The plant has been operated over an extended period continuously. While
certain scale-up problems are anticipated, reasons for not utilizing this
technology to design and construct an efficient commercial-scale facility
within a reasonable period of time are not readily apparent.
Petrosix Process (Type 3)
Process Description
Petrosix process, developed by the Brazilian National Oil Company,
employs the Cameron and Jones kiln. The process is characterized by its use
of continuous gravity flow of shale, direct gas-to-solid heat exchange, with
retorting heat supplied by an externally heated carrier fluid (recycle gas).
Except for the mode of heat transfer, this system is similar to the Bureau of
Mines gas combustion process. The essentials of the process are illustrated
in Figure 11. The retort is a vertical, refractory-lined shaft with a conical
bottom, equipped with elaborate shale and gas handling devices.
-------
Oil
Hl6M-atU
C*} PftOOuC1
FIGURE 11. PETROSIX PROCESS
(18)
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49
Crushed shale enters an anti-segregation feeder; a rotating
"pants-leg" chute which discharges the shale into an annular stationary
trough. Tubes in the trough distribute the shale to different locations
at the top of the kiln. The crushed shale moves downward through the
product cooling zone, the retorting zone, and a heat recovery zone.
Combustion air is not admitted to the kiln, so no heat is generated
internally. Instead, part of the recycle gas is heated in an external
furnace to 705 C and is injected into the retort at its midpoint. Additional
cold recycle gas, at 54 C (130 F), is introduced at the bottom of the retort,
where it rises through the shale-bed recovering heat from the hot spent
shale. This gas then mixes with the injected gases to heat and retort the
shale in the upper part of the vessel. The oil and gas are carried out of
the retort as a mist and are collected and separated. Product gas from the
Petrosix process is undiluted with combustion gases, and, therefore, has a
relatively high heating value and may be readily processed for recovery of
sulfur, ammonia, and condensable hydrocarbons. The spent shale enters a
discharge grate which has annual openings. A number of hydraulic cylinders.,
spaced around the circumference of the kiln, move the grate in a circular
path to insure a uniform flow of spent shale out of the kiln.
Status of Development
Published details of Petrosix process development are scant; however,
it is known that a 900-1400 kkg/day semiworks plant is operating in Brazil. ^'L9'
In addition, a 2267 kkg/day kiln is now being constructed in Brazil for use in
the Petrosix process. Kilns with 5.5 meters* diameter are already in existence
in other than oil shale retorting processes. Kilns of 10.7-13.7 m diameters
are considered by Cameron Engineers to be operable for use with oil shale.
When the 2267 kkg/day (2500 ton/day) facility is completed, it will be the
largest existing shale retorting facility. Considering 9,000 kkg/day to be the
minimum desired capacity for a single unit of a multiple retort commercial
1 meter =3.3 feet approximately.
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50
facility, this new Petrosix process facility will be one-fourth commercial
scale. Petrosix data on yields of oil from U.S. raw shale are not available;
however, since Brazilian oil shales average a much higher oil assay than
U.S. shales, a lower yield process could still be economically viable when
using the oil-rich Brazilian shales.
Nature of Products
The characteristics of the oil, gas, and spent shale produced from
U.S. oil shale by the Petrosix process are not available. However, expected
product characteristics are presented as follows.
Oil. The oil produced in this retorting process should be similar
to the oil produced from other vertical retort processes such as the gas com-
bustion and Union Oil processes. Typical analyses of these oils have been
presented in the previous sections.
Gas. Gaseous products from the Petrosix process should be superior
to that produced by direct fired internal combustion retorting processes
(i.e., gas combustion and Union Oil). Typical analyses of gases produced
from an externally heated retorting process (TOSCO process) are presented
in the following section. Expected heating value is high (6300-7200 kcal/
scm*) and approaches pipeline quality gas Btu rating. Because the gases
are not diluted by nitrogen, the high sulfur and hydrogen content of the
gas can be economically exploited. A low nitrogen, low sulfur, relatively
high Btu gas that can be utilized in a variety of on-site and off-site uses
is possible. A remote possibility that the gases might be piped through
existing natural gas supply lines for sale also exists.
Spent Shale. Because the Petrosix process involves a vertical bed
arrangement, the minimum particle size of the oil shale feed is limited.
Therefore,like other vertical processes, the resulting retorted shale would be
* 700-800 Btu/scf.
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51
expected to retain its approximate initial size. The loss of shale by the
entrainment of fines in the gas stream should be relatively low because of
the large shale rock size distribution employed. The residual carbon content
of spent shale is expected to be high due to absence of direct fired internal
combustion heating.
Process Efficiency
Thermal Efficiency. Again, available data to accurately evaluate
the efficiency of this retorting process is inadequate. The use of an
externally heated heat transfer fluid is a less efficient means of retorting
the shale than internal direct heating as regards thermal efficiency. However,
with this type of heating,dilution of the product gas is avoided. The result
is a trade-off. A smaller quantity of a more easily handled high Btu product
gas is produced but the retorting process requires a greater heat input.
Combustion of the carbonaceous matter left on the retorted shale, as a means
of generating this additional heat, is a definite possibility although it is
not mentioned in the literature as part of this process. Additional data are
needed to evaluate this process.
Product Yield. Data are not available on the yields of crude
shale oil from oil shale.
Costs. The Petrosix process is slightly more involved than the two
previously discussed retorting processes. The inclusion of the recycle gas
furnace in the process train will add to required capital investment. The
economics of the trade-off between the additional equipment and producing a
gas amenable to the recovery of sulfur, ammonia, and condensable hydrocarbons,
and the additional capital for the recovery operations versus the value of
the recovered products, is unknown. However, it is believed that this
process is more advanced and, therefore, has better chance for economic success,
The capital cost for retorting, employing the Petrosix process,
has been estimated at $1108 per kkg of retort capacity. This cost is
expected to apply to the general range of plant capacity up to 63,000 bbl/
day. Estimated retort operating costs (not including interest on capital,
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52
taxes, insurance, cost, or Land and working capital) are $1.26/kkg ($1.14/
ton) of shale retorted. All costs were escalated from 1968 costs to late
(18)
1973 by the Chemical Engineering Plant Cost Index.
Process water requirements are not directly addressed in the
literature for the Petrosix process. Possibly the recycle gas furnace
could require noncontact cooling of certain vital parts; this would require a
relatively high quality (river) water, of which a certain quantity would be
lost upon cooling and a certain quantity would have to be bled. The required
quantity of water in the semiarid area of U.S. oil shale deposits could
become a very significant factor in the overall profitability of the Petrosix
process.
The retorted shale produced will require disposal. The increase in
specific volume of this shale is, therefore, critically important. The spent
shale from the Petrosix process is expected to have a disposal problem of a smaller
magnitude than the two previously discussed processes because the oil shale
is simply pyrolyzed rather than combusted and pyrolyzed. However, if the
carbonaceous matter retained on the spent oil shale is burned to recover its
heat content, a finely divided shale ash would be produced. Such shale ash
often has an increase in specific volume as high as 60 percent rather than
the more typical 30-50 percent. In addition, the quantity of water required
in adequate landfilling of this material is much more than for larger sized
spent shales. Whether the economic advantages possible through the recovery
of heat from the pyrolyzed shale would outweigh the economic penalties is not
known.
Environmental Considerations
Preretorting. The pollution aspects of the Petrosix process from
the preretorting operations (i.e., crushing, grinding, and sizing of the oil
shale) are identical to the two previously discussed vertical kiln configuration
processes. The larger particle size of the shale feed decreases the potential
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53
for air pollution while creating a potential solid waste (undersized oil
shale) and lowering the utilization of all the mined shale. These problems
can be effectively dealt with by installing an auxiliary briquetting
operation.
Retorting. The retorting operation will produce a gaseous product
stream containing the shale oil and product gases and a spent shale stream.
The collection and separation of the valuable products in the gaseous stream
can be adequately controlled since both the oil and product gases will need
further processing. The product gases can be piped to gas desulfurization
units. Since the fuel will have been desulfurized, the gas furnace can be
equipped with readily available particulate removal systems. The spent shale
leaving the retort will be relatively hot (94 C;200 F). Therefore, like the
previously mentioned processes, adequate precautions will have to be taken to
minimize emissions. Alternately, if the spent shale is employed for heat
generation by combustion of the carboneous matter retained on it, additional
pollution abatement would be required.
Expected Commercial Development
The very advanced stage of process development makes the Petrosix
process among the leaders in the commercial exploitation of the vast oil shale
resources. Development plant scale-up of only 4 times would be required to
obtain a commercial unit. In addition, this process shows promise because it
combines the very extensive research of the Bureau of Mines process with a
process modification which produces a more useful, higher Btu, undiluted
product gas.
The Brazilian government is expected to help subsidize the develop-
ment of this retorting process. In the United States, the development of the
gas combustion process could be extended to include this modification of the
heating procedure.
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54
TOSCO Process (Type 4)
Process Description
The Colony Development Operation's TOSCO II retorting process
is characterized by: (1) the use of a horizontal rotating kiln, wherein
shale is agitated and transfered through the retorting zone by the mechanical
rotation of the tilted kiln, (2) direct solids-to-solids heat transfer, and
(3) heat supply by externally heated ceramic balls. The essentials of the
process are illustrated in Figure 12. Crushed shale (-1.3 cm size) is pre-
heated and pneumatically conveyed through a vertical pipe to the retort by
flue gases from the ball heating furnace.The preheated shale then enters the
horizontal pyrolysis drum along with previously heated (650° C) ceramicfheat-
(20)
carrying balls. The shale is brought to a retorting temperature of
480° C (900° F) by conductive and radiant heat exchange with the balls. The
oil vapors and gases are removed from the drum, cooled, and the oil and
gases separated and sent to further processing. The drum is discharged
over a trommel screen where the balls are separated and recycled back to the
ball heater. Combustion of up to 5 percent organic carbon retained on the
retorted shale, or alternately a fraction of the retort gas, will provide the
required energy for the reheating of the balls; the flue gas generated is
further utilized, as noted, for preheating the incoming shale. The finely
divided spent shale or shale ash (when employed for a fuel) is then cooled
and sent to disposal. '
Status of Development
The TOSCO II process has its origin in the "Aspeco" process-the rights
to which were purchased from Aspegren & Company of Stockholm, Sweden,in 1952.
The Oil Shale Corporation was formed to exploit this process and, in 1955,
contracted with the Denver Research Institute (DRI), University of Denver,
to conduct engineering research and development. DRI constructed both a 136
kg/hr laboratory unit and a 22 kkg/day pilot plant and operated these for
TOSCO for several years. In 1964, the Colony Development Company was formed to
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FLUE GAS TO ATMOSPHERE
I
RAW SHALE
ec
o
(Jl
SPENT SHALE
TO DISPOSAL
OR BALL
HEATER FUEL
FIGURE 12. TOSCO II PROCESS
(5)
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56
commercialize the TOSCO II process. Participants in this venture were The Oil
Shale Corporation, Standard Oil Company (Ohio), and Cleveland-Cliffs Iron
Company. This group financed the construction in 1965 of a 900 kkg/day semi-
works plant located on Parachute Creek, near Grand Valley, Colorado. The
plant was operated by the group until September 1966., when The Oil Shale
Corporation assumed sole responsibility until they placed the unit on stand-
by in 1967. Atlantic Richfield Company joined the group, now Colony Develop-
ment Operation, in 1969 and has since been responsible for modifying and
reactivating the semi-works plant. Operation was begun again early in 1971
and completed in late 1972. ' Ashland Oil is the latest to join in the
TOSCO recovery process. Atlantic Richfield, The Oil Shale Corporation, and
Ashland Oil now hope to start building a 50,000 bbl/day plant in the
Piceance Basin of western Colorado during 1974, with construction to take
about three years. Sohio and Cleveland-Cliffs hold an interest in the
privately owned oil-shale reserves that are likely to be selected for the
plant site, and retain the right to join in construction of the facility. ^ '
Nature of Products
Oil. The yield of oil from the demonstration scale unit
(900 kkg/day size) has been termed "excellent".^ ' Various sources have
reported yields as high as 105 weight percent of Fischer assay. Properties
of the crude shale oil are displayed in Table 8 .
TABLE 8. PROPERTIES OF CRUDE SHALE OIL PRODUCED
BY THE TOSCO II PROCESS^
Gravity, API 28.0
Sulfur, wt % 0.80
Nitrogen, wt % 1-70
Pour Point, C (F) 23 (75)
v. ori(=.f.,F centistoke @ 38 C ,_ . , ...
