EPA
United States
Environmental Protection
Agency
Office of
Research and
Development
Industrial Environmental Research
Laboratory
Cincinnati, Ohio 45268
EPA-600/7-77-069
July 1977
A PRELIMINARY ASSESSMENT
OF THE ENVIRONMENTAL
IMPACTS FROM OIL SHALE
DEVELOPMENTS
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2 Environmental Protection Technology
3. Ecological Research
4 Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of. and development of. control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service. Springfield. Virginia 22161.
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EPA-600/7-77-069
July 1977
A PRELIMINARY ASSESSMENT OF THE
ENVIRONMENTAL IMPACTS FROM
OIL SHALE DEVELOPMENTS
by
K. W. Crawford, C. H. Prien
L. B. Baboolal, C. C. Sh1h, and A. A. Lee
TRW Environmental Engineering Division
Redondo Beach, California 90278
and
Denver Research Institute
Denver, Colorado 80210
Contract 68-02-1881
Project Officer
Thomas J. Powers III
Energy Systems Environmental Control Division
Industrial Environmental Research Laboratory
Cincinnati, Ohio 45268
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U. S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency, Cincinnati, Ohio, and ap-
proved for publication. Approval does not signify that the contents neces-
sarily reflect the views and policies of the U.S. Environmental Protection
Agency, nor does mention of trade names or commercial products constitute
endorsement or recommendations for use.
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FOREWORD
When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on our
health often require that new and increasingly more efficient pollution con-
trol methods be used. The Industrial Environmental Research Laboratory -
Cincinnati (lERL-Ci) assists in developing and demonstrating new and improved
methodologies that will meet these needs both efficiently and economically.
The material presented in this report summarizes the status of oil shale
technologies and development activities, the nature and sources of pollution
from oil shale development and their potential impacts on the physical envi-
ronment. This information has been collected from related on-going industrial
and government activities to provide a consolidated data source for planners
and researchers concerned with oil shale development, to identify data and
research gaps so that priorities for subsequent efforts in this area can be
defined, and to establish the baseline material from which later environ-
mental assessments can be made and related pollution control methods can be
developed. Further information can be obtained from the Energy Systems Envi-
ronmental Control Division, lERL-Cincinnati.
David G. Stephan
Director
Industrial Environmental Research Laboratory
Cincinnati
i«
11
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ABSTRACT
This Preliminary Environmental Assessment has been assembled from a wide
variety of governmental and industrial data sources, including the Detailed
Development Plans filed by federal lease tract developers as recently as June
1976. This document reviews potential environmental impacts that could result
from direct or indirect discharge of air, water, and solid wastes, and some
of the environmental control technology which has been developed or proposed.
Secondary pollution effects, such as those stemming from population influx,
are not considered. The primary purpose of this document is the identifica-
tion of important environmental research areas in oil shale technology, and
for setting research priorities.
Chapter 1 is an introduction and summary of the Preliminary Environmental
Assessment (PEA). Chapter 2 presents a brief review of oil shale extraction
and retorting technologies. The discussion includes the history, technology,
development plans, and environmental programs of the major contenders for
commercial development. Chapter 3 reviews the sources and nature of pollution
from shale oil operations including the pollutant inventories presented by the
various developers for air, liquid and solid waste emissions. Chapter 4 des-
cribes the baseline environmental conditions and discusses potential environ-
mental impacts of the various technologies and developments. Chapter 5 is a
brief review of shale oil upgrading and refining experiences to date, and of
waste streams and hazards associated with refining and handling of shale oil.
Chapter 6 is a summary of monitoring projects and studies which have been or
are being conducted in the Piceance and Uinta Basins, and which are relevant
to oil shale development.
This report was submitted in partial fulfillment of Contract 68-02-1881
by TRW Environmental Engineering Division under the sponsorship of the U.S.
Environmental Protection Agency. This report covers the period of June 1,
1975 through June 1, 1976, and work is continuing toward the final project
report "Assessment of the Environmental Impacts from Oil Shale Development"
to be published in mid-1977.
iv
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CONTENTS
FOREWORD iii
ABSTRACT iv
FIGURES ix
TABLES x
SUMMARY OF METRIC/ENGLISH UNIT EQUIVALENTS xii
1.0 INTRODUCTION AND SUMMARY 1
2.0 THE STATUS OF OIL SHALE TECHNOLOGIES AND DEVELOPMENT ACTIVITIES. . 7
2.1 The Extraction and Preparation of Oil Shale for Retorting. . 7
2.1.1 History 7
2.1.2 Underground Room and Pillar Mining 10
2.1.3 Open Pft Mining 14
2.1.4 Mining for In-Situ Retorting 19
2.1.5 Advanced Mining Methods 19
2.1.6 Storage, Transport and Crushing of Oil Shale 22
2.2 Surface Retorting Technologies and Development Plans .... 24
2.2.1 TOSCO I! Retorttng Process 24
2.2.2 The Paraho Processes 27
2.2.3 The Union Oil Process 33
2.2.4 Superior Oil Process 36
2.2.5 Lurgf-Ruhrgas Process 40
2.3 Commercial Development Plans Employing In^Situ Technology . 41
2.3.1 The Occidental Modified In-Situ Process 41
2.3.2 Western Oil Shale Corporation (WESTCO) 46
2.3.3 Geokinetics, Inc 46
2.3.4 ERDA In-Situ Research, Development and Demonstration
Project 46
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2.4 Federal Oil Shale Lease Tracts 46