Viscosity, (sug @ 10Q p) 25.4 (120)
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57
Gas. The retort gas produced by the TOSCO II process is undiluted by
combustion gases. In addition the use of a lower retorting temperature
limits the dilution of the product gas by C0« released from the high temperature
decomposition of inorganic carbonates in the oil shale. Characteristics and
yields of untreated and desulfurized retort gases typical of indirectly heated
retorting processes are presented in Table 9.
TABLE 9. PROPERTIES OF RETORT GAS PRODUCED BY
INDIRECT HEATED RETORTING PROCESSES
Composition (Volume %)
Nitrogen
Carbon monoxide
Carbon dioxide
Hydrogen sulfide
Hydrogen
Hydrocarbons
Gross Heating Value
kcal/scm
Btu/scf
Molecular Weight
Yield, scm/bbl oil
(scf/bbl oil)
As
Produced
0
4.0
23.6
4.7
24.8
42.9
6975
775
25
25.8 (923)
After
Desulfurization
0
4.2
24.8
(0.02)
26.0
45.0
7335
815
24.7
24.6 (880)
Spent Shale. Spent shale or shale ash (depending on the use of the
retorted shale) from the TOSCO II process is very finely divided, with particles
in the sand-to-clay size range. Disposal of such fine material will require
special care because of the inherent dust problem. In addition, a greater
quantity of water will be required to moisten spent shale before transporta-
tion and disposal.
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58
Process Efficiency
Thermal Efficiency. The transfer of heat to the shale by externally
heated materials is normally a far less efficient process than direct heat
transfer by internal combustion. However, because of several offsetting
advantages resulting from this retorting method, better overall shale oil
extraction is accomplished. The exclusion of combustion products, mainly
nitrogen, allows the production of an undiluted retort gas. In addition ,the
heat required to raise the temperature of the incoming combustion air is
conserved. Another advantage of this mode of retort heating is the minimal
decomposition of inorganic carbonates in the shale resulting from greater
shale agitation and hence controlled temperature retorting. Limiting thermal
decomposition reactions results in additional heat savings.
Product Yield. The yield of shale oil from raw oil-shale by the
TOSCO II process is the highest of any reported process. Yields as high as 104-
105 percent of Fischer assay are reported with the demonstration scale unit and
a yield of 100 percent is assumed appropriate for a commercial scale facility.
If the carbonaceous residue on the retorted shale can be effectively
utilized to provide the heat for the ball heating operation - thereby allowing
the total gas production to be included in the yield from the process, then
yields as high as 126 percent of Fischer assay are possible. The use
of the rotary kiln rather than a vertical bed eliminates the lower particle
size restrictions; in fact,it requires a higher degree of crushing and size
reduction than any other process.
Costs. The very high yields possible with the TOSCO II process will
allow the construction of a commercial scale facility of lesser capacity
equipment than the Type 2 or 3 retorting processes. As with the Petrosix
process,the retort gas will be undiluted with combustion gases and easily lends
itself to desulfurization,resulting in the production of sulfur, ammonia, and
condensable hydrocarbons. The very high carbon content of the spent shale
makes this product an excellent auxiliary fuel for the reheating of the
retorting balls,thus freeing the retort gas for the operation of the post-
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59
retorting facilities. The capability of the process to accept shale fines
results in complete shale utilization. However, the requirements for finer
crushed input shale will result in higher preretorting costs and possibly
the necessity for additional air pollution control equipment. No water is
required for the retorting operation, but significant quantities will be
required for the ultimate disposal of the spent shale. Because the kerogen
is so completely extracted in this process the residue has little structural
(2)
stability, resulting in an increase in specific volume as high as 60 percent.
The increase in specific volume will necessitate the disposal of a majority
of the spent shale in landfills since only a fraction can be replaced in
the shale mines. This represents an additional cost factor.
Data on cost estimates of commercial scale retorting operations are
scant. Assuming that the TOSCO II process is employed and retort gas is not
needed for retort plant fuel, because the process is assumed to utilize
heat recovered from burning the coke-like deposits on the spent shale,
estimates of capital and operating costs follow.
The capital cost for retorting is estimated at $1820 per kkg ($1650
per ton) of retort capacity. This cost is expected to apply to the general
range of plant capacity of 54,400-72,600 kkg/calendar day (60,000 to 80,000
tons/calendar day) production of 53,000 to 71,000 bbl/calendar day of oil
from 37.1 gal/ton oil shale. Included in the above costs, in addition to the
complete retorting system, are costs for site preparation, tankage and other
off-site construction, buildings, sewer system, gas compression and absorption
plant, oil and gas pipelines to the up-grading plant, and 25 percent contingency
in the entire plant. An estimated paid-up royalty cost is also included.
Estimated retort operating costs (not including depreciation and
income taxes) are $0.41/kkg ($0.37/ton) of shale retorted during the first 15
years and $0.52/kkg ($0.47/ton) during subsequent years. The additional cost
for later years provides for increased maintenance.
* Based on June, 1970,costs and escalated to December, 1973,using CE plant
cost index (CPI). The escalation is 16% for the 3-1/2 year period.
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60
Environmental Considerations
Preretorting. The main influence of the TOSCO II process on environ-
mental emissions from the preretorting facilities will be because of the
very fine particle size requirement. Shale feed must be crushed to 1.3 cm
(0.5 in.) or smaller size for efficient oil extraction. This results in
large quantities of fines and necessitates the use of efficient dust control
devices. A positive aspect of this finer size requirement is that all the
shale received can be utilized without creating a raw shale fines disposal
problem.
Retorting. The undiluted gaseous stream produced by the retorting
operation will contain the shale oil and the retort gas. Both components, as
process products, can be adequately collected and separated with minimal
environmental emissions. Both streams will be transferred to adjacent
processing facilities for refining, separation, and/or purification. (These
will be briefly discussed as part of the pollution aspects of the post-
retorting processes).
Spent shale with a high degree of carbonaceous residue can either
be disposed of directly or more efficiently burned in the process to liberate
heat for the reheating of the retorting balls. The cleaning of the resultant
flue gas will be a necessary, requiring cyclones, baghouses, or electrostatic
precipitators. The removal of the sulfur from these gases will also be
necessary. Employing the shale residue for fuel will probably require
conventional stack gas cleaning—such as scrubbing--which could become
expensive because of the scarcity of water.
Post-Retorting. No special pollution problems are anticipated in
the shale-oil refining operation as a direct result of special process re-
quirement of products produced by the TOSCO II process. The separation and
purification of the retort gas however will most likely result in the need
for additional pollution abatement equipment. Since these operations are
currently being performed on a large scale at most U.S. refineries with adequate
pollution controls sufficient technology should exist to assure that the
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61
environment can be protected during retort gas purification.
Expected Commercial Development
The TOSCO process is currently the most likely candidate process
to be developed commercially. Predictions on the imminent initiation of
construction of a 50,000 bbl/day facility have been announced as early as
(14)
1968. A most recent announcement was to the effect that construction
on a 50,000 bbl/day plant will begin in 1974.(15)
The TOSCO II process has been extensively demonstrated over a
period of years in a 900 kkg/day facility. It is believed that sufficient
engineering data have been generated to scale up the demonstration facility
to commercial scale.
As the most advanced retorting process which has been demonstrated
on a large scale, the TOSCO II process would be expected to be eligible for
new federal energy monies for the development of commercial-scale retorting
technology. Actual development of the planned 50,000 bbl/day plant would
certainly enhance this position. The Colony Development Operation is a
diversified group of private industries pooling their resources to
commercialize the TOSCO II process. Included in the group are the developers
of the TOSCO II process, three oil concerns and a mining company. Collectively
they represent sufficient capital and technology to commercially develop
the TOSCO II oil shale retorting process.
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VI. RETORTED SHALE REFUSE DISPOSAL
The spent shale and shale ash produced by the various ex-situ
retorting processes are expected to be a large percentage (up to 70 percent)
of the shale input on a weight basis. On a volume basis, the expected
quantity of refuse will be even larger due to swelling. This chapter reviews
the magnitude of this disposal problem and possible disposal methods. In
addition, the spent shale characteristics will be reviewed to determine the
potential for its economic use.
Factors Affecting the Magnitude of the Disposal Problem
The various retorting techniques will have differing effects on
the quantity and physical and chemical characteristics of the spent shale
produced. The differences in certain important physical properties of spent
shale from three different processes are shown in Table 10. Four parameters
of the magnitude of the disposal problem can be identified. They are:
(1) yield--the percent extraction of shale oil from the raw oil shale;
(2) specific volume--the degree of increase in the volume of the shale feed
after retorting; (3) compactability--the reduction in volume resulting through
natural or artificially induced settling of disposed shale; and (4) leachability-
the susceptibility of chemical ions in the retorted shale to enter into
solution with water percolating through or flowing over retorted shale.
Yield
The efficiency of the retorting process in terms of the quantity
of shale oil recovered from the raw oil shale will dictate the tonnage of feed
that will require processing to obtain a desired production capacity. The
exact yields obtainable by any of the retorting processes in a commercial scale
facility are unknown since no process has been commercialized. However, by
noting the performance of the demonstration scale facilities approximate
estimates can be obtained. The gas combustion retorting process of USBM has
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63
TABLE 10. PHYSICAL PROPERTIES OF RETORTED SHALE
(5)
Property
Geometric mean size, cm
(in)
2
Permeability - cm
(in*)
Bulk density, g/cc
(Ib/ft )
Solid density, g/cc 7
(lb/ftj)
Maximum size, cm
(in)
Minimum size, cm
(in)
Gas Combustion
0.205
(0.081)
3.46xlO~9
(5.36x10-10)
1.44
(89.90)
2.46
(153.58)
3.81
(1.50)
0.00077
0.0003
Retorting Method
Union
Not Reported
Not Reported
1.80
(112.37)
2.71
(169.19)
Not Reported
Not Reported
TOSCO II
0.007
0.003
2.5xlO-10
(3.88x10-11)
1.30
(81.16)
2.49
(155.45)
0.476
(0.19)
0.00077
0.0003
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64
shown decreasing oil yield as the capacity of the processing facility is
increased, e.g., 94-95 percent at 5.4 kkg/day and 83-87 percent at 136 kkg/day *•
(14)
and about 85 percent at 272 kkg/day. These yields,when extrapolated to a
commercial scale of 10,000 tons per day per unit, reduce to 78 percent. At
this yield 22 percent additional shale would have to be processed over a system
capable of a 100 percent yield, such as the Colony Development Operation's TOSCO II
retorting process. Yield for this latter system ranges from 104 to 126 percent
of Fischer assay at the 900 kkg/day capacity level and is conservatively
estimated at 100 percent for commercial scale. No data to estimate possible
commercial scale yields with either the Union Oil or Petrosix process have been
reported. The Union Oil retort was capable of over 100 percent yield at the
1.8 kkg/day scale. Generally both processes are considered very efficient
and an average industry estimated yield is 86-95 volume percent. Assuming
these estimates to be accurate indications of the variation of oil yields as
a function of the retorting process, the variation in refuse produced could
be as high as 30 percent.
Specific Volume
The volume of shale refuse to be disposed of is directly proportional
to the "swelling" of the .shale feed. The organic material (kerogen) present in
the raw shale seems to be the cementing agent that holds the rock together so
that extraction of the organic material leaves a residue with little structural
(14)
stability. Therefore, the more complete the extraction process, the lower
the structural stability, and the more friable or brittle the retorted shale
becomes. The resulting swelling problem therefore is accentuated by extensive
initial crushing and agitation during the retorting process. Both crushing
(A)
and agitation tend to increase the extraction of oil and tend to produce
a greater quantity of smaller end products.
The gas combustion, Union Oil, and Petrosix processes all employ a
vertical kiln retorting arrangement, necessitating the use of rather large
sized feed shale particles and producing similar sized spent shale. In
addition, all three processes extract considerably less than 100 percent of the
organic matter in the raw shale. Therefore, the increase in specific volume
of the spent shale above that of the feed from these three retorting processes
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65
should be relatively low. However, the volume of spent shale from any known
retorting process, even after maximum compaction, is at least 12 percent greater
than its in-place volume. Reported data show that typical shale ash from
the Union Oil process increased approximately 21-28 percent in specific volume
after retorting. Similar Increases in specific volume could be expected
with the gas combustion or Petrosix processes. The TOSCO II retorting process,
as noted in the previous section, employs (1) a much smaller feed size than
any of the other three processes, (2) a rotating rather than a stationary
extraction process which tends to grind or fracture the embrittled shale, and
(3) obtains a 100 percent or greater oil yield. All three factors tend to
increase the specific volume of the sand-sized spent shale. Specific volume
increases as high as 60 percent are reported for the TOSCO II process.'1'
The above data indicate that an average increase in volume of loosely
dumped spent shale over in-place shale can be at least 50 volume percent.