2.4.1 Tract C-a - Rio Blanco Oil Shale Project (RBOSP) ... 48
2.4.2 Tract C-b - Roxana 52.
2.4.3 Tracts U-a/U-b - White River Shale Project (WRSP). . . 53
2.4.4 Federal In-Situ Lease Tract Nominations 55
3.0 THE NATURE AND SOURCES OF EMISSIONS, EFFLUENTS AND SOLID WASTES
FROM SHALE OIL OPERATIONS 60
3.1 Atmospheric Emissions 60
3.1.1 A Comparison of Retorting Processes for Potential
Emissions 62
3.1.2 Process Emissions Inventories 67
3.1.3 Fugitive Emissions Inventories 73
3.2 Water Requirements and Wastewater Processing 76
3.2.1 Water Requirement Estimates for Oil Shale Development 76
3.2.2 Sources and Nature of Wastewater 78
3.2.3 Specific Process Wastewaters 80
3.2.4 Process Wastewater Treatment 83
3.3 Solid Wastes Associated with Oil Shale Extraction and
Processing 86
3.3.1 Raw Shale Fines 86
3.3.2 Retorted Shales 87
3.3.3 Other Shale Derived Solid Wastes 91
3.3.4 Non-Shale Solid Wastes 91
3.3.5 Inventory of Solid Wastes 93
4.0 POTENTIAL IMPACTS OF EXTRACTION AND PROCESSING ACTIVITIES ON THE
PHYSICAL ENVIRONMENT 99
4.1 Air Quality Impacts of Oil Shale Extraction and Processing . 99
4.1.1 Baseline Characterization of Meteorology and Air
Quality 99
4.1.2 Review of Model Application to Oil Shale Related
Emissions in Colorado and Utah 103
4.1.3 Assessment of Models and Model Concepts Applied to Oil
Shale Emissions 108
4.1.4 Comparison of Modeling Results 109
VI
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4.2 Impacts on Water Quality and Hydrology 113
4.2.1 Existing Surface Water Quality and Flow 113
4.2.1.1 Upper Colorado River Basin 113
4.2.1.2 Piceance Creek Basin 113
4.2.1.3 Uinta Basin 116
4.2.2 Existing Ground Water Quality and Yields 117
4.2.2.1 Piceance Creek Basin 117
4.2.2.2 Uinta Basin 122
4.2.3 Effects of Water Withdrawal by Oil Shale Development
on the White and Colorado Rivers 122
4.2.4 Effects of Development on Local Surface and
Groundwater 124
4.3 Potential Impacts Associated with Solid Waste Disposal ... 131
4.3.1 Solid Waste Disposal Plans for Oil Shale Development . 131
4.3.2 Potential Hazards and Pollution Problems 140
4.3.3 Experience in Establishing Vegetative Cover on Retort
Shale Piles 141
5.0 THE REFINING AND END USE OF SHALE OIL PRODUCTS 148
5.1 Upgrading and Refining of Shale Oil 148
5.1.1 Upgrading Plans for Oil Shale Developments 148
5.1.2 Experiences in Oil Shale Refining 148
5.2 Waste Streams and Hazards Associated with Refining and
Handling of Shale Oil 153
5.2.1 Waste Streams 153
5.2.2 Carcinogenic Properties of Crude Shale Oils and
Refined Products 153
5.3 Emissions from the Combustion of Shale Oil Products .... 157
6.0 ENVIRONMENTAL MONITORING PROGRAMS AND STUDIES 160
6.1 Monitoring and Environmental Studies by Private Industry,
Universities, and certain Government Agencies 160
6.2 Environmental Programs of the Federal Prototype Oil Shale
Leasing Program 160
6.2.1 Geotechnical Data Gathering 167
6.2.2 Environmental Baseline Programs 168
6.2.3 Continuous Monitoring Programs 170
vii
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6.3 Comments on Monitoring Programs 170
6.3.1 Air Quality and Meteorological Monitoring 171
6.3.2 Surface and Ground Water Monitoring 171
6.3.3 Solid Wastes 171
6.3.4 Revegetation 172
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FIGURES
2-1 Locations of Potential Oil Shale Developments - Piceance
Basin, Colorado 8
2-2 Locations of Potential Oil Shale Developments - Uinta Basin, Utah 9
2-3 Perspective Drawing of Oil Shale Room and Pillar Mining .... 11
2-4 Vee-Cut Blasting Pattern for Underground Oil Shale Mining ... 13
2-5 Typical Bench Blasting Pattern Viewed from Above - Tract C-a . 15
2-6 Cross Section of Typical Bench Blasting Pattern Viewed from the
Side 16
2-7 Typical Bench Development Viewed from Above - Tract C-a .... 17
2-8 30-Year Pit Cross Section - Tract C-a 18
2-9 Schematic of Occidental Modified In-Situ Mining Method .... 20
2-10 Oil Shale Feed Preparation Schematic 21
2-11 Schematic of the TOSCO II Retorting Process 25
2-12 Schematic of Paraho Direct Mode 29
2-13 Schematic of Paraho Indirect Mode 30
2-14 Side View of Union B Retort 31
2-15 Flow Diagram for Union B Retorting Process 34
2-16 Top View of Superior Retort 37
2-17 Cross Section View of the Superior Retort 38
2-18 Schematic of the Occidental Modified In-Situ Process 43
2-19 Flame Front Movement in the Occidental Modified In-Situ Process 44
4-1 Location of Selected Stream Gaging Stations and Oil Shale
Developments 115
4-2 Aerial View of Colony Development Operation Disposal Site -
Davis Gulch 132
4-3 Tract C-a Conceptual Phase I Solid Waste Disposal Plan .... 134
4-4 Tract C-a Conceptual Phase II Solid Waste Disposal Plan .... 135
4-5 Schematic of Union Oil Company Retorted Shale Disposal Plan for
Operations at Parachute Creek Site 136
4-6 Backfilling of Mined Out Shale Zone with Processed Shale -
Superior Oil Company 139
ix
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TABLES
2-1 Results of Federal Oil Shale Lease Offerings 47
2-2 Tract C-a - Rio Blanco Oil Shale Project Summary 49
2-3 Tract C-b - Roxana Oil Shale Project Summary 51
2-4 Tracts U-a/U-b - White River Shale Project Summary 54
3-1 The Sources and Nature of Atmospheric Emissions from Oil Shale
Extraction and Processing 61
3-2 Comparison of Total Sulfur in Raw Retort Gases 63
3-3 Comparison of TOSCO II Emissions Inventories (8000 m3/day)
(50,000 bbls/day) 69
3-4 Lease Tract C-a Phase II Emissions Inventory (56,000 bbls/day) . 70
3-5 Lease Tracts U-a/U-b Emissions Inventory (50,000 bbls/day) ... 71
3-6 Union B Fuel Gas Combustion Emissions 72
3-7 Summary of Air Pollution Control Technology for Oil Shale
Preparation and Retorting, and Shale Oil Upgrading 74
3-8 Potential Fugitive Dust Emissions 75
3-9 Estimates of Process Water Requirements for Full Scale Oil Shale
Production (m3 of water needed per m3 of oil produced) 77
3-10 Water Consumption Requirements for Unit Processes Associated
with Oil Shale Processing 77
3-11 Approximate Composition of TOSCO II Combined Process Wastewater
(8000 nr/day upgraded shale oil production) 81
3-12 Paraho (GCR) Process Wastewater Analysis 82
3-13 Approximate Composition and Flow Rates for Selected Wastewater
Streams Lease Tracts U-a/U-b (Phase III, 8000 m3 upgraded shale
oil/day) 84
3-14 Ash Composition of Typical Retorted Oil Shales 88
3-15 Properties of Retorted Shales
yy
3-16 Inorganic Ions Leachable from Freshly Retorted Shales (kgs/tonne)
Based on Laboratory Tests go
3-17 Levels of Benzo(a)pyrene (BaP) Reported in Selected Natural and
Industrial Materials
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3-18 Typical Composition of Shale Oil Coke ............. 93
3-19 Major Solid Wastes from TOSCO II Processing .......... 95
3-20 Solid Wastes Generated During Construction and Operation of Shale
Oil Facilities at Tracts U-a/U-b - Phase IV .......... 96
4-1 Existing Air Quality Data Summary for Federal Oil Shale Lease
Tracts ............................. 102
4-2 A Comparison of Air Pollutant Emissions (kg per hour) Used in
Modeling Studies ........................ 110
4-3 Comparison of Modeling Results with Applicable Standards .... 112
4-4 Water and Dissolved Solids Discharge at Selected Stations in
Upper Colorado River Basin ................... 114
4-5 Summary of Piceance and Yellow Creek Streamflow Records .... 116
4-6 Summary of Roan and Parachute Creek Streamflow Records ..... 117
4-7 Maximum Values for Dissolved Constituents of Surface Waters on
and Around Federal Oil Shale Lease Tracts ........... 118
4-8 Mean Values for Dissolved Constituents in Ground Water on Federal
Oil Shale Lease Tracts C-a and C-b ............... 121
5-1 Summary of Crude Shale Oil Properties ............. 150
5-2 Summary of "On Site" Upgrading of Shale Oil Planned at Develop-
ment Sites ........................... 152
5-3 Comparable Carcinogenic Potency of Complex Mixtures .......
6-1 Summary of Meteorology and Air Quality Monitoring and Studies. .