Compactability
The degree to which retorted shale can be compacted either by
natural cementation or external pressure directly affects the volume of
disposal area required. Two characteristics can be identified which are
important to the compactability of spent shale. They are: (1) surface carbon
content and (2) particle size distribution. Small scale experimental work
indicates that natural surface-cementation reactions are inhibited if a
material amount of carbon is present to coat the particles. The particle
size distribution is important because large void spaces will exist in shale
dumps composed of large shale rock. These void spaces tend to limit natural
cementation and resist mechanical compaction.
The Union Oil retort produces a completely burned shale ash which
may contain large chunks of clinkered material, but most of the ash is about
the same size range as the feed, 0.3 to 15 centimeters, with a relatively small
amount of fines. The larger materials may require crushing prior to the
water addition and compaction. The lack of carbon should approximately offset
the larger spent shale size to produce an average compactable refuse.
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The gas combustion process spent shale is considered intermediate
with about 3 percent carbon content. This is a high enough carbon content
to inhibit some surface cementation reaction. In addition, the relatively
large spent shale particle size should somewhat inhibit natural and artificially
induced compaction.
The Petrosix process, which establishes heat transfer through the
use of an externally heated carrier fluid, produces a high carbon spent shale
ranging from 5 to 6 percent organic carbon. Like the gas combustion process,
this is certainly enough carbon to limit certain natural cementation reactions.
The Petrosix process also produces a relatively large sized spent shale which
will somewhat inhibit compaction efforts.
The TOSCO II process products (like the Petrosix process) have a high
carbon refuse. However, the particle sizes of the spent shale is of the sand
grain size—which should offset the negative cementing characteristics of the
TOSCO spent shale. The average compaction of loosely dumped spent shale is
assumed to result in a 25-26 percent volume reduction; this, however, is still
a 13-16 percent increase in volume over the in-place oil shale. This can be
interpreted as only requiring 13-16 percent of the spent shale to be eventually
disposed of above ground—the rest being returned to the worked out mine. Less
optimistic forecasts of 40 percent above ground disposal are often considered
more accurate. In any event, use of the worked out mine for a spent shale
disposal site will require waiting for a considerable amount of time (up to
16 years) for completion of the commercial operation. Until that time 100 percent
of all spent shale will have to be properly disposed of above ground. Table 11
displays the anticipated quantity of oil shale that would have to be mined
and the annual volume of spent shale that would have to be disposed for
various upgraded shale oil capacities.
Leachability
Another factor effecting the magnitude of shale refuse disposal
problem is the leachability of spent oil shale. This will dictate the degree
of water channeling required to redirect water around the disposal sites
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TABLE 11 . QUANTITY OF IN-PLACE AND SPENT SHALES
Upgraded Shale Oil
Production Plant
Capacity
(bbl/day)
50,000
100,000
250,000
1,000,000
Shale Mined,
106 kkg/yr
(106 ton/yr)
24.4-27.1
(26.9-29.9)
48.8-54.2
(53.8-59.8)
122.0-135.6
(134.5-149.5)
488.0-542.4
(538.0-598.0)
In-Place
0.11-0.13
(0.40-0.45)
0.22-0.25
(0.80-0.90)
0.56-0.63
(2.00-2.25)
2.24-2.52
(8.00-9.00)
Shale Volumes
100 Million cu.m./yr
(Billion cu.ft./yr)
Spent (loose)
0.17-0.20
(0.60-0.70)
0.34-0.39
(1.20-1.40)
0.84-0.98
(3.00-3.50)
3.36-3.92
(12.00-14.00)
Spent (Compacted)
0.13-0.15
(0.45-0.52)
0.25-0.29
(0.90-1.04)
0.63-0.73
(2.25-2.60)
2.52-2.91
(9.00-10.40)
Basis: Oil shale assaying 30 gallons per ton; upgraded oil yield of 86-95 vol. pet., based on in-place
crude shale oil potential; loosely dumped spent shale bulk density of 71-75 Ibs. per cu. ft.;
compacted spent shale bulk density of 90-100 Ibs. per cu. ft.
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and the number and size of retaining ponds required to collect water which has
flowed over or percolated through the shale dump. Three factors can be
identified which are important to the susceptibility of spent shale leaching.
They are (1) refuse compaction, (2) carbon content, and (3) carbonate decompo-
sition. The factors which inhibit refuse compaction have been discussed in
the preceding paragraphs. The carbon content of retorted shale was also
discussed in its inhibiting effect on natural surface cementation. However,
the carbon coating on the spent shale also has the effect of preventing water
penetration to the extent that percolation-type leaching is not expected to
be a problem. ^ '
Methods of Disposal of Retorted Shale Refuse
The cooled and moistened solid residue from retorting will be
disposed of by a system involving minimum handling, such as truck or belt
transport, to convey the waste material to adjacent canyons or other topo-
graphic depressions. Disposed material will be compacted, as needed, to main-
tain stability as the pile is built up. To prevent downstream pollution by
dissolution of soluble material from the residue during run-off periods,
disposal areas must be adequately safe-guarded by dams, culverts, and/or
diversion ditches.
Disposal of fine-sized residue by slurrying and pumping to a disposal
pond has considerable attraction because of the relative simplicity and low
cost of the system. However, such disposal may be limited by two factors:
(1) inadequate disposal areas and (2) water availability. High dams will be
required to impound adequately sized tailings ponds in topographically low areas.
Since it appears that some residue may be too fine-grained to be safely used
alone in the construction of such dams, other suitable material which is likely to
be more expensive, since it may not be readily available, may be required. In ad-
dition, slurry disposal consumes a considerable amount of water due to evaporation
and retention in the solid fill. Adequate water supplies undoubtedly will be a
future problem and this may preclude disposal by the slurry method. It is
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69
possible that saline water, if produced from some deep mines, could be used
and recycled, thus solving two disposal problems.
As a means of protecting the environment, all residue disposal
areas will have to be adequately protected against erosion. Erosion would be
of particular concern on the steep slopes of unprotected residue piles. Storms
could lead to the formation of deep gullies on the slopes and alter the pattern
of drainage established from preceding runoffs. Continued erosion also would
expose new surface areas to air and moisture which could lead to undesirable
leaching and the creation of water quality problems. The effect of revegetation
on these potential problem areas is unknown. If unprotected, a large portion
of the sediment from the spent shale piles might be deposited in stream channels
near the disturbed area. However, sediment also would be carried into large
streams, where it would settle out or move downstream. Thus, entire river basins
could be adversely affected by the spent shale piles if no care was taken to
prevent these potential problems. If streams are required to carry heavy, loads
of sediment, additional treatment may be required to make them more suitable
for domestic and industrial uses. In addition, recreational use of streams
could also be adversely affected by sediment, and fish habitat could be destroyed.
Erosion of spent shale piles may be lessened to some extent through
physical, chemical, and vegetative methods of stabilization. Physical methods
Include covering the fine tailings with topsoil removed from underneath the
shale residue piles. One possibility for a surface disposal site would be a
canyon in the vicinity of a proposed commercial plant site. The processed shale
could be placed in a series of horizontal layers 1 to 2 feet thick. The upper
surface would be a temporary surface until the last layer is placed. Each
layer could be started a little further back Into the canyon, giving the front
surface of the pile (permanent surface) a slope sufficiently less than the
angle of repose to insure frictlonal stability. Chemical stabilization, involving
reacting the residue with a reagent to form a water and air impermeable crust or
layer, could also be employed. Vegetative stabilization may pose some difficult
problems. Wastes are usually deficient in plant nutrients or may contain material
noxious to plant growth. Tailings and other fine wastes usually must be covered
to a depth of four inches or more with soil and fertilized prior to seeding.
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70
However, Kentucky Blue Grass, fertilized at the rate of 150 pounds per acre
twice per year and watered at the rate of 1 inch per week during the 10 week
summer season has been grown on the TOSCO II process waste after conditioning
with sawdust.
Much consideration has been given to the disposal of solid residue
in mined-out areas underground. Ultimately this procedure may prove to be a
partial solution to the disposal problem, because the decreased specific
gravity of residue compared to the in-place rock restricts disposal in this
manner to a maximum of about 70 percent (more likely 50 to 60 percent) of
the total volume of waste material produced.
Both conveyor and slurry methods for underground disposal have been
studied. Conveyors pose great distribution problems and undoubtedly will be very
expensive to install and operate. Pipeline transportaion of slurry eases
the underground distribution problem and is less expensive but, as in surface
disposal operations, may consume large amounts of water in addition to requiring
numerous and expensive dams to seal off mined-out areas. Also, since the resi-
due may not drain well, additional problems of water recovery and stability
of filled areas should be considered. Control of particle size is essential.
Ideally, particle size should not exceed 60 mesh for transport through pipe-
lines, and oversize may have to be reground or screened out and disposed of
elsewhere. For effective drainage and compaction much of the -325 mesh slimes
may have to be removed and disposed of in some surface ponded area. The total
effect of all this damming, processing, and handling may well make underground
slurry disposal economically unattractive.
The susceptibility to water leaching is effectively limited by
proper disposal site construction and compaction. Leaching tests show that
while there is a definite potential for high concentrations of certain minerals
in the runoff from spent shale residues, upon proper compaction the disposal
piles become essentially impermeable to rainfall. Studies conclude that water
contamination due to percolation type leaching will be negligible and that the
main emphasis must be placed on surface runoff. To this extent it is concluded
that the greatest concern of possible water pollution is not with the normal
snow and/or rain that occurs throughout the year but with occasional flash floods
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71
that may deposit large quantities of rainfall in a relatively short period
of time. To handle this water and runoff from adjacent plateaus which drain
into the disposal canyons, it will be necessary to either channel the water
away from the disposal sites or install large conducts in the bottom of the
canyon under the spent shale dump which lead to retaining ponds immediately
downstream. This water, including the brines, can then be impounded and
eventually returned and reused in subsequent disposal operations.
Utilization of Spent Shale
Oil shale contains other potentially valuable components in addition
to the organic material. The characteristics of retorted oil shale and some
of its potential economic uses will be reviewed in this section.
Characteristics of Spent Oil Shale
Detailed chemical analyses of spent oil shale show that the main
differences in spent shale produced by different retorting processes are in the
organic carbon and undecotnposed carbonate contents. Table 12 presents several
analyses of the mineral composition of spent shale ash from the nine minable
beds in the Mahogany zone on an oxide basis and on a raw shale basis. These
analyses should be typical of retorted shale because the mineral matter in oil
shale of the Mahogany zone of Colorado and Utah, where oil shale averages 146 1/kkg*
is very consistent, and regardless of the extent of decomposition, the basic
oxide forms of the minerals in retorted shale are similar.
Potential Economic Uses
The principle products expected to be recovered are (1) alumina
from the dawsonite deposits and (2) soda ash from the nahcolite (a natural
sodium bicarbonate). The recovery of alumina has received the greatest Interest.
The Oil Shale Corporation (TOSCO II), Wolf Ridge Minerals Corporation, and Kaiser
* 35 gal/ton.
-------
TABLE 12. MINERAL COMPOSITION OF MINABLE-BED SAMPLES
FROM THE MAHOGANY ZONE, RIFLE, COLORADO<4>
Ash content of raw shale wt . pet,
Composition of ash:
Si02 wt. pet,
Fe 0_ wt . pet .
Al 0 wt. pet,
CaO wt. pet,
MgO wt . pet ,
SO, wt . pet.
Na20 wt . pet.
K 0 wt. pet,
Total wt. pet.
ksh composition, raw-shale basis:
SiO wt. pet,
Fe20_ wt. pet.
A 10. wt. pet.
CaO wt. pet.
MgO wt. pet,
S03 wt. pet.
Na2°3 wt. pet.
K 0 wt. pet.
Total wt. pet.