6-2 Summary of Surface and Ground Water Monitoring Activities ... 152
6-3 Summary of Spent Shale/Solid Waste Disposal Projects ...... 164
6-4 Summary of Revegetation Projects ................ 165
XI
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SUMMARY OF METRIC/ENGLISH UNIT EQUIVALENTS
Energy
1 Btu = 2.929 x 1(H kilowatt hour (kWh)
1 kcal = .397 Btu
Length
1 inch = 2.54 centimeter (cm)
1 foot - 0.3048 meter (m)
1 yard - 0.9144 meter (m)
1 mile - 1.609 kilometer (km)
1 pound = 0.4536 kilogram (kg)
1 ton (short) = 9.072 x Ifl2 kilogram (kg)
1 tonne = 1 metric ton (tonne)
Area
1 acre = 0.407 hectare (ha)
1 acre = 4.047 x 1Q3 square meter Cm2)
1 square foot = 9.290 x 10"2 square meter (m2)
1 square mile =2.59 square kilometer (km)2
Volume
1 cubic foot = 2.832 x 10~2 cubic meter (m3)
1 gallon = 3.785 x 10~3 cubic meter (m3)
1 barrel = 0.1590 cubic meter (m3) = 42 U.S. gallons
1 acre-foot = 1234 cubic meters
1 cubic yard = .764 cubic meter (m3)
Conversions especially important in this report:
Shale oil1 m3 = 6.3 barrels =0.93 tonnes crude shale oil
Volumetric flow rates1 m3/sec = 2120 ft3/min
Emission factors1 lb/106 Btu = .1145 kg/kcal
Heating value890 kcal/m3 = 100 Btu/SCF
0 Oil shale yield0.125 m3/tonne = 30 gal/ton
Water resources1234 m3 = 1 acre-foot
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1.0 INTRODUCTION AND SUMMARY
Commercial interest in the extraction and processing of oil shale has
been shown for several decades. A viable oil shale industry has been "about
to start" several times in this century, but each time economic, technical,
political, or legal roadblocks have postponed actual development. More re-
cently, the impetus to develop domestic energy sources has prompted many new
government and privately sponsored oil shale activities. This apparent in-
creased interest in oil shale has also led to increased concern about envi-
ronmental impacts which might be associated with large scale extraction and
processing operations.
The oil shale area of northwestern Colorado and northeastern Wyoming has
no large human population or industrial base at present, and thus air and
water quality are not unduly influenced by human activities. Large-scale con-
struction and operation of oil shale facilities, however, will result in direct
atmospheric emissions, and wastewater and solid waste generation. Further,
an influx of shale industry employees and support services population will
create numerous indirect impacts on air, water, and land resources.
The Environmental Protection Agency is empowered to encourage and promote
the development of pollution control technology for industrial waste streams.
Such technology includes not only "add on" devices for minimizing emissions
and effluents, but also "in house" and management techniques for controlling
pollution or averting undesirable environmental effects of industrial activi-
ties. To aid in defining the nedd and priorities for control of waste streams
associated with oil shale development, EPA has requested the preparation of
this preliminary environmental assessment. Included are a summary of current
oil shale technologies and development activities, a review of the properties,
sources and quantities of wastes which may be generated by these technologies
and activities, a discussion of potential environmental impacts and hazards
resulting from oil shale development, and discussions of pollution control
technology and/or management practices which have been developed or are planned
for commercial operations. Some of the current baseline environmental moni-
toring and control technology development projects are discussed and briefly
evaluated. Indirect impacts resulting from population influx into the oil
shale region are not discussed in this report, although the relative importance
of such impacts should not be minimized. The preliminary environmental assess-
ment will be updated in the final assessment report which will be submitted by
TRW/DRI to EPA in June of 1977.
Several oil shale mining and retorting technologies are approaching the
commercial state of development. Oil shale has been mined on a modest scale
for over three decades. To date, however, mining has been underground and con-
fined to the southern end of the Piceance Basin, with adit access at the
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Mahogany zone outcrop. Current development plans for larger scale oil shale
extraction call for both room and pillar mining and for open pit mining. In-
dividual developers envision the mining of from 10,000 to over 100,000 tonnes
of oil shale per day.
The private sector has developed both above-ground and in-situ retorting
technologies, and several companies plan to apply these technologies on pri-
vately owned oil shale lands in Colorado and Utah. Similar technologies are
likely to be utilized on federally leased oil shale lands. Crude or upgraded
shale oil production rates of 1200 to over 8000 mj (8000 to over 50,000 bbls)
per day are envisioned. Above«ground retorting processes which have reached
the stage of industrial interest in the United States may be divided into three
classes based upon the way heat is supplied to the retorting process. These
categories include retorts using (a) recycled hot solids (e.g., TOSCO II and
Lurgi-Ruhrgas, (b) an internal combustion zone within the retort (e.g., Paraho
Direct Mode, Superior Circular Grate), or (c) an external, fuel-fired furnace
or gasifier (Union Retort B, Paraho Indirect Mode). The major U.S. retorting
processes which employ these various modes of heat transfer are individually
discussed in Chapter 2 of this report. Although private developers such as
the Colony Development Operation, Union Oil Company, and the Paraho Group con-
sider their respective retorting technologies to be demonstrated at the pilot
and/or prototype stage,full scale commercial operations are not currently
planned or such plans have been postponed. Among the reasons cited for the
cautious approach to commercial development are the lack of a definite fed-
eral energy policy, uncertainties regarding both production costs and product
prices, questions about the ability to meet ambient air quality standards,
and the threat of environmental litigation.
Although in-situ extraction of shale oil has attracted research interest
for over 20 years, only recently has commercial interest emerged. The Occi-
dental Petroleum Corporation has developed a modified in-situ process and
claims that commercial production is technically and economically possible.
Several other private interests, as well as the Laramie Energy Research Center
CERDA), are supporting or have proposed in-situ extraction projects.
Chapter 2 includes a summary of the development plans for the federal
lease tracts in Colorado and Utah. The developers of Tracts C-a, C-b, and U-a/
U-b have recently submitted Detailed Development Plans for their respective
tracts to the Area Oil Shale Supervisor (AOSS), as required by the lease stip-
ulations. Each lessee has also, however, requested suspension of certain lease
conditions, including tract development requirements for the immediate future.
The Department of the Interior has recently granted all of these suspension
requests for a period of one year.
In 1975 the Department of the Interior accepted nominations of tracts to
be leased for in-situ development. Four of the tracts nominated by industry
were recommended by a special committee of the Oil Shale Environmental Advisory
Panel. The Secretary of the Interior has not acted to date on the recommenda-
tions. An environmental impact statement is currently in preparation.
Chapter 3 of the report is a summary of the types, sources, properties,
and quantities of wastes which may be generated during the extraction and
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processing of oil shale. Of the atmospheric emissions from oil shale process-
ing activities, the major source of S02» NOX, and CO is fuel combustion for
process heat. S02 is also emitted in the tail gases of sulfur recovery opera-
tions. The use of fuel oils in mobile equipment and in explosives results in
emissions of CO and NOx. Hydrocarbons are present in both combustion emis-
sions and in product storage tank vapors. Emissions of particulate matter
can result from blasting, raw and retorted shale handling and disposal, shale
dust in flue gases, fuel combustion, and site activities which generate fugi-
tive dust.
Emissions of hazardous substances may occur during the extraction and
processing of oil shale. Silica (quartz) may be present in dust derived from
oil shale and associated rocks and in fugitive dust. Particulate emissions
from fuel combustion and fugitive dust from retorted shale handling and dis-
posal could contain small quantities of hazardous organic material and certain
trace metals. Retorted shale may release ammonia, hydrogen sulfide, and vola-
tile organics during moisturizing and subsequent cooling. Catalyst materials
may release metals to the atmosphere during regeneration, handling, or final
disposal.
The quantities of atmospheric emissions associated with shale processing
depend on the size of the operation, the type of mining and retorting tech-
nology employed, the extent of on-site upgrading, and the degree of emissions
control practiced. Emissions inventories for the Colony Development Operation
and for Tracts C-a, C-b, U-a/U-b are reported in Section 3.1. Less complete
emissions data are presented for the proposed Union Oil Company and Occidental
Oil Company operations, and for fugitive dusts which may result from site use
activities.
Water is a necessary resource for the development of an oil shale indus-
try. Water would be used for cooling, dust control, gas cleaning and pro-
cess emissions control, and for moisturizing retorted shale. As much as 3.7
m3 of water is required for the production of 1 m3 of upgraded shale oil.
Unlike their counterparts in the petroleum, by-product coke, and related
industries, oil shale developers do not plan to discharge wastewater directly
to local surface water. Rather, process waters would be reused for purposes
requiring progressively lower quality water within the plant, and finally
for moisturizing retorted shale.
The sources and properties of process wastewaters are discussed in Sec-
tion 3.2. Generally, the characteristics of these wastewaters are similar to
those encountered in petroleum refining - high dissolved and suspended solids,
and high chemical and biochemical oxygen demand. Oil and grease, reduced
nitrogen and sulfur containing compounds, and organic compounds such as
phenolics and carboxylic acids are likely to be present in such waters. Con-
stituents in wastewater applied to retorted shale may be an indirect source
of water pollution if mobilization occurs via erosion, runoff, or leaching
of a retorted shale disposal pile.
The major solid wastes from oil shale processing are raw shale fines from
crushing and dust control, and the processed shale remaining after retorting.
In an integrated facility, these constitute more than 95 percent of the solids
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requiring disposal. The quantity and nature of other solids to be discarded
depend primarily upon the extent of upgrading of the crude shale oil which
is carried out in conjunction with the retorting operations, and the solid
wastes from auxiliary operations. The latter might include shale coke from
delayed coking; spent catalysts from hydrotreating, sulfur recovery, and
arsenic removal; lime and alum sludges from water treatment; spent activated
carbon and diatomaceous earth from oil or gas treatment. The quantities of
these wastes which may be generated by various developments are tabulated in
Section 3.3.
With many retorting technologies (e.g., TOSCO II and Union B) an organic
residue remains on the oil shale after retorting. Other technologies (e.g.,
Paraho Direct Mode) have been designed to burn most organic material as part
of the retorting step. Retorted shale exhibits cement-like properties if most
of the carbonaceous material has been burned off during retorting, and such
properties may be used to advantage in creating an impermeable disposal pile.
On the other hand, carbonaceous retorted shales do not generally exhibit such
cementing properties. Inorganic constituents of both burned and carbonaceous
retorted shales are partially water soluble, and may be mobilized by water
run-off or by percolation through a disposal pile. Carbonaceous retorted
shales contain organic substances which may also present a hazard during hand-
ling and disposal, or may be present in fugitive dust or leachate waters from
disposal piles.
Chapter 4 is a summary of the major potential impacts which can result
from oil shale development. The scope of the chapter is limited to direct
and indirect impacts on air and water quality resulting from extraction and
processing activities. Effects of increased human population (e.g., vehicle
traffic) and effects of development on biota are not considered.
Several air quality modeling efforts have been undertaken to predict the
impact of process emissions on ambient air quality. Section 4.1 reviews
these efforts, including those performed by the developers of the federal lease
tracts, for the adequacy of the data inputs and the models employed. Currently,
most air quality levels in the oil shale region are well below the federal and
state ambient standards, with the exception of occasional short term particu-
late and oxidant levels. Maximum ambient levels of sulfur dioxide and carbon
monoxide associated with individual oil shale operations are predicted to meet
state and federal standards. However, suspended particulate and non-methane
hydrocarbon levels are predicted to exceed short term standards for signifi-
cant deterioration and maximum allowable increment increases. Further, emis-
sions assumed in most of the modeling efforts have generally not accounted
for fugitive dust, secondary sources such as vehicular traffic, or transient
releases.
Potential effects of extraction and processing activities on the quality
and flows of the surface and groundwater are discussed in Section 4.2. Exist-
ing water quality in the oil shale region varies geographically and seasonally.
Several streams and shallow aquifers provide water suitable for irrigation
purposes although water quality in lower oil shale aquifers in the Piceance
Basin and in the lower reaches of Piceance Creek exceeds the dissolved solids,
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fluoride, or boron criteria for domestic or irrigation uses. The only signi-
ficant quantity of water found on or near the Utah lease tracts (U-a/U-b) is
that in the White River. Water quality in the White River is suitable for
irrigation use except during low flow in the summer.
Withdrawal of good quality surface and groundwater from sources in the
upper Colorado Basin for consumptive use may result in increased salinity
levels in the lower Colorado River. Conversely, consumptive withdrawal of
poor quality groundwater which might otherwise reach the upper Colorado River
or its tributaries may result in decreased salinity levels in the lower
Colorado River. The exact impact of withdrawal on the Colorado River is not
known, but the estimated maximum increase in total dissolved solids at Imperial
Dam resulting from a 160,000 m3 (1,000,000 bbl) per day oil shale industry is
only about 15 mg/1, or 1.7% of the current value of TDS at that point.
All of the major developers have indicated their intention to discharge
no wastewaters directly to surface streams. All process waters would be re-
used and ultimately applied to retorted shale. Effects of extraction and pro-
cessing activities on local hydrology and water quality are therefore likely
to be of an indirect or incidental nature. Generally, the water pollution
implications of mine dewatering and of the creation of large retorted shale
disposal piles are not currently known, and perhaps cannot be known until
development occurs. The site specific water pollution problems and proposed
water management programs of the Superior Oil Company, Occidental Oil Company,
and lessees of the federal tracts are summarized in Section 4.2.
Section 4.3 is a summary of solid waste disposal plans for major oil
shale developments, and a review of physical hazards and intermedia pollutant
transfer potential of retorted shale disposal piles. Most of the developers
propose to use canyon sites for solid waste disposal, and plan to establish
stable slopes and water diversion features on the waste piles. The surface
of the piles are to be revegetated and retention structures to be built to
prevent contaminated waters from reaching surface or groundwater.
In general, retorted shale cannot be entirely returned to mined-out
areas as a disposal method since retorted shale occupies a greater volume
than the raw shale from which it was derived. The Superior Oil Company, how-
ever, proposes to return all of the processed shale from its oil and mineral
extraction operations to the mined out zone. In this case, the recovery of
sodium and aluminum minerals in addition to shale oil results in a processed
shale whose volume is less than that of the parent shale.
The major potential problems for surface disposal of retorted shale are
(1) physical instability allowing mass movements; (2) runoff and leaching of
retorted shale creating indirect water pollution; and (3) surface destabili-
zation allowing excessive wind and water erosion to occur. These problems
or hazards and some experiences with small scale disposal pile stabilization
efforts (physical and vegetative) are reviewed in Sections 4.3.2 and 4.3.3.
Shale derived oils have properties different from petroleum derived oils,
and different processing steps may be required to produce suitable petroleum
-------
substitutes. The composition and properties of shale oils which may influence
upgrading steps, refining waste streams, and combustion emissions are discussed
in Chapter 5. A brief summary of two experiences in refining crude shale oil
is also included. Section 5.2.2 is a review of epidemiological studies, ana-
lytical measurements, and bioassay tests which have been aimed at determining
the carcinogenicity hazard associated with human exposure to crude and refined
shale oils.
Chapter 6 is a summary of environmental monitoring projects and studies
which have been or are being conducted in the Piceance and Uinta Basins rele-
vant to oil shale development. Such programs may be divided into two general
categories: (1) private and/or specialized projects and (2) projects con-
nected with the Federal Prototype Oil Shale Leasing Program. The chapter in-
cludes a catalog of various monitoring activities, a narrative summary of the
monitoring programs of the lease tracts, and comments about monitoring pro-
grams, with focus on scope, quality, and the availability of data and results
to interested parties.
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2.0 THE STATUS OF OIL SHALE TECHNOLOGIES AND DEVELOPMENT ACTIVITIES
Several oil shale mining and retorting technologies are approaching the
state of economic feasibility. The private sector has developed mining,
above-ground retorting and in-situ retorting technologies, and several com-
panies plan to apply these technologies on privately owned lands in Colorado
and Utah. Similar technologies are likely to be applied on federally leased
oil shale lands. This chapter is a brief review of oil shale extraction and
retorting technologies. The discussion includes the history, technology,
development plans, and some environmental programs of the major contenders
for commercial development at present.