(a)
Bed designation
C JADHBIGEF
70.70
46.41
4.36
13.08
20.34
8.80
1.21
3.00
2.91
100.11
32.8
3.1
9.2
14.4
6.2
.8
2.1
2.1
70.7
63.01
35.12
3.67
10.21
33.90
13.43
.85
1.65
2.11
100.94
21.9
2.3
6.4
21.2
8.4
.5
1.0
1.3
63.0
67.73
42.63
3.91
13.66
20.63
12.82
.87
3.12
2.35
99.99:
23.9
2.6
9.2
14.0
8.7
.6
2.1
1.6
67.7
69.56
45.86
4.24
13.65
20.17
9.15
1.58
2.35
3.03
.00.03
31.9
3.0
9.5
14.0
6.4
1.1
1.6
2.1
69.6
68.03
42.51
4.05
12.42
23.66
9.84
2.17
3.73
2.43
LOO. 81
23.7
2.7
8.4
16.0
6.6
1.5
2.5
1.6
68.0
66.80
46.01
4.78
12.18
20.41
8.10
2.11
3.92
1.73
99.27
31.0
3.2
8.2
13.7
5.5
1.4
2.6
1.2
66.8
60.17
39.18
4.35
9.78
29.26
10.27
2.50
2.42
2.19
99.95
23.6
2.6
5.9
17.6
6.2
1.5
1.5
1.3
60.2
62.15
39.71
4.53
13.56
25.50
8.58
2.90
3.85
2.05
LOO. 68
24.5
2.8
8.4
15.7
5.3
1.8
2.4
1.3
62.2
59.64
41.93
4.82
13.81
20.44
8.62
4.35
3.96
1.81
99.74
25.4
2.9
8.2
12.2
5.1
2.6
2.4
1.1
59.6
Aver-
age
65.31
42.15
4.30
12.48
23.81
9.96
2.06
3.11
2.29
100.16
27.5
2.8
8.2
15.5
6.5
1.3
2.0
1.5
65.3
Com-
posite
65.68
42.71
4.56
13.15
23.27
9.97
1.81
3.09
2.33
100.92
27.8
3.0
8.6
15.1
6.5
1.2
2.0
1.5
65.7
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73
Footnotes to Table 12.
(a) Nine minable beds in the Maghogany Zone.
Note: Spectrographic and chemical analyses Indicated the presence of other
elements in Colorado oil shale in maximum amounts (weight percent)
as follows:
Arsenic
Barium
Boron
Chromium
Copper
Gold
0.005
.03
.03
.007
.008
.001
Lead
Lithium
Manganese
Molybdenum
Phosphorus
Selenium
.09
.05
.08
.001
.4
.001
Silver
Strontium
Tellurium
Titanium
Vanadium
Zinc
.001
.08
.7
.06
.06
.1
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74
Aluminum & Chemical Corporation have all developed process for extracting
the alumina in oil shale. These companies have not disclosed any details of
their processes, but government researchers have been working on nitric
(22)
acid-leach techniques in which the acid is recovered and reused. v Their
work has shown that complete extraction of the alumina in the sample was
obtained with a dilute acid leach. Their tentative conclusions are that recovery
(23)
of soda ash and alumina is feasible and is compatible with retorting for oil.
Alkaline leach tests perfoi?med at different residence times, temper-
atures and concentrations of sodium hydroxide have shown that good recoveries
of alumina with low silica contamination are obtainable at room temperature
and low residence times with relatively dilute sodium hydroxide (NaOH) con-
centrations. Maximum alumina recoveries at these conditions were 95 percent
of the acid soluble alumina (approximately half the alumina content of the
shale). An attractive feature of the leaching was that the leached pulp and
liquor did not become gelatinous nor did slimes develop, and the residue was
easily washed.
Economics of a postulated mining, retorting and by-products recovery
plant employing (1) including physical separation of nahcolite from the raw
shale, (2) conversion of part of the nahcolite to soda ash, and (3) recovery of
alumina via the caustic leach process have been reported. Based on a plant
processing 27,210 kkg/day (30,000 ton/day) of oil shale containing 21 percent
nahcolite, 12 percent dawsonite and 15 percent organic material, total capital
costs have been estimated at $140 million (based on 1968 costs escalated to
late 1973). Of this total $31 million is for the mine, $13 million for the
retort, $63 million for the alumina plant, and $33 million for the nahcolite
and soda ash plants. By-products from the plant includes 5714 kkg/day (6300
ton/day) of nahcolite separated after the crushing step, with 1596 kkg/day
(1760 ton/day) converted to soda ash. Spent shale is crushed, leached,
filtered, washed, precipitated with CO., thickened, washed and calcined to
produce 907 kkg/day (1000 ton/day) of alumina. Three quarters of the gross
(22)
revenue of over $64 million per year is derived from the sale of byproducts .
Although these economics look favorable, sufficient markets for the nahcolite
and soda ash are questionable and plans to incorporate such an alumina recovery
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75
process in the proposed 50,000 bbl/day facility to be constructed in 1974
has not been reported.
Acid mine drainage pollution control utilizing nahcolite directly
or by way of soda ash from nahcolite is another possibility. The potential
consumption could be in the range of 3.5-4.5 MM kkg/yr (4-5 MM tons/yr).
Present control of this huge acid pollution problem is either by neutralization
with dolomite or limestone, or is nonexistent. Such treatment while beneficial
has the undesirable effect of adding large amounts of calcium and magnesium
hardness to the effluent. The use of sodium carbonate would provide more
(22)
efficient neutralization as well as the reduction in hardness.
One other possible use for the spent shale is portland cement
clinker. As a major product of Estonian (USSR) oil shale industry, portland
cement clinker offers high strength and high resistance to frost. The pro-
duction of this clinker requires burning the shale at about 1982 C (3600 F)
in special furnaces to melt the inorganic constituents. Other uses are
(24)
(22)
(24)
bitumen for road building, fill material, raw material for brick manu-
facture, and glass making.
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76
VII. OTHER ENVIRONMENTAL CONSIDERATIONS
The impact of the various oil production processes on waste genera-
tion has been discussed in previous chapters. However, it is important to
consider the impacts of oil-shale industry on land and landscape, general
aesthetics and recreation, noise, vegetation, economic and social develop-
ment, and water resources and quality. These areas of concern are reviewed
briefly in this chapter.
Impact on Land and Landscape
An estimate of land requirements for surface mining, underground
mining, and in-situ processing is presented in Table 13 . As expected, surface
mining land requirements are the highest. After 30 years of shale development,
surface mining would require about twice the land needed for underground
mining and 5 times that needed for in-situ processing. In conclusion, the
reduced land requirement for in-situ processing and underground mining with
ex-situ retorting favor their development and use. The cumulative land
disturbed in 30 years does not seem excessive. It would not be wise, however,
to make firm conclusions without further investigation of this aspect.
Impact on Vegetation
Projected vegetation impacts associated with construction and opera-
tion of surface facilities, mining activities, overburden removal, processed
shale disposal, and development of utility corridors will vary considerably
from tract to tract depending upon the development options considered. The
physical characteristics of the individual tracts also will determine impacts.
The impact on vegetation areas disturbed for 8 types of plant communities and
for the three types of mining and processing is summarized in Table 14' .
Existing vegetation essentially will be eliminated from all land
surface allocated to surface facilities, overburden storage, stockpiling,
and waste disposal. Mining activities and waste disposal associated
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77
TABLE 13. LAND REQUIREMENTS
(ACRES)*
Requirements
Surface Mining:
Surface disposal:
With restoration
Cumulative land disturbed
Surface disposal with
backfill:
With restoration
Cumulative land disturbed
Underground Mining;
Surface disposal:
With restoration
Cumulative land disturbed
Underground disposal (oO&)
Cumulative land disturbed
In situ: With restoration
Years
5
2,400
2,450
2,450
2,450
350
350
350
300
10
2,700
3,200
2,700
3,200
700
700
600
775
20
3,300
5,000
3,300
4,300
850
1,450
800
775
30
3,400
6,650
2,700
4,600
1,110
2,210
1,090
775
* At a production rate of 50,000 bbl/day.
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TABLE 14. VEGETATION IMPACT AREAS -UNDERGROUND MINE, SURFACE MINE, IN SITU
(8)
Plant Ci— Munltles
Lormv slcpi*4
bis SJ|Xi servlca-
cciry, hhcatgrasa
Plnxon-U'nlper
l'ln>an, Juniper,
servlccberry, stlpa
Roll tnc lo.ini
S.icebruvh. wheat*
grass
fcep loan
Sagebrush, atlpa
Mountain swale
Khcatgrass, vlldryt
Lomv hriiiVs
Blttcrbrush,
eervlcebcrry
Rourli brc
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79
with underground mines will destroy the vegetation on small areas
around the mine openings.
Vegetation changes will take place on the entire surface area
involved in in-situ shale oil extraction activities. Existing vegetation
will be eliminated from drill pad sites and the vegetation on the areas
between drill pads will be damaged by trampling and mobile equipment operations.
Utility corridor development will completely remove existing vege-
tation from portions of the corridor and much of the balance of the corridor
areas will experience substantial trampling impact from mechanical activities.
Revegetation is called for on portions of these areas when back-
filling and surface placement of overburden has progressed to a point where
workable areas are available for rehabilitation and when construction is
complete in utility corridors and operations have progressed through in-situ
areas that have been developed.
The existing vegetative complexes of these areas have evolved over
long periods of time. The species and species groups are interdependent and
In a reasonable degree of natural balance and stability. The natural balance
between species and groups of species will be altered in some processing
options (for example, in-situ processing) or completely destroyed in others,
such as mine development and processed shale disposal areas.
In general, revegetation can be initiated on such disturbed areas as
soon as activity is terminated. The nature of the resulting new plant
communities and the pattern of the ensuing successional changes will also vary
distinctly from site to site depending upon site characteristics, types of
disturbance, species planted, revegetation methods, and subsequent management.
A considerable body of information is available on revegetating
native soils. Relatively successful cover establishment can be anticipated on
disturbed native soils in areas such as utility corridors, and roadside cuts.
Information on revegetation of processed shale and deeply disturbed parent soil
materials is rather limited, research having emphasized grasses with only
limited attention having been given to forbs and almost no long-term studies on
shrubs. Thus, the optimum selection of species, germination and survival rate,
and expected density of cover have not yet been fully established nor can the
future pattern of succession be predicted with certainty.
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80
If mixtures of native species, which include the major climax (or
desired sub-climax) species, are used to revegetate disturbed native soils,
natural progression may be relatively rapid. The planting of older age
class shrub and tree seedlings could accelerate the establishment of more
stable plant communities.
If exotic species are used, particularly as monocultures, successful
changes will be much more extensive as the introduced species will eventually
be replaced by natives beginning with aggressive invader species and ending
with climax or "use sub-climax" species. Exotic plant monocultures can survive
for extended periods with adequate management. However, they are susceptible to
severe set-back by adverse climatic conditions and insect or disease infections,
destroying the cover and increasing erosion. Maintenance of non-native species
would therefore require long-term management.
Establishment of initial cover and successional change on processed
shale disposal sites will be constrained by the plant growth media, and the
semi-arid climate, exposure, slope, and cultural practices, Including temporary
irrigation and fertilization. Revegetated processed shale areas will be
fragile sites highly susceptible to damage from biotic influences such as
improper grazing or fire.
Impacts on Grazing
Development of an oil shale operation would affect grazing by removing
land from grazing use, by disrupting livestock travel routes, and possibly by
loss of watering facilities, but the impact would only be minor. Only the land
actually occupied by the mining operations, the processing plant, waste disposal
and related facilities would be removed from grazing use. Thus the extent of
grazing loss would depend upon the mining method used and the rates and success
of the rehabilitation measures.
The approximate reduction in grazing use of land that would be
expected from 50,000 barrels per day of shale oil production operation for
various mining and/or processing options is shown in Table 15.
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81
TABLE 15. ACREAGE REDUCTION FOR GRAZING
Operation
Open Pit
Open Pit
(w/backfill)
Underground
In situ
Total Acres
Affected
6,650
4,600
2,210
1,510
Average Grazing
Area Loss
Acres/yr.
3,000
2,800
1,100
720
Average
Grazing Loss
AUM/yrCa)
353
329
129
aa
30-yr Accumu-
lative Total
AUM Loss
10,590
9,880
3,880
2,650
(a) The animal unit months (AUM) of grazing loss figures are based upon
an average carrying capacity of 8.5 acres/AUM for Track C-a and 7.9
acres/AUM for Track C-b.
Noise Impacts
During the initial exploration and construction phases on any of
the selected tracts, the noise resulting from diesel trucks, compressors,
mixers, drills, and other general construction machinery and vehicles might
cause certain wildlife on or near the tract to move to other locations.