The locations of potential oil shale development sites in the Piceance
and Um'ta Basins of Colorado and Utah are shown in Figures 2-1 and 2-2.
2.1 THE EXTRACTION AND PREPARATION OF OIL SHALE FOR RETORTING
Oil shale has been mined on a modest scale for several decades. To
date, however, mining has been underground and confined to the southern end
of the Piceance Basin with adit access at the Mahogany zone* outcrop. Con-
siderable experience in room and pillar mining has been accumulated.
Current development plans for larger scale oil shale extraction call
both for room and pillar mining and for open pit mining. This section re-
views the history of oil shale mining, the status of mining technology at
present, planned research and development programs, and technology for pre-
paration of shale for retorting.
2.1.1 History (1,2)
Oil shale property was purchased as early as the 1920's for possible
development. However, actual oil shale development efforts were not con-
ducted until the Bureau of Mines Shale Research Facility at Anvil Points
Colorado was established under the Synthetic Liquid Fuels Act of April 5,
1944. The plant and underground mine were operated by the Bureau of Mines
during the period from 1944 through 1956. Authority to lease the facility
was given to the Secretary of the Interior in 1956, and from 1964 through
1968 the facility was leased to the Colorado School of Mines Research Founda-
tion for purposes of improving retorting technology.
*The Mahogany zone is a rich interval of oil shale strata which extends
throughout the Piceance and Unita geologic basins in Colorado and Utah.
-------
OUTCROP OF
fAAHOGANY LEDGE
U.S. NAVAL
RESERVE
NO. 1 AND 3
95W 94W 93W
Figure 2-1. Locations of Potential Oil Shale Developments -
Piceance Basin, Colorado
-------
20E
21
OUTCROP
OF
MAHOG:
ONY
LEDGE
21 22
RANGE
24
25E
Figure 2-2. Locations of Potential Oil Shale Developments
Uinta Basin, Utah
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Mobil Oil Company acted from 1964 through 1968 as project manager for
a six company cooperative effort for improving oil shale technology. At
first this group operated the Anvil Points mine and in 1966 opened a new
mine in a 24 meter (78 ft) high ledge of the Mahogany zone which produced
453,600 tonnes (500,000 tons). Union Oil Company operated a mine from 1955
through 1958 on their property located on the east fork of Parachute Creek.
This effort resulted in the mining of over 56,500 tonnes (70,000 tons) of
shale for Union's retort development activities.
The Colony Development operation started with a prototype mining
effort in 1964 with the intent of eventually proceeding to a 59,892 tonne
(66,000 ton) per day production mine. Operations were suspended in 1973.
The objective of all these efforts, in addition to tfie production of shale
for testing various retorting processes, was to develop applicable methods
for mining the richer oil shale of the Mahogany zone. The total years of
effort devoted to the development of mining methods in shale have made avail-
able reliable systems of ore extraction, a necessary condition for the start
of a commercial shale oil industry.
The production systems expected to be used through 1985 are underground
room and pillar; open pit (a standard method); and the Occidental modified
in-situ method. These mining methods are described below.
2.1.2 Underground Room and Pillar Mining (1.2,3,4,17)
Room and pillar mining is most commonly associated with relatively thin
tabular beds of coal and potash. The type of room and pillar mining associ-
ated with oil shale is more closely akin to that practiced in the lead-zinc
mines of Missouri and Kansas. Once the mine opening has been developed,
the basic sequence is as follows (see Fig. 2-3): a) drill, load and blast
the upper (approximately 1/2 the thickness mined) heading and ventilate the
area; b) bar down dangerous overhead rock; c) muck the blasted oil shale;
d) scale the remainder of the loosened shale from the overhead and sides of
the ribs and pillars; e) install roof bolts to assure structural integrity
for safety in future operations. Mobile units are diesel powered, and carry
air compressors for the rotary drills, water for drilling and dust suppres-
sion, and lighting systems for operational illumination.
At some distance behind the initial heading development, a similar
sequence is followed in the bench area; a) drill, load, blast and ventilate;
b) muck; c) scale the pillars and clean up the area for haulage.
Drilling: Rotary drilling jumbos have been developed which are totally
self-contained. These units are capable of drilling the necessary 40 to 50,
6.6-12.7 cm (3-5 in) diameter holes rapidly enough to allow loading and
blasting a heading in one shift.
Blasting: Ammonium Nitrate/Fuel Oil (ANFO) mixtures of 95/5 composition
have proven to be an effective blasting agent for dry holes in oil shale when
properly primed. Headings require 0.35 Kg of blasting agent per tonne of rock
10
-------
Figure 2-3. Perspective Drawing of Oil Shale Room and Pillar Mining
-------
(0.7 Ib/ton). Benches require less explosive - about .175 Kg/tonne (0.35
Ibs/ton) because of their easier blasting characteristics.
Blasting in a wide heading is most economically accomplished using a Vee
cut (the name is apparent from the view of Fig. 2-4). Since there is only one
"free face" to blast to, and the remainder of the area is surrounded by rock
which resists movement, a Vee cut requires heavier loading and thus a higher
blasting agent factor. In order to open up the blasted area, the shooting is
done sequentially from the "cut" holes outward to the "trimmer holes. Holes
may also be sequentially fired from the middle of the face upward and down-
ward, with the bottom row of "lifters" typically being the ast fired. This
allows the muck to be thrown away from the face for easier loading.
Bench blasting is similar to that associated with open pit mining and
will be described in Section 2.1.3.
Ventilating: Ventilation regulations require a minimum of 2.8 m3/min
of air flow (100 cfm) per diesel horsepower. After blasting there is a re-
quirement to reduce the NO/ level in mine air below a Threshold Limit Value
(TLV) of 25 ppmv within an hour so that the next shift can work in a safe
atmosphere. All fumes and dust generated will generally be rejected to the
outside atmosphere in a short period of time.
Barring Down: Before mucking and haulage, safety procedures normally
require men working on top of the muck pile to bar down loose rock from the
back to prevent rock falls during mucking.
Mucking and Haulage: The practice of room and pillar mining in Colorado
oil shale and in the midwestern lead-zinc district has led to the development
of diesel front end loaders of 19 m3 (25 cubic yards) capacity and diesel
trucks to 67 tonnes (75 tons) capacity. All diesel engines are equipped with
scrubbers to meet mine toxic gas emission requirements. Haulage from the
mine is accomplished by trucks or conveyors through adit entry mines. For
inclined shafts, conveyors or skips will be used depending on the angle of
incline. Skips will be required for operation from vertical shafts.
Roof Bolting and Scaling: AS soon as the heading has been mucked out,
detailed scaling of the back* and installation of rock bolts is accomplished,
A pattern of installing rockbbolts on 1.8 m (6 ft) centers has been estab-
lished for present mines along with a general pattern of 18 m (60 ft) rooms
and 18 m (60 ft) pillars. The length of rock bolts will depend upon the
thickness and competence of overlying strata.
Shale mine pillars have been instrumented and various surveys have been
made of their structural competence. Knowledge of the geological joint
system of the oil shale bed has a large influence on the ability to calculate
pillar size versus thickness of overburden. Thus, orientation of the mine
to take advantage of the geological joint system is important. But, since
the oil shale mines developed to date have been of small areal extent, the
effect of large scale underground excavation on pillars is unknown.
*The roof of a hard rock mine is normally referred to as the back.