Once commercial-level operations are attained at each tract, it
can be expected that the general noise level on each tract would increase
over that associated with construction. Conventional surface mining would
require power shovels, earthmovers, conveyors, and grinders that would generate
considerable noise on or near the tracts. Similar problems, but with less
intensity, would occur with underground mining techniques. Blasting, perhaps
three times per day per operation, would create a routine disturbance and
annoyance to the few local ranchers and wildlife. Retorting and upgrading
processes would emit noises quite similar to those for petroleum refinery
operations, although the level of such noise would depend on the specific
processes employed. For the in-sltu extractive processes, underground blasting,
compressors, pumps, etc., would provide obvious noise sources.
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82
General Esthetics and Recreation
Presently the area where the Green River oil shale deposits occur
is remote and sparsely used by hunters and ranchers as well as oil and gas
industry personnel. There is little incidence of air pollution, other than
dust from vehicles and smoke from occasional wildfires. Noise is intermittent,
and its primary sources are related to aircraft passage and scattered drilling
rigs exploring for oil, natural gas, or oil shale resources. The natural
landscape of the area is in some places interspersed by roads and trails,
cleared fence lines and gas pipelines on cleared rights-of-way.
Assuming surface-mine development, the tract would lose its
natural quiet at the mine and plant site. Noises associated with the activities
of the operation will be greatest at the mine and plant sites and at spent
shale disposal areas.
Air quality would be slightly degraded due to the dust from oil shale
operations and vehicles associated with such operations. Impact from the mine
and retort may not be noticeable in the immediate area during the summer months
since meteorological lifting will disperse particles in prevailing winds aloft.
However, inversions during the winter months occasionally may trap and concentrate
emissions over the Piceance Basin and could result in accumulation of particulate
contaminants in the atmosphere.
The visual impact from the disposal of spent shale and over-burden
storage would be noticeable until restoration activities are completed. A
plant would be visible from ridge tops kilometers away. Spent shale disposal
in some cases would alter the view of scenic areas from atop bluffs. However,
the development of a large surface mine would provide an unusual attraction which
could increase tourist traffic. Some visual impact on the asymmetric landscape
would result from utility rights-of-way such as pipelines, powerlines, roads,
and stacks and plumes. During the first 5 years, surface mine development
would eliminate some of the existing recreation areas. After vegetation has
been successfully reestablished on a site, the area would be able to sustain
levels of recreation that may be similar to those previously existing.
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83
With underground mining, recreation opportunities lost would be
small during the first 5 years; with 30 and 50 percent in 20 and 30 years,
respectively, assuming no rehabilitation, and 15 and 20 percent with
rehabilitation.
With in-situ mining, the recreational area lost would be approximately
20 percent after 10 years operation.
Deer hunters will be displaced from the same areas to other areas in
the Ficeance Creek Basin and/or adjacent regions. These hunters, as well as
those related to normal population growth, will increase hunter density in
the adjacent areas, thus lowering the existing quality of the hunting experience.
Outdoor recreational benefits which may be gained because of improved
accessibility include sightseeing, both on and off the road camping, and fishing
throughout the basin and on adjacent private and public lands. In addition, the
oil shale project may increase visitor use of the basin as a tourist attraction
beyond that of normal outdoor recreation activities.
Pipelines, power lines, roads and other service facilities would
change the existing landscape. Noise created by crushing and retorting
operations and the movement of heavy equipment in disposing of spent shales would
impact the aesthetic value of the area, as would the minor petroleum odors from
the retorted hydrocarbon liquids and gases.
Economic and Social Development
Population
The 1970 population of the tri-state oil shale area was about 120,000
persons and is at present probably the same. For each 50,000 barrel per day of
oil shale the population is expected to increase by 8,600 persons during the
3 year construction period and thereafter by 6,200 persons as a permanent
increase. An additional permanent increase in population of about 600 persons
would result from the influx of persons in business fields and service industries
to accommodate the increased population employed by the oil shape industry,
making a total permanent increase of 6,800 persons in the area population for
each 50,000 barrel per day operation. With the probability of several such
operations it is evident that a tremendous population increase could in 5 to 10
years result for the area under consideration.
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84
Tax Revenue
In the tri-state area in recent years tax revenue has varied,
according to location and at different times from $112 to $325 per capita.
It is expected that with the start and with the significant expansion of an
oil shale industry this revenue would increase considerably to a level of
around $1,000 per capita.
Personal Income
No estimates are available concerning the average per capita
income in the area, but it would probably increase several orders of magnitude
over present levels.
Commuting Patterns
Commuting patterns would change drastically from present patterns
for evident reasons, and the changes would result in not only the improvement
of present roads and highways, but the construction of many miles of new ones.
Building Industry
There would be a "boom" in the building industry because of the need for
industrial, business, and residential construction to serve the new oil shale
industry of the area. Whole new towns probably would be created.
Zoning and Planning
Good zoning and building codes will be necessary to insure the
quality of industrial and urban development.
Nonagricultural employment is at present evenly divided between white
collar and blue collar jobs. Most of the oil shale plant jobs will be blue
collar jobs, but the new urban support jobs associated with expanding communities
will be white collar and service. The overall composition of employment will
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85
shift to a larger percentage of blue collar jobs. These shifts in the
composition of urban populations could cause strains to develop between the
established residents and the newcomers. A mutual effort will be needed
to mitigate these strains if they occur.
Demand for Public Utilities. Police, and Fire Protection
Increased population and development will raise local demands for
these factors in the total picture. Increased tax revenue, however, should
be readily adequate to satisfy such demands.
Water Resources and Quality
Water resources of the oil shale regions of Colorado, Utah, and
Wyoming are complex and varied. Surface water supplies, most of which
originate from the higher elevations due to rainfall and/or snowmelt, are
available from the area's large rivers - the Green, the White, and the Colorado.
Groundwater is also a potential source of water for oil shale development,
particularly within the Piceance Creek Basin of Colorado.
Demand for water will be created for use in processing as well as
for use in communities that will be required to support industrial development.
The water required for processing and for associated urban populations has
been the subject of several investigations. These studies have provided
important background information concerning the general range of water require-
ments including water requirements not only for mining and crushing, but also
for shale disposal and revegetation and for cooling water for process and
domestic power.
Water consumed in processing and that consumed for an associated
urban population are listed separately in Table 16 for various 50,000 bbl/day
extraction methods. This table was based on the sources discussed below.
-------
TABLE 16.
86
WATER CONSUMED BY OPTIONAL MININGg.
METHODS FOR SHALE OIL PRODUCTION
(Acre-feet/year)
Shale Oil Production (Barrels per day)
PROCESS REQUIREMENTS
Mining and Crushing
Retorting
Shale Oil Upgrading
Processed Shale Disposal
Power Requirements
Revegetation
Sanitary Use
Subtotal
ASSOCIATED URBAN
Domestic Use
Domestic Power
Subtotal
GRAND TOTAL
AVERAGE VALUE
50,000
Underground
370-510
580-730
1,460-2,190, ,
2, 900-4, 400 w
730-1020
0-700
20-50
6,060-9000
670-910
70-90
740-1,000
6,800-10,600
8,700
50,000
Surface Mine
365-510
585-730
1,460-2,190
2,920-4,375
730-1,020
0-350
15-35
6,075-9,210
570-765
55-75
625-840
6,700-10,050
8,400
50,000
In Situ
730-1,820
0-700
20-40
2,210-4,780
720-840
70-80
790-920
3,000-5,700
4,400
(a) Water used is 20% by weight of the disposed spent shale.
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87
Water requirements for mining, crushing, retorting, and shale-oil
upgrading are based on process engineering studies by the U.S. Bureau of
Mines; water power requirements are based on Jimeson and Adkins. ' ' The water
needs for shale disposal are based on stability research by Denver Research
Institute, on experimental work by Colorado State University,and by the Colony
Development Operation. Water requirements for revegetation of processed or
spent shale will range from zero as a given area is built up, to about 1 foot
per year for each acre to be revegetated. Urban population water requirements
associated with a given plant size were made by the U.S. Bureau of Mines, and
the water demands per capita have been obtained from the work of Ryan and Wells.
A block diagram depicting the demand and supply of water for two
regions are presented in Figures 13 and 14 for different tracts* in the
Green River basin. Each of these diagrams is based on a 50,000 bbl/day plant
for an underground mine,ex-situ plant. The diagram of Figure 14 shows that
significant amounts of mine water to meet the demands for low quality water
at the plant are available. It is suggested that it may be possible to operate
the plant with a low withdrawal rate from the mine so that problems of its
disposal are minimized. If mining operations require a higher withdrawal rate
than plant water demands, the excess water will have to be released to either the
natural creek or the river after treatment. This is another area that requires
considerable study.
* The tracts U-a and U-b, and C-b are as referenced in Volume III of Reference (5),
-------
SURFACE SOURCES
0.
MINING
AND
CRUSHING
L
i
rt
LOW QUALITY WATER
A
2-0.5
\
RETORTING
/
\
1
0
V
.4-
.7
^
o.
5.
1
PROCESSED
SHALE
DISPOSAL
<3 °'2
0.8-1
0.5-0
o-
6
2.
HIGH QUALIT
-3.
\
7
SHALE
OIL UP
GRADING
A
.0
.7
1
r
^
YWATFB K *
1.0-1.3
0-1.
1. 1-1.5 1
v . V
POWER REVEGE- /
REQUIREMENTS TAT ION I
r
SANITARY
JSE
1
ASSOCIATED
JRBAN
OB
oo
FIGURE 13. DEMAND AND SUPPLY FOR WATER :
50,000 Barrel Per Day Underground Mine,
Tracts U-a and U-b (cu.ft. per sec)
-------
MINE WATER
0-28.
0-12.
0-28
I EXCESS WATERS
t-w
jr
SURFACE SOURCES
0.5-0.7 0.2-0.5
.MINING
!&
!CRUSHING
0-14.
LOW QUALITY
WATER
RETORTING
PROCESSED
SHALE
DISPOSAL
0.8-1.0
0-0.7
HIGH QUALITY
WATER
2.-3.
SHALE OIL
UP
GRADING
0.1
1.0-1.3
0-1.
1.1-1.5
POWER
REQUIRE-
MENTS
REVEGE-
TATION
ASSOCIATED
URBAN
00
\o
FIGURE 14. DEMAND AND SUPPLY FOR WATER: 50,000 Barrel Per Day Underground Mine, Tract C-b
(cu. ft. per sec.) (Assumes 40 cis pumped initially, of which 12 cfs is of high
quality water and 28 cfs is of low quality water)
-------
90
VIII. PRODUCT TREATMENT AND USAGE
The usage of the products and by-products from the oil shale
industry is reviewed in this chapter. The review covers product composition
as a function of retorting method, required treatment prior to use, and the
economic and environmental impact and energy capability resulting from the
use of these new products.
Gaseous Products
Gas Composition as a Function of Retorting Method
Different retort gas compositions will result from different
retorting methods. The compositions of the retort gases and the reasons for
their differences, discussed in detail in the section on retorting, will be
briefly reviewed here.
Shale oil is heated to the vapor state, drawn out of the retort
and thereby separated from the oil shale. In the process a certain quantity
of retort gas is also produced from the cracking of the hydrocarbons. The
quantity and quality of this retort gas depend to a large extent on the
method and temperature of heating. Basically, there are three retorting
schemes, 1) internal combustion retorting, 2) indirect heat retorting and
3) in-situ retorting. These schemes are summarized below.
1) Retorting by Internal Combustion Heating: crushed shale
is feed to a vertical kiln wherein a major portion of the
shale oil is liberated by pyrolysis. The organic residue
remaining on the depleted shale is ignited with the addition
of combustion air and recycle gas. The gases produced,
containing valuable cracked hydrocarbons, are diluted by the
combustion air, carbon dioxide, and by the products of the
thermal decomposition of inorganic carbonates.
-------
91
2) Retorting by Indirect Heating: crushed shale is fed to a
vertical kiln or horizontal rotary kiln wherein a major
portion of the shale oil is liberated from the oil shale
by pyrolysis. Heat is supplied not by internal combustion
but by introduction of some heat transferring medium such
as heated retort gas or heated ceramic balls. The gases
produced therefore contain primarily cracked hydrocarbons
and very little inerts. In addition, since indirect
heating can'often be carried out at lower temperatures
the extent of carbonate decomposition and hence dilution
of the retort gas by CO is reduced or avoided completely.
3) Retorting by In-Situ Combustion Heating: unmined oil shale
in the formation (or in-situ) is artificially fractured to
induce mass permeability. The formation is then ignited to
generate heat and gases which liberate the oil from the oil
shale by pyrolysis. Air and recycle gases are introduced
through the injection well to provide (a) oxygen for the
combustion process, (b) supplemental fuel for additional
heating, and (c) a force to drive the combustion zone
through the reservoir towards the producing wells. Because
of the massive quantities of air employed the retort gas
produced is severely diluted by nitrogen and oxygen.
The composition of the major constituents, heating values, and
yields typical of the three retorting methods are summarized in Table 17.
Treatment Necessary Prior to Use
Because the expected uses of retort gases are retort heating and
site electrical power and steam generation, treatment necessary prior to use
is restricted primarily to sulfur removal. Processes employing internal
combustion or in-situ retorting produce a gas diluted to a low sulfur
-------
TABLE 17. CHARACTERISTICS AND YIELDS OF UNTREATED RETORT GASES
(5,25)
Type of Retorting
Composition, vol. pet
. .
Nitrogen
Carbon monoxide
Carbon dioxide
Hydrogen Sulfide
Hydrogen
Hydrocarbons
Oxygen
Gross Heating Value
kcal/scm
(Btu/scf)
Molecular Weight
Yield, scm/bbl oil(c)
(scf/bbl oil)
Internal
(b)
60.1
4.7
29.7
0.1
2.2
3.2
— —
747
(83)
32
582
(20,560)
Combustion
(b)
62.1
2.3
24.5
0.1
5.7
5.3
—
900
(100)
30
309
(10,900)
Indirectly
As v
Produced
—
4.0
23.6
4.7
24.8
42.9
— —
6975
(775)
25
25.8
(923)
Process
Heated
After
Desulfurization
—
4.2
24.8
(0.02)
26.0
45.0
— —
7335
(815)
24.7
24.7
(880)
In-Situ
75.5
0.5
15.7
0.1
(not reported)
1.8
6.8
270
(30)
28.7
(29.700)
NO
K>
(a) Includes oxygen of less than 1.0 volume percent.
(b) First analysis reflects relatively high-temperature retorting in comparison with second, promoting
higher yield of carbon oxides from shale carbonate and relatively high yield of total gas.
(c) Oil from the retort, or shale formation.
-------
93
concentration which makes prior treatment for desulfurization economically
unattractive. Such processes most likely will require stack gas scrubbing
to meet air quality standards.
Processes employing indirectly heated retorts have the advantage
that they produce an undiluted, relatively high sulfur-concentration gas
amenable to economical gas desulfurization techniques. The actual process
steps, the same as those employed for gases produced in the crude shale
oil upgrading processes, will be described in detail in a following
section outlining the shale oil upgrading procedures.
Economic Impact of Gaseous Products
Gaseous products produced either by retorting or on-slte
upgrading of the crude shale oil are expected to be consumed at either the
retorting or upgrading- facilities or for the generation of on-site
electrical power and steam requirements. Even if a high Btu gas could be
produced in quantities large enough to exceed on-site requirements, the
volume available for export would not be significant in comparison to
other sources of gaseous fuels.
Environmental Impact of Gaseous Products
The environmental impact of product gas usage, since the vast
majority will be consumed on-site, will be a local problem Involved
mainly in combustion processes. Technology is currently available for
adequate partlculate control. However, control of sulfur and nitrogen
oxides have not reached such an advanced stage. Combustion, without
control of these emissions, could have a significant effect with a
developed industry (300,000-400,000 bbl/day operations) because of the
relative purity of the present oil shale lands' environment. Enforcement
of current particulate and sulfur control regulations should reduce
adverse effects to an acceptable level. However, with the promulgation
of new regulations or enforcement of "nondegradation" standards, these
emissions would have to be reduced even further.
-------
94
Energy Capability of Gaseous Products
The vast majority of gaseous products will be consumed on-site as
fuel; therefore, the energy capability of these products available for export
will be very small and totally negligible on a national scale.
Crude Shale Oil Products and By-Products
Shale Oil Composition as a Function of Retorting Method
Crude shale oil from Green River oil shale varies slightly in its
characteristics, depending on the above ground retorting method used. The
geographic area and the geologic age of a particular oil shale zone appears
to have only a minor influence on the properties of the oil. Information
on the crude oil produced from in-situ retorting is more limited; however,
as noted in Tab],e 18 it has a much lower pour point and viscosity — low
enough to permit pipelining without further processing. Another difference,
not noted in the table, is that in-situ oil is more highly saturated and
contains more than twice the naphtha and light distillate content of oil pro-
duced by above-ground retorting. These characteristics indicate that, with
exception of degree of saturation, in-situ crude shale oil is similar to the
coker distillates from other crude oils and suggests that similar refining
(27)
techniques should be appropriate.
Table 19 displays typical properties of crude shale oil
produced by above ground retorting and syncrude (crude shale oil upgraded
by a catalytic hydrogenation process). Similar data for in-situ crude
oil are not available. Over 50 volume percent of the in-situ oils boil
below 316 C (600 F), compared with approximately 30 percent of most
ex-situ shale oils. The fraction of the in-situ oil having a boiling
range from 425-535 C (800 to 1000 F) ranged from 12 to 18 percent,
compared with 27 to 57 percent characteristic oils from above ground
(25)
retorts. This in effect states the production of lower boiling
distillates will be greater from in-situ crude and the production of
coke will be greater from shale oil extracted by ex-situ methods.
-------
95
TABLE 18. CHARACTERISTICS OF CRUDE SHALE OILS
(13,27)
Retorting Process
Gravity, API
Sulfur, wt %
Nitrogen, wt %
Pour Point, C
(F)
Viscosity, centlstoke @ 38 C
(SUS @ 100 F)
Gas Combustion
19.7
0.74
2.18
28
(80)
55.3
(256)
Union (a)
20.7
0.77
2.01
32
(90)
48
(223)
TOSCO *b^
28.0
0.80
1.70
23
(75)
25.4
(120)
In Situ(c)
36.2
0.79
1.14
-13
(9).
5.2
(43)
(a) Typical of product from original Union process.
(b) Unpublished Information submitted by Colony Development Operation indicates
TOSCO crude shale oil may have gravity as low as 21 API and sulfur content
of 0.75 wt %.
(c) Average of values presented in Table 2.
-------
96
TABLE 19. TYPICAL PROPERTIES OF CRUDE SHALE OIL AND SYNCRUDE
CD
Gravity, API
Pour Point, C
(F)
Sulfur, wt %
Nitrogen, wt %
Reid Vapor Pressure, atm
(psi)
Viscosity, centistoke @ 38 C
(SUS @ 100 F)
Analysis of Fractions
Butanes and Butenes, vol %
C--177 C (350 F) Naphtha
Vol %
Gravity, °API
Sulfur, wt %
Nitrogen, wt %
K Factor
Aromatics, vol %
Naphthenes, vol %
Paraffins, vol %
177-288 C (350-550 F) Distillate
Vol %
Gravity, °API
Sulfur, wt %
Nitrogen, wt %
Aromatics, vol %
Freezing Point, C (F)
288-455 C (555-850 F) Distillate
Vol %
Gravity, "API
Sulfur, wt %
Nitrogen, wt %
Pour Point, C (F)
455 C (850 F) - Plus Residue
Vol %
Gravity, °API
Sulfur, wt %
Nitrogen, wt %
Crude
Shale Oil
28.0
24
(75)
0.8
1.7
-
-
25.4
(120)
19.1
50.0
0.70
0.75
11.7
-
-
—
17.3
31.0
0.80
1.35
-
-
33.0
21.0
0.80
1.90
-
26.0
12.0
1.0
2.4
Syncrude
46.2
10
(50)
0.005
0.035
1.5
(8)
4.3
(40)
27.5
54.5
^0.0001
0.0001
12.0
18
37
45
41.0
38.3
0.0008
0.0075
34
-37 (-35)
22.5
33.1
40.01
0.12
27 (80)
None
-------
97
Necessary Treatment Prior to Use
Crude shale oil produced b> both ex-situ and in-situ retorting is
a black, viscous, foul-smelling, high nitrogen, relatively high sulfur oil
that is usually a slushy solid at room temperature. It tends to form
sludge and otherwise deteriorate if stored for prolonged periods of time.
Direct combustion of this material as fuel is not considered likely. Instead,
on-site upgrading to convert the crude shale oil to pipeline quality, followed
by processing at a petroleum refinery is considered the most likely scheme
for recovery of fuel and chemical products.
Shale oil has several qualities which make it a superior refinery
feedstock. There is essentially no fuel-oil cut in the shale oil which means
a higher yield of gasoline and middle distillates, shale oil has a lower
sulfur and nitrogen content, after upgrading, than most crudes, and it has a
lower aromatic content. Shale oil does, however, have a higher percentage
of unstable molecules that have a tendency to react to form gums and other
undesirable compounds. Although it has some unusual characteristics, it is
similar in most respects to conventional crude oil and can be accepted for
processing by conventional techniques to manufacture high-quality petroleum
products including gasoline, jet and diesel fuels, and domestic and industrial
heating oils.
Crude shale oil from in-situ retorting, as noted earlier, has
certain physical and chemical properties different from shale oil produced
by above ground retorting. These differences will allow direct pumping to
refineries for processing with no prior upgrading. It appears unlikely that a
large refining industry will develop in the area of the oil shale deposits.
The market for products in this area is small and it is preferable, for
economic reasons, to transport crude oil out of the area rather than finished
products. An additional and perhaps even more compelling motivation for
avoiding refining near the oil shale retorting area is the limited water
resources.
-------
98
It can be expected however, that early oil shale plants will
include facilities for upgrading shale oil. Upgrading is necessary
because shale oil has a high pour point and viscosity which need to be
reduced to facilitate handling in pipelines. In addition, upgrading is
necessary to remove the unusually high concentration of nitrogen compounds
which would otherwise deactivate catalysts used in petroleum refining
processes such as catalytic cracking, hydrocracklng and reforming.
Thus, the necessary treatment prior to use of the crude shale
oil can be divided into two stages: (1) on-site upgrading of crude shale
to pipeline quality through processing for the removal of nitrogen and
sulfur, and (2) refining the syncrude (crude shale oil subjected to
catalytic hydrogenation) to fuel products and chemicals.
On-Site Upgrading—Coking and Hydrotreatlng of Distillate. There
are a number of possible processing sequences and proprietary processes
suitable for removing nitrogen from shale oil. One set of alternatives
that is applicable to a typical crude shale oil is illustrated in Figure 15.
In this scheme the crude shale oil is heated to vaporize a portion of the
oil and the resulting mixture of liquid and vapor is fed to a distillation
column in which light oil, naphtha and gas are removed from the upper section
of the column and heavy oil and resid are removed from the bottom section.
The resid is further heated and processed in a delayed coking
unit wherein a thermal cracking process with chemical reactions similar to
those in retorting takes place. The products from coking are petroleum coke
and a vapor stream containing gas, naphtha, light oil and heavy oil. This
vapor stream flows back to the crude distillation and gas processing units
for separation of the various constituents. The products of the gas
processing section are specifically: high quality fuel gas, light naphtha
and by-product hydrogen sulfide from which sulfur can be obtained. The
products of distillation are naphtha and light and heavy distillates.
-------
GAS
TREATING
HYDROGEN SULRDE
NAPHTHA
NAPHTHA
S50"F EP-
LIGHT OIL
AND NAPHTHA
LIGHT
OIL
• STEAM
• PROCESS GAS
• FUEL GAS
ni.QTiiiAi.nM A HEAVY OIL
CRUDE SHALE OIL
104.000 B/CO
'EnH Point
4
•MMM
k
A
VAI
'OR
w
RESID r
DELAYED
COKER
CATALYTIC
HYDRO-
GENATION
H7
HYDROGEN
PLANT
CATALYTIC
HYDRO-
GENATION
WATER
WATER
STABILIZER
SEPARATOR
0
AMMONIA -
HYDROGEN
SULFIDE
SEPARATION
SULFUR
PLANT
FUEL GAS
100.000 B/CD
SYNCRUDE
253 i,C()
AMflCJNiA
1UO I/CO
SULFUR
50 T/CD ^
COKE
FIGURE 15. FLOW DIAGRAM FOR UPGRADING CRUDE SHALE OIL
(1)
-------
100
The naphtha, light oil and heavy oil from the retorting and
coking steps are hydrogenated to remove nitrogen. The hydrogenation
process comprises heating the oil feed to an elevated temperature i.e.,
316-455 C and treating with a catalyst in the presence of hydrogen at
elevated pressure i.e., 41.8-205.2 atm (600 to 3000 psi). The reaction
produces sulfur-free, low nitrogen-content hydrogenated oils, ammonia,
hydrogen sulfide and a small amount of gas. The hydrogenated oils are
then blended with butanes, pentanes and hexanes from gas and naphtha
treating to produce the finished syncrude.