12
-------
HOLES"
"TRIMMER HOLES"
Ftgure 2-4. Vee-Cut Blasting Pattern for Underground Oil Shale Mining
-------
2.1.3 Open Pit Mining (2,5,7)
Open pit mining is not as complex as underground mining, but the basic
steps are similar: a) drill, load, and blast either the overburden or the
oil shale; b) load the material for transport to the retorting or disposal
area; c) scale the face for safety and repeat the cycle.
Drilltng: Drilling in open pit mines is normally accomplished with
large mobile drills, capable of drilling large diameter holes. Bench height
and drill characteristics are usually chosen to obtain a drill with a mast
height sufficient to drill a hole in one pass. If achievement of the neces-
sary bench deoth requires the addition of lengths of drill stem, the opera-
tion would be slowed down. Figure 2-5 shows a view of a drilling pattern
planned for a large bench on Tract C-a (7).
Blasting: Because larger loading equipment can be used on surface than
is possible underground, the blasting pattern in a pit mine can be spread
out and large powder holes used, even though this may produce larger blocks
of ore. An average of 0.35 Ibs of ANFO blasting agent per ton (.175 kg/tonne)
of material will likely be required, although the quantity can be adjusted
as experience with the variations in the oil shale develops. Figure 2-6
shows the cross section of a typical blasting pattern as envisioned for Tract
c~a (7). The holes are drilled and loaded below the bench level to preserve
a level floor for subsequent operations. Stemming in the top of the hole
effectively contains the explosion to maximize useful effects.
In open pit mining, detonating cord is normally used between holes and
down the holes to the primers. Millisecond delay connectors are used between
sections of cord to sequentially initiate blasts from front to back and side
to side. This improves fragmentation as well as minimizing shock to the
surrounding area. Since the detonating cord is relatively insensitive to
initial detonation, safety is improved. Electrically initiated caps used to
start the sequence do not have to be connected until last. If there are
thunderstorms and lightning in the area blasting can thus be delayed.
Loading and Hauling: Broken ore is loaded with large shovels (usually
electrically powered) into trucks having capacities of up to 77 tonnes (85
ton). Diesel powered front end loaders and bulldozers are used for cleanup
in and around the loading areas. Road graders and watering trucks are re-
quired to maintain haul roads since tire wear is one of the most expensive
operating costs associated with open pit mining.
Frequently primary crushing of the ore is accomplished in the open pit,
followed fay haulage from the pit with either large diesel trucks. Alterna-
tively ore may be transported by conveyor belt to the secondary crushing
storage pile. Figure 2-7 shows a schematic plan of a loading operation (7).
Slope Stability: Both the safety of the pit and economics of open pit
mining are highly dependent upon the steepness of the side slopes which can
be maintained in the pit (see Figure 2-8 where the slope angle is«45°).
If the slope stability cannot be maintained at a fairly steep angle, slides
14
-------
en
ru v.wiw.'v
»-
TO
INITIATION
CAP
328'
PD = Primary Detonating
Figure 2-5. Typical Bench Blasting Pattern Viewed from Above - Tract C-a (7)
-------
PD*CORD
Ot
SOFT
TRUE
BURDEN
EXPECTED
BENCH LEVEL
15 FT
STEMMING
42 FT POWER
COL. ANFO
/ EXPECTED
/ BACK BREAK
HOLE DIA.
15 IN.
PRIMERS
SUBDRILUNG
^Primary Detonating
Figure 2-6. Cross Section of Typical Bench Blasting Pattern Viewed from the Side (7)
-------
SOFT
90 FT 230 FT
90 FT
I
SOFT
I
I
LEGEND
HAULAGE ROUTE TO PLANT SITE
HAULAGE ROUTE TO EXCAVATION SITE
Figure 2-7. Typical Bench Development Viewed from Above - Tract C-a (7)
-------
C'
CP
EAST
C GENERALIZED
WEST pHASE H
PIT UMIT
7500
7000
6500
6000
5500
GENERALIZED
PHASE H
PIT LIMIT
ORIGINAL SURF ACE
-5 THRU R-2 ZONES ORE
LOWER AQUIFER
5500
Figure 2-8. 30-Year Pit Cross
Section - Tract C-a (7)
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hazardous to personnel may result. If it is necessary to maintain the slope
at low angles to avoid slides, the amount of overburden which must be removed
compared to the amount of usable oil shale produced could make the operation
too expensive.
2.1.4 Mining for In-Situ Retorting (8)
A general discussion of in-situ retorting can be found in Section 2.3.
Of interest here is the Occidental modified in-situ operation near De Beque,
Colorado. As described in Section 2.3, mining is performed at two levels.
The layer between these levels is drilled and blasted to form a room or
"chimney" filled with rubblized shale for retorting (Figure 2-9). The chimneys
are planned to be about 95 meters high and 30 meters square.
Since large cross-section chimneys are desirable from a resource recov-
ery point of view it is probably necessary to leave pillars in both the upper
and lower levels for safety during mining. These pillars would be blasted
at the same time as the main column and form part of the rubblized column for
retorting. Though a chimney would be partially filled with retorted shale,
the long span across the tops of a chimney would make subsidence more likely
than in the case of normal room and pillar mining.
2.1.5 Advanced Mining Methods
The Bureau of Mines contracted with several companies for studies of
advanced mining methods (10).> The contracts were with Cameron Engineers for
underground mining methods, Fennix and Scisson for modified in-situ methods,
and Sun Oil Company for single pass open pit mining methods.
Cameron Engineers examined eight underground mining systems for mining
thick shale under heavy overburden (9). Of the eight systems examined, four
were considered acceptable. In order of preference they were chamber and
pillar, sublevel stopfng with spent shale backfill, sublevel stoping with
full subsidence, and block caving to si usher drifts.
Fennix and Scisson examined ten basic mining system possibilities and
selected four candidate rubblization techniques for modi tied in-situ retort-
ing based upon two mining systems, room and pillar and tunnel boring (11).
The rubblization techniques examined were raise boring, vertical drill and
blast, fan drill and blast, and horizontal ring drill and blast. System II
Room and Pillar, Vertical Drill and Blast, System IV Tunnel Boring, and
Horizontal Ring Drill and Blast were recommended to the Bureau of Mines for
further study in the second phase of the contract.
Sun Oil Company examined a single pass open pit mine (5). The most signi-
ficant aspect of their efforts was that their rock mechanics calculations in-
dicated that an average 37° slope could be maintained in the area considered.
19
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MINED SHALE
TO SURFACE
LONGHOLES
MINED SHALE
TO SURFACE
Figure 2-9. Schematic of Occidental Modified In-Situ Mining Method
20
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In addition to the above contracted studies, the Bureau of Mines is dev-
eloping mining technology for the rich, deep oil shales and associated saline
minerals of the central Piceance Basin, Colorado (9). One corehole has been
drilled in this area, and a second hole, 1.8 m in diameter, is planned to
gather additional shaft sinking data in FY 77. Later plans call for sinking
a full sized shaft (in FY 78) to develop full technical and economic data for
shaft sinking through the saline aquifer system and leached zone strata UU).
2.1.6 Storage, Transport and Crushing of Oil Shale (6.7,12)
Figure 2-10 schematically represents a typical oil shale preparation
circuit. The mined shale is fed from trucks or conveyors into a feed surge
control hopper(s). From the feed hopper(s) the ore is conveyed to grizzlies
above the primary crushers. A grizzly serves the purpose of screening out
ore which will choke the entry to the primary crusher and is made of heavy
bar. The oversize ore is broken on the grizzly (hydraulic picks are used
for this purpose) so that the retained rocks pass the bar screen.
The primary crusher reduces the ore to a size which will fit the entry
for the secondary crusher. Primary-crushers to be used for oil shale are
generally the largest size comrnetscially available and are banked for two
reasons: a) the higher reliability of standard units and b) having several
units increases the overall system reliability. It is not efficient for a
crusher to produce 100% of a product which will feed the next crushing stage
because too much undersize material will be produced which may slow the flow
through the following crusher). Therefore, the primary crusher product is
screened and the oversize portion (10-20%) is returned to the primary crusher
feed.
From the primary crusher the ore is moved to a stockpile by covered con-
veyor. The surface storage required for reliable feed to the retorts is a
minimum of a 30-day supply. A stacker-reclaimer is used for stockpiling the
ore in windrows and reclaiming it for feeding the secondary crushing circuit.
The secondary crushing circuit is a duplicate of the system described for
the primary crushing circuit, except that a grizzly is not required since the
ore is already sized to fit the input requirements of the crushers. The size
requirements and limitations may be found in the individual process descrip-
tions (see Section 2.2).
Fine ore from the secondary crusher is stored in silos from which the
ore is moved by weight belt conveyors to the retorts.
Particulate Emission Control: Emissions and effluents from the various
operations are discussed in Section 3. Particulate emissions from crushing
have predominant impact potential, and all developers plan to control dust
from the crushing operation by use of the best available technology. Crusher
buildings are to be negatively pressurized, conveyor belts are to be covered,
suction hoods are to be placed over appropriate points and all dust laden air
21
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HAULAGE
FEED HOPPER
GRIZZLY*
PRIMARY CRUSHER
SCREENING
t
RECIRCULATE
OVERSIZE
**
STOCKPILE
STACKER RECLAIMER
FEED HOPPER
SECONDARY
CRUSHER
I
I
RECIRCULATE
OVERSIZE
**
SCREENING
-------
is to be fed to bag house (fabric) filters. The collected dust may be fed to
retorts which can use fine material or may be mixed with spent shale and
placed in the disposal area. Stockpiles will be sprayed with bitumastic or
latex preparations to reduce wind blown dust. A review of expected fugitive
dust emissions from these sources is also included in Section 3.
23
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2.2 SURFACE RETORTING TECHNOLOGIES AND DEVELOPMENT PLANS
Above ground retorting processes which have reached the stage of indus-
trial interest in the United States may be divided into three classes based
upon the manner heat is supplied to the retorting process. These categories
include retorts using (a) recycled hot solids, (b) an internal combustion zone
within the retort, and (c) an external, fuel-fired furnace or gasifier. Poten-
tially commercial U.S. retorting processes which employ these various modes
of heat transfer are individually discussed in the sections to follow. Pro-
cesses are presented in the approximate order of their technical and commer-
cial advancement.
2.2.1 TOSCO II Retorting Process (Recycled Hot Solids)
History (14): TOSCO II is the process of The Oil Shale Corporation.
Initial development work (from 1955 to 1966) was conducted under TOSCO
sponsorship by the University of Denver Research Institute, in a 22 tonne/
day (24 ton/day) pilot plant. In 1964 the Corporation formed Colony Develop-
ment Operation, which included SOHIO, Cleveland Cliffs, Atlantic Richfield,
and TOSCO. (Later, Ashland Oil and Shell Oil replaced SOHIO and Cliffs.)
A 909 tonne/day (1000 ton/day) semi-works plant was constructed near Grand
Valley, Colorado, and operated until 1972. The site included a room-and-
pillar mine which produced over one million tons of raw shale, and a number
of test sites for the study of retorted shale disposal and site revegetation.
This process is probably the closest to immediate industrial scale-up
to 8000 m3/day (50,000 bbl/day). It has been dormant since 1974, pending
initiation of a federal synfuels participation program and completion of a
final Environmental Impact Statement (EIS).
Process Technology (12,13,14,15): Minus one-half inch crushed shale
(including fines) is preheated by direct contact with hot flue gases from a
ball heater (see Figure 2-11) used downstream in the process. The preheated
shale is then fed to a horizontal, rotating retort, where it is heated to 480°
C (900°F) by mixing with small, 1.30 cm (1/2") hot ceramic balls. Shale oil
vapors are removed, fractionated and condensed. The cooled balls and retorted
(spent) shale are discharged from the retort, and screened to separate the
spent shale from the balls. The spent shale is cooled in a rotating drum
steam generator, moistened to about 14% water content, and transported to the
disposal site. As discarded it normally contains about 4-5% residual carbon-
aceous matter.
The cooled balls are sent to an external ball heater, reheated, and
recycled to the retort. In a typical situation the ball to raw shale feed
ratio to the retort is about 2:1. The ball heater can use an outside fuel,
a portion of retort off-gases, and/or even the carbonaceous residue on the
spent shale as a fuel source(s).
24
-------
ro
en
RAW SHALE
FLUE GAS TO
ATMOSPHERE
1
BALLS
HOT BALLS
PREHEATED SHALE
RESID
FLUE GAS TO
ATMOSPHERE
MOISTURIZER
EMISSIONS
PROCESSED SHALE
TO DISPOSAL
Figure 2-11. Schematic of the TOSCO II Retorting Process (12)
-------
The crude shale oil is fractionated into gas, naphtha, gas oil, and
bottoms oil. Subsequent hydrotreating and coking is used to upgrade the
products to plant fuel gases and LPG, low sulfur fuel oil, diesel fuel, plus
sulfur, ammonia, and petroleum coke byproducts.
TOSCO has presented considerable detail (",J3) regarding proposed pol-
lution control technologies to be utilized throughout its Yar1^ operations
(mining, retorting, upgrading). In the case of the retorting plant, a venturi
wet scrubber is to be used for dust control in the shale preheat system,
together with settling chambers and cyclones. Hot flue gases in the preheat
system will be incinerated prior to discharge, in order to reduce trace
hydrocarbons. Warm flue gas and a high energy venturi scrubber will remove
residual dust from the ball recirculation system. A foul water stripper will
remove most of the NH3, H2S, and C02 gases from plant waters. Plant fuel
gases will be treated to reduce the sulfur and nitrogen present, prior to
on-site use for heat generation. HgS is recovered as elemental sulfur in a
Claus Plant, tail gases are treated for trace SO? removal in a Wellman-Lord
unit. Arsenic is removed from the gas oil and naphtha prior to hydrogenation
by a proprietary catalytic process. Emissions from the moisturizing of spent
shale are controlled bv a venturi wet scrubber.
Development Plans (13): A full-scale commercial plant processing some
55,000 tonnes (61,000 tons) of raw shale per day for 20 years from a 1600
hectare (4,000 acre) underground mine has been designed, together with up-
grading facilities. A plant site on upper Parachute Creek has been selected,
together with a 325 hectare (800 acre) disposal site in adjacent Davis Gulch.
Two 230 kv powerlines may be built by Colorado Public Service Company to
service the plant. Permit applications have been made for a 310 km (194
mile) long, 40 cm (16 inch) product pipeline to Lisbon Valley Station, Utah.
Access roads and a railroad spur are under construction. A water contract
with the U.S. Bureau of Reclamation proposes to divert .35 cubic meters/sec
(12.5 ft3/sec) of water for the plant from the Colorado River at Grand Valley,
Colorado.
Annual construction employment is expected to reach 2400 people in the
second year of construction. Plant and mine direct employment is estimated
to stabilize at 1,000 when full-scale production is attained in the fourth
year after project initiation, with an additional 1,000 people involved in
peripheral indirect employment.
Recent estimates indicate a grand total investment of $960 million
(Sept. 1975 dollars), with a required selling price of $14.20/bbl at a 10%
discounted cash flow return on an all-equity investment.
Use of TOSCO II Technology at Sites Other than Parachute Creek (Dow
Property):Some 5480 hectares (14,700 acres) of Unitah County land held by
The Oil Shale Corporation has been consolidated into the "Sand Wash Unit" (16)
The Corporation is committed to expend a minimum of $8.million in predevelop-
ment costs on the site. Room and pillar mining of 10-13m (30-40 ft) of shale
at approximately 600 meters (2000 feet) in depth is planned and TOSCO II re-
torting is to be employed.