The products from the hydrogenation unit are mixed with water
to remove ammonia and hydrogen sulfide. This water stream is then
separated by gravity from the oil and gas products and is distilled to
separate hydrogen sulfide and ammonia from each other and from the water.
The water is recycled. The ammonia, produced at a rate of approximately
2.3 kg/bbl (5 Ib/bbl), is liquified for storage and sale. Hydrogen sulfide
is converted by the conventional Glaus Process to elemental sulfur
(0.9 kg/bbl) and can be sold as such. The small amount of gas formed in
the catalytic hydrogenation process is separated from the hydrotreated
synthetic crude by distillation and can be used for plant fuel or for hydrogen
plant feed. Hydrogen required in the catalytic hydrogenation process is
manufactured by reforming of natural gas or other light hydrocarbons by
catalytic, high-temperature reaction with steam. '
There are a number of variations which can be applied to the
processing sequence shown in Figure 15 Including: (a) addition of a second-
stage vacuum distillation for the feed to cause more of the crude shale oil
to flow directly to hydrogenation and, if carried far enough, eliminating
delayed coking, (b) replacement of the delayed coking unit with a catalytic
hydrotreating system designed for heavy oil, (c) combining hydrogenation
units for the naphtha and gas oils, and (d) generation of hydrogen by
partial oxidation of oil rather than reforming of light hydrocarbons. However,
the scheme shown has been researched a great deal and is relatively simple.
-------
101
Refining Syncrude. The refinery operations to convert syncrude
to marketable petroleum products has received less attention than the
required on-site upgrading processes because it believed that currently
employed refining techniques can easily be adapted to process syncrude.
Commercial processing of shale oil was performed on a limited basis
(20,000 bbl) at American Gilsonite Company's Grand Junction, Colorado,
(20)
refinery in 1961 using shale oil produced in the Union Oil retort.
Regular and premium gasoline were among the products produced by a three
step upgrading-refining scheme. These steps were: (1) upgrading by
coking, (2) upgrading by hydrogenation, and (3) refining by hydrocracking
or catcracking and reforming. More recent investigations were conducted
by Phillips Petroleum Company. Researchers postulated that the most
economic sequence of refining steps, displayed in Figure 16, would
be recycle coking and hydrostabilization in one or more passes and fractionation.
Distillates requiring further nitrogen reduction (to avoid catalyst poisoning)
would be separately processed. Naphtha would be reformed to increase octane
number by dehydrogenation of naphthenes to aromatics and isomerization of
paraffins. Heavier distillates would be catalytically cracked to products
of lower boiling ranges. It was concluded from this work that the refining
processes used—coking and hydrostabilization (upgrading), hydro-denitrificatlon,
reforming and cracking — converted raw shale oil into petroleum products
suitable for sale in present markets, and the processes were capable of sus-
tained operation. Optimization is considered likely upon further study of the
process variables.
Economic Impact of Shale Oil Products
The products derivable from shale oil by upgrading and refining
operations are listed in Table 20. Products from shale oil are expected to
enter the fuels and chemicals market as a supplement to domestic production.
The fully developed oil shale industry is envisioned to be limited to
approximately 5 million bbl/day because of water scarcity and other restricting
conditions discussed throughout this report. At this rate gasoline, jet, and
diesel fuel from oil shale will not supplant domestic oil production. Regardless,
both the refined oil and by-products from processing the crude shale oil and
syncrude will have a significant impact on the domestic economy.
-------
102
Raw
Shale •»
Oil
Gas
C5-400
«*
V
400"*
H0
JLJ
Gas
c
o
vl
4J
fl)
O
Vl
4J
•rl
C!
i
Vl
H20 Gas
Sr
C5-400
Gas
A
V
4004
c
o
•rl
4J
(9
g
C5-180
180-400
400-650
4J
U
eg
u
73
•H
3
"2°
650+
Gas
H2
1
e
o
M-l
••-I
H
4J
T<
C
4)
•8
Gas
1
0)
£
o
v
± Reformate
FIGURE 16. REFINING OF SHALE OIL
(28)
-------
103
(1,2,5,29)
TABLE 20. PRODUCTS FROM SHALE OIL PROCESSING
Processing Product
Upgrading Ammonia
Sulfur
Green Coke
Syncrude
Gas
Refining Gasoline
Jet and diesel fuels
Domestic and industrial heating oil
Solvents
Paraffin wax
Asphalt
Petrochemical plant feed stock
Tar acids
Tar bases
-------
104
By-products obtained from the upgrading of crude shale oil —
sulfur, ammonia, green coke, and fuel gas — could add new supplies to the
economy. Production at the 1 million bbl/day level could provide upwards
of 4 percent of the U.S. sulfur demand and 7 percent of ammonia demand (based
on 1968 figures). The green coke and fuel gas produced are expected to supply
nearly all the on-site energy needs. The coke may be utilized as a more
valuable raw material in metallurgical uses or for manufacture of electrodes.
By-products from shale oil refining are expected to be typical of the petroleum
industry. The major by-products, noted previously , will probably be solvents,
paraffin wax, asphalt, and petrochemical feedstocks (such as ethylene,
propylene, butylene, benzene and naphtha). Some of the major petrochemical
products derived from these raw materials are organic chemicals, synthetic
rubber, plastics, carbon black, and synthetic fibers. Some by-products not
commonly obtained from petroleum refining may be produced by shale oil
refineries. Among these are tar acids and tar bases which can be refined to
phenol and pyridine base compounds, respectively. These shale oil by-products
can be expected to have an appreciable impact on the chemical and petrochemical
industries—resulting in shale oil refineries operation modified specifically
to market demand for by-products as well as the main products.
Environmental Impact of Shale Oil Products
The impact of both the main products and by-products from shale
oil processing on the environment is restricted to that resulting from
the product's usage. Fuels produced from upgraded crude shale oil will
be low in sulfur and nitrogen. Therefore, combustion of these products
should result in low sulfur and nitrogen oxide emissions. However,
since the liquid fuels produced from shale oil will be mainly gasoline
and jet and diesel fuels (fuels typically low in sulfur and nitrogen
compounds), the overall increase in emissions from combustion should be
similar to that anticipated from increased petroleum based fuel usage
rather than because of differences in properties of gasoline, jet fuel,
and diesel fuel produced from oil shale.
-------
105
By-products will provide new sources of currently employed chemicals,
not new products. Therefore, utilization of these chemicals, produced in new
low pollution facilities, will either reduce emissions by supplanting existing
(and likely more polluting) processes for the production of these chemicals,
or provide a low pollution source of additional supplies required by increasing
demand.
Energy Capability of Shale Oil Products
A well-developed shale oil industry will be capable of increasing
the domestic supplies of crude oil. The energy capability of these products
will depend on the extent of development of the industry as well as the yield
of fuels from the crude shale oil. A reasonable production schedule, provided
favorable economic, environmental, and technical influences prevail, is
displayed in Table 21.
TABLE 21. PROJECTED SHALE OIL PRODUCTION
Thousand __ ..
bbl/calendar day 10 kcal/year 10 Btu/year
1978 through mid-
year 1981
Mid-year 1981
through 1983
1984-1985
100
200
400
49.6
99.3
198.6
197
394
788
A maximum production capacity of approximately 5 MM bbl/day Is predicted
(assuming all other factors favorable) because of water availability limitations,
The production rate of 400,000 bbl/day will have a nearly insignificant effect
on the total U. S. energy supply and demand in 1985, reducing the quantity of
imported oil by only 0.7 percent. By assuming the continuing growth pattern
in both import oil requirements (0.8 MM bbl/day increase per year) and the oil
-------
106
shale industry growth (0.1 MM bbl/day increase per year), and that domestic
oil production will remain approximately constant, by the year 2000 oil shale
potentially could reduce foreign oil imports by 7 percent. However, the crude
produced by oil shale developments, expressed differently, would provide an
increase of 15 percent in domestic oil supply. Therefore, shale oil should
provide a significant long-term energy supply of liquid energy sources.
Other By-Products
The possibility of producing alumina and soda ash in addition to
shale oil was noted earlier.
Another possible product from spent oil shale is portland cement
clinker, a major product of the Estonion (USSR) oil shale industry. The
shale has been shown to offer high strength and high resistance to frost
following extended heat treatment.
Economic Impact of Other By-Products
The development of large scale facilities for the production of
alumina, nahcolite, and soda ash connected with the oil shale industry could
have a significant effect on the domestic economy. The most important
product would naturally be alumina, employed primarily for aluminum and
abrasives, chemicals production, and refractory production. Presently the
United States is heavily dependent on foreign sources for about 90 percent
of its alumina ore. Development of the vast resources available in the
oil shale regions could provide alumina (and therefore aluminum) self-
sufficiency. Estimates on the quantity of alumina obtainable depend on
the dawsonite content of the shale; however, it is estimated that a
100,000 bbl/day facility would produce anywhere from 907 to 4080 kkg/day of
(13)
alumina. Alumina production from a partially developed oil shale industry
of 400,000 bbl/day (estimated production capacity obtainable by 1985) would
produce nearly 80 percent of domestic alumina requirements, based on
4080 kkg alumina/day production from a 100,000 bbl/day facility.
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The influx of such a large new source of alumina would likely
glut existing markets, with a resultant fall in bauxite and oil shale-derived
alumina prices. However, it is unrealistic to expect oil shale alumina to
capture a majority of the existing alumina markets immediately. There-
fore, its economic impact, while still significant, will initially be some-
what limited and be gradually felt.
Soda ash from spent shale could also have appreciable economic
impact. Soda ash finds applications in glass, detergent, soaps, pulp and
paper, textile and water softeners, as well as in the manufacture of
caustic soda, sodium phosphates, and sodium bicarbonate. Present markets,
while extensive, are not expected to require the vast new quantities of soda
ash obtainable from spent shale processing. Estimates of production from a
single 100,000 bbl/day facility range from 7256 to 3447 kkg/day (8000 to
3800 ton/day)(38) of soda ash plus 23,320 kkg/day (25,600 ton/day) of sodium
(24)
bicarbonate. Coproduction of soda ash from shale on a large scale would
swamp existing markets; therefore, soda ash production based on present
demand Is envisioned to be limited. However, while uses of nahcollte are
presently limited, it shows potential as a pollution control chemical,
specifically for S02 absorption or for acid water neutralization. Estimates
of potential markets of nahcolite are very large, on the order of 550 MM kkg/yr
(600 MM tons/year).
Environmental Impact of Other By-Products
The impact of other by-products from shale oil on the environment
should be minimal. Alumina, the most likely major product, will be employed
primarily as a raw material for the production of aluminum, and as such,
would simply be displacing foreign bauxite sources. The absence of fluoride
in the oil shale alumina, the major air and water pollutant from the alumina
industry, could markedly reduce both air and water emissions resultant from
the production of aluminum.
Soda ash and nahcolite, if produced in only limited quantities,
will have little environmental impact. If employed on a larger scale, their
most likely use would be in the field of pollution control chemicals; therefore,
the overall environmental impact of their use would be positive.
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IX. RESEARCH AND DEVELOPMENT NEEDS
The Nation's oil shale resources are of great importance to this
country's future. The resources are vast* and liquid fuel which can be
produced from shale is a significant source of energy. Also, some oil shales
contain appreciable quantities of valuable aluminum and sodium minerals, and the cost
of shale-oil production, with the rapidly rising cost of crude, is becoming
more economically attractive.
Recent predictions of the rate of development of an oil shale
industry range from 100,000 to 1.3 million barrels per day by 1985, but the
fact remains that technology has yet to be developed and demonstrated on
a commercial scale. Therefore, many new processes will have to be developed
and current processes improved in the next few years in order to exploit the
vast oil shale resources. The anticipated rapid development of a now infant
industry provides a unique opportunity for the Federal EPA to monitor, advise,
and direct the developing technology into an environmentally sound industry.
The following specific research and development needs are designed for the
attainment of that goal—an environmentally sound, nonpolluting or low-
polluting industry.
Shale Mining
While mining research into various technical areas such as pillar
design, roof stability, shaft sinking, etc., is needed, environmental related
research is much more limited. Room and pillar, strip, and open pit mining
have been carried out for a number of minerals throughout areas of the
United States for a number of years. Specific precautions to avoid or limit
emissions of pollutants to the environment have been developed. Research is
needed to obtain the data required to determine the suitability of applying
current mining emission control methods to the new problems encountered in
oil shale mining. When and if current methods are found unacceptable, a
Eighteen hundred billion barrels is enough to supply all U. S. oil needs
for 250 years at current consumption levels if the resources can be recovered.
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research program should be initiated to develop new effective methods. The
program should first indicate the data to be obtained, methods to be
employed, and potential sources of such information. Then with the available
data gathered, a determination of data gaps would be possible, and a program
employing experimental mines or commercial oil-shale under ground or surface
mining operations could then be investigated to obtain the missing data.
Research also is needed in the area of methods and techniques of returning
waste shale material to worked out mine areas fur the purpose of ground
stabilization and disposal and containment of spent shale.
Ore Handling and Pretreatment
In the case of ore handling and pretreatment, there are no
recommendations for research and development to be made. Equipment required
is not unique and is readily available from producers of such equipment. The
same is true for equipment necessary for environmental control requirements
related to ore handling and pretreatment.
Retorting
The lack of experimental characterization of the effluents of
the different ex-situ and in-situ retorting processes poses as one of the
most significant data deficiencies which must be corrected. Recommended
is an experimental test program to obtain data on the largest scale
facilities practical. Such an environmental test program would determine
the quantitative pollutant loads from the various emission sources, and
by variation of certain process parameters the optimum process considering
both process efficiency and environmental consideration could be deter-
mined. Coordinated with these emission experiments must be the deter-
mination of the applicability of conventional and new control technology
for the control of emissions from the process streams employed in these
studies. Solutions to those control problems encountered could then be
sought through a control and treatment process development study which
should include pilot plant testing of the proposed control technologies.
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Additionally, another major data deficiency area is the
emission levels and the applicability of current and new control technology
required for the processing of the retort gas stream and for the upgrading
of crude shale oil. Similar to the experimental program recommended for
the retorting operations an experimental program should be initiated to
investigate the control problems likely to be encountered in the retort
gas processing area and in the shale oil upgrading operations. Such a
program should include both an emissions testing program and pilot-plant
operations for the testing of proposed control techniques.
Refuse Disposal
Specific refuse disposal research needs include large-scale
experimentation for verification and optimization of methods based on
preliminary conclusions obtained in small-scale disposal tests. Needs also
include large-scale landfill disposal tests to determine necessary proce-
dures for compaction, stability tests, run-off protection, percolation
control, leachability, impoundment facilities, etc., with an extension of
the project to include a large-scale, extended time, revegetation experiment
with investigation into different varieties of plants, fertilizers, e.g.,
commercial versus solid waste and sewage sludge, and the method and degree
of alkalinity reduction necessary. Research is needed into the refuse
conveyance systems, i.e., conveyor, truck, water slurry systems, etc. The
evaluation should Include determination of both the environmental
repercussions and economic factors such as potential mechanical problems,
necessary maintenance, required capital investment, water requirements,
and associated dams and water recovery methods necessary and their costs.
Also to be investigated is the best configuration of disposal piles,
and methods of reintroduction of spent shale into worked out mines.
The most attractive method of refuse disposal would be utilization*
Therefore, research is needed into the areas of conversion of wastes into
coproducts. Specific needs include investigation into the environmental
and economic effects of extraction methods for alumina and sodium based
minerals from raw or spent shale. Determination of the character and quantity
of effluent streams should be combined with a determination of present and
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Ill
future markets, product purity, cost of production, transportation costs with
relation to existing or future markets, and amenability of product to
current or proposed processing techniques in a complete environmental-
economic analysis.
Product Usage
Specific product usage research needs include examination of the
environmental impact of products, by-products, and coproducts from oil shale
processing when phased into the nation's economy as either a supplement to
existing supplies or as the source of new products. Processing of oil
shale will produce a fuel gas of differing heat content and sulfur concen-
tration. Research is needed to examine methods of desulfurizing this gas
either before or after combustion while utilizing a minimum of water.
Research is also needed to investigate the environmentally acceptable
modifications required by the petroleum and minerals industries to accept
these new products, e.g., modification of specific petroleum refinery
operations, including equipment selection, product split, catalyst usage, etc.,
or modification in aluminum smelting operations Including the effects
on water, air, and land pollution.
The overall objective of the research recommended here is to
produce an authoritative document on the technology of pollution control in
the oil-shale industry. Current information on environmental impacts is
based on limited testing and extrapolations from related technologies. The
document would be based on extensive and intensive field and laboratory
research with detailed cost data for each control option. While such research
may be expensive, the need for it can hardly be overlooked given the potential
imminence of this emerging industry. The oil-shale industry fortunately has
the option to plan for environmental controls in advance of its gearing up to
meet the U. S. energy needs.
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X. REFERENCES
(1) Kelley, Arnold (Chairman), "U.S. Energy Outlook, An Interim Report -
An Initial Appraisal by the Oil Shale Task Group, 1971-1985", Other
Energy Resources Subcommittee, National Petroleum Council, 1972.
(2) Schramm, L. W., "Shale Oil", Section from Bureau of Mines Bulletin
No. 650, U.S. Department of the Interior, Mineral Facts and Problems,
1970 edition, pp 185-202.
(3) Kite, Robert J. and Dyni, John R., "Potential Resources of Dawsonite and
Nahcolite in the Piceance Creek Basin, Northwest Colorado", quarterly of
the Colorado School of Mines. .62, 3, July, 1967, pp. 25-38.
(4) Matzick, A., et al., "Development of the Bureau of Mines Gas-Combustion
Oil-Shale Retorting Process" U.S. Bureau of Mines Bulletin No. 635, 1966,
199 pp.
(5) Anon., "Final Environmental Statement for the Proposed Prototype Oil
Shale Leasing Program", Volumes I-V, U.S. Department of the Interior, 1973.
(6) East, J.H., Jr. and Gardner, E. D., "Oil Shale Mining, Rifle, Colorado,
1944-1956", U.S. Bureau of Mines Bulletin No. 611, 1964, p. 163.
(7) Grant, Bruce F., "Retorting Oil Shale Underground - Problems and
Possibilities", Colorado School of Mines Quarterly. 59, 3, July, 1964,
pp. 39-46.
(8) Cameron, R. J., "Technology for Utilization of Green River Oil Shale",
Proceedings of Eighth World Petroleum Congress, £, Manufacturing, 1971,
pp. 25-34.
(9) Barnes, A. L. and Ellington, R. T., "A Look at In-Situ Oil Shale Retorting
Methods Based on Limited Heat Transfer Contact Surfaces", Colorado School
of Mines Quarterly. 63, 4, October, 1968, pp. 83-108.
(10) Duggon, P. M., Reynolds, F. S., and Root, P. J., "The Potential for In-Situ
Retorting of Oil Shale in the Ficeance Creek Basin of Northwestern
Colorado", Colorado School of Mines Quarterly, 65, 4, October, 1960,
pp. 57-72.
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(11) Anon., "Bronco Oil Shale Study", prepared by U.S. Atomic Energy Commission,
U.S. Department of the Interior, CER-Geonoclear Corporation and Laurence
Radiation Laboratory, PNE-1400, Clearinghouse for Federal Scientific and
Technical Information Service, Springfield, Virginia, 1967, p. 64.
(12) Woody, Robert H., "Firm Tables Oil Shale A-Shot Plan", Salt Lake City
Tribune. June 26, 1971.
(13) Burwell, E. L., et al., "Shale Oil Recovery by In-Situ Retorting - A Pilot
Study", Journal of Petroleum Technology, December, 1970, pp. 1520-1524.
(14) Cook, Glenn L., "Oil Shale - An Impending Energy Source", Journal of
Petroleum Technology. 4, November, 1972, pp. 1324-1330.
(15) Anon., "Chementator", Chemical Engineering. 81. 2, January 21, 1974,
p. 70.
(16) Reed, Homer and Berg, Clyde, "Shale and Air Counter-Flow in New Continuous
Retort", Petroleum Processing. ^, 12, December, 1948, pp. 1187-1192.
(17) Hartley, F. L., "Union Oil's Shale Program - Progress Report", Presented
at Colorado Mining Association Meeting, Denver, Colorado, February 7, 1957.
(18) Conn, A. L., "Developments in Refining Processes for Fuels", Chemical
Engineering Progress, 69. 12, December, 1970, pp. 11-17.
(19) Vasconcelos, Decio, C.E.B. and Padula, V.T., "Brazilian Oil Shale
Development", Eighth World Petroleum Congress, held in Moscow, USSR, 4^,
Manufacturing, Applied Science.
(20) Anon., "Shale Oil - Dig it Out, or Burn it Out", The Oil and Gas Journal.
March 9, 1964, pp. 68-70.
(21) Caffln, D.L. and Bredehoeft, "Digital Computer Modeling for Estimating
Mine - Drainage Problems, Plceance Creek Basin, Northwestern Colorado",
U.S. Geological Survey Open File Report, 1969.
(22) Anon., "By-Products Boost Oil Shale", Chemical Week. March 9, 1968,
pp. 16-18.
(23) Savage, J.W. and Biley, D., "Economic Potential of the New Sodium
Minerals Found in the Green River Formation", presented at the Symposium
on Chemical Engineering Approaches to Mineral Processing, Sixty-First
Annual Meeting, December 1-5, 1968.
(24) Anon., "Oil Shale in the U.S.-Some Shifts in Focus", Chemical Engineering.
25, 16, July 29, 1968, pp. 70-72.
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(253) Burwell, Edward L., "In-Situ Retorting of Oil Shale: Results of Two
Field Experiments", U.S. Bureau of Mines Report of Investigations No. 7783,
1973, 41 pp.
(26) Sohns, H.W. and Carpenter, H.C., "In-Situ Oil Shale Retorting", Chemical
Engineering Progress, 62, 8, August, 1966.
(27) Frost, C. M. and Cottingham, P. L., "Method for Refining Crude Shale Oil
Produced by In-Situ Retorting", U.S. Bureau of Mines Report of Investigations
No. 7844, 1974, 21 pp.
(28) Montgomery, D. P., "Refining of Pyrolytic Shale Oil", I&EC Product Research
and Development. T_, 4, December, 1968, pp 274-282.
(29) Thorne, H. M., "Retort Oil Shale for Chemicals", Petroleum Refiner. July,
1956, p. 155.
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TECHNICAL REPORT DATA
(Pit-use read Instructions on the reverse before completing)
1 REPORT NO.
EPA-650/2-74-099
3 RECIPIENT'S ACCESSION-NO
4 TITLE AND SUBTITLE
Environmental Considerations for Oil Shale
Development
5 REPORT DATE
October 1974
6. PERFORMING ORGANIZATION CODE
7 AUTHORIS)
Nick Conkle, Vernon Ellzey, and Keshava Murthy
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORG \NIZATION NAME AND ADDRESS
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-023
11 CONTRACT/GRANT NO
68-02-1323 (Task 7)
12 SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13 TYPE OF REPORT AND PERIOD COVERED
Final; 1/74-5/74
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
IB. ABSTRACT The rep0rj. gives results of B. preliminary literature survey of environmen-
tal considerations associated with the development of a shale oil industry in the U. S.
The survey was not meant to be an exhaustive analysis of the environmental aspects
of oil shale production. The study includes: oil shale deposits, mining and pretreat-
ment processes, in-situ and ex-situ retorting, refuse disposal, and produce treat-
ment and usage. The report provides an overview of the anticipated oil shale indus-
try, including available resources and the likely technical and environmental prob-
lems to be encountered. It identifies specific technologies likely to be employed in
the mining, oil extraction, and on-site upgrading processes. It also describes the
development status of these technologies and their potential economic, resource,
and environmental impacts upon the oil shale resource regions. The report notes
research and development needs required to eliminate inadequacies in the data base
necessary to evaluate potential environmental problems.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b IDENTIFIERS/OPEN ENDED TERMS
c COSATl I idd/CJroup
Air Pollution
Reviews
Oil Shale
Shale Oil
Mining
Treatment
Retort Furnaces
Refuse Disposal
Resources
Air Pollution Control
Stationary Sources
13B, 13A
05B
08G
21D
081
19 DISTRIBUTION STATEMENT
19 SECURITY CLASS (Tins Report)
Unclassified
21 NO OF PAGES
133
Unlimited
20 SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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