26
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TOSCO II retorting may be employed in varying degrees at Lease Tracts
C-b, C-a and U-a/U-b.
Environmental Programs: The Colony/TOSCO group has conducted a thorough
environmental assessment of its proposed plant. A 20-volume Environmental
Impact Analysis for the Parachute Creek Development was published in 1974(13).
A formal BLM prepared Draft Environmental Impact Statement was issued in Dec-
ember 1975(12). Hearings were held in January 1976. A final EIS is now being
prepared. The production of 7500 m3/day (47,000 barrels) of fuel oil per day
is contemplated. Revegetation of the disposal area, as stated by Colony,
will be continued for as long as necessary to establish a compatible, stable
vegetative cover.
2.2.2 The Paraho Processes (Gas Combustion and Hot Inert Gas Retorting)
History (14,17): The Gas Combustion Retort was initially developed in
the U.S. Bureau of Mines at Anvil Points, Colorado in 1951, and reached a 136
tonne/day (150 ton/day) pilot plant-capacity at the conclusion of the Synthe-
tic Liquid Fuels.Program in 1955. Between 1964 and 1966, a consortium of six
petroleum companies (Mobil, Humble, Pan American, Sinclair, Continental,
and Phillips) improved the process, attaining a capacity of 320 tonnes/day
(350 tons/day) at yields in excess of 85% of Fischer assay. However, the
studies of the consortium indicate that difficulties were encountered with
small shale sizes, high rates of gas and shale throughout, and bridging due
to rich shales. The Paraho/Development Engineering, Inc. gas combustion
retort was designed to overcome such limitations.
The Development Engineering, Inc., (DEI) kiln was invented by John B.
Jones (U.S. Patent No. 3,736,247), and initially used for calcining limestone
where it has attained a capacity of 636 tonnes/day (700 tons/day) in a 3.2
meter (10.5 ft) diameter design. In May 1972 DEI leased the federal faci-
lities at Anvil Points, Colorado and launched a project to apply the DEI
kiln to oil shale retorting. A consortium of 17 companies, known as the
Paraho Oil Shale Project was formed, and activities at Anvil Points initiated
in late 1973. A 1.4 meter (4.5 ft) diameter pilot kiln was built, followed
by a 2.6 meter (8.5 ft) inside diameter semi-works retort with a nominal
capacity of 410 tonnes/day (450 tons/day). This latter retort has been
operated since 1974, producing 1590 m3 (10,000 barrels) of shale oil for
the Navy in a 56-day continuous run in March 1975. Private financing for
the project to date has been $9 million.
It is planned to continue process development for the next 18 to 24
months under a proposed $6 million ERDA/Navy appropriation, while an Environ-
mental Impact Statement is prepared for construction of a full-scale 11,800
tonnes/day (13,000 ton/day) commercial module.
Process Technology Gas Combustion or Direct Mode (14,17,18): The USBM
Gas Combustion Retort consisted of a vertical vessel fed from the top with raw
shale, which moved downward by gravity through a top preheat zone, thence into
a retorted shale cooling zone. Oil vapors from the retorting zone passed upward
through the preheat zone, where they condensed to a stable aerosol mist that
passed out with the retort gases and were recovered in mist collectors.
27
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Part of the gases released by retorting 700-900 KCAL/m (80-100 Btu/
SCF) were recycled near the bottom of the retort, where they were heated
and passed upward into the combustion zone. Here, new retort gas was in-
jected and the gases burned, together with a portion of the residual carbon
on the retorted shale to furnish the heat for the process.
The Paraho/DEI retort employs the same four-zone configuration and
operating methods, but substantial improvements have been made in the design
of inlet and discharge mechanisms, and in recycle gas/air introduction to
the retort. As a result the remainder of discussion of the gas combustion
method in this section will be restricted to the Paraho process.
In the direct mode Paraho process (Fig. 2-12) minus 7.6 cm (3 in) plus
0.6 cm (1/4 in) shale is introduced into the top of the retort through a
rotating spreader, passes through the 4 zones previously described, and is
discharged through a special, hydraulically operated discharge grate, which
more uniformly controls solids flow rates. Retort off-gases (approx. 900
kcal/m3 Or 100 Btu/SCF) are recycled to the retort at three points. These
gases, together with combustion of a portion of the carbonaceous residue
on the spent shale, provide the heat for the process. The retorted shale
containing a 2.3% carbonaceous residue, is discharged to disposal at approxi-
mately 150°C (3000F). Retort gases, oil mist, and vapors leave the top of
the retort at approximately 66<>C (1500F), and pass through a cyclone, wet
electrostatic.precipitator, and aerial condenser to remove oil. As pre-
viously noted, a portion of these gases are recycled to the retort.
Process Technology: The Paraho Indirect Mode Retorting Process (Hot
Inert Gas Retorting) (18): The Paraho process may also 5e operated in the fn-
direct mode (Fig. 2-13), in which case no combustion is carried out in the
retort, per se. The retort gases therefore have a high heating value 8000
kcal/nn (900 Btu/SCF). A portion of these gases are used to heat a recycle
portion of same in an external furnace, and the latter are recycled to the
retort as a heat source. The retorted shale has a carbon content of 4.5%.
A combination of direct and indirect operating modes may also be employed.
The product shale oil has a 21° API gravity, with pour points of 32°C
(900F, direct mode) or 190C (680F, indirect mode). It may be upgraded by
conventional hydrotreatment to remove nitrogen and sulfur, and refined to
normal petroleum products. No shale oil upgrading has been undertaken at
Anvil Points; all product oil is stored for transport elsewhere.
Development Plans (32); It is proposed by Paraho to construct a single,
full-size, 11,800 tonnes/day (13,000 tons/day) commercial modular retort
at Anvil Points, Colorado, on a site approximately one mile west of the
existing Paraho semi-works plant. The present underground room-and- pillar
mining facilities will be expanded eastward. Raw shale will be passed
through a conveyor system to a 2 hectare (5 acre) retort plant area located
on the present mine road approximately 1.2 KM (3/4 mile) southwest of the
mine, at an elevation of approximately 2,100 meters (7,000 feet). Retorted
shale will be conveyed to the disposal area now being used for the current
Paraho operations. Shale oil will be transported by rail or truck to a
refinery for processing.
28
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RAW
SHALE
t
\t/
OIL MIST
SEPARATORS
D
RETORTING
ZONE
COMBUSTION
ZONE
RESIDUE
COOLING
AND
\ GAS PREHEATING
\ ZONE
DISTRIBUTORS
K
7
OIL
4
GRATE
SPEED
CONTROLLER
RETORTED SHALE
/ELECTROSTATIC
V PRECIPITATOR /
IRECYCLE GAS
BLOWER
I
CRUDE SHALE OIL
NET PRODUCT GAS
AIR BLOWER
FIGURE 2-12 SCHEMATIC OF PARAHO DIRECT MODE
(GAS ooreusTiGN RETORTING PROCESS (is)
29
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MIST FORMATION AND
PREHEATING
ZONE
ELECTROSTATIC
PRECIPITATOR
GRATE
SPEED
CONTROLLER
CRUDE SHALE OIL
AIR BLOWER
fRETORTED SHALE
FIGURE 2-i3Soewnc OF PARAHO INDIRECT MODE
(HOT INERT GAS) RETORTING OB)
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SHM.C nit
CHUTC
Oil ll»tl
Figure 2-14. Side View of Union B Retort (36)
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Primary crushing down to minus 25 cm (10 inch) will be carried out in
the mine, and the raw shale will be fed to a conveyor for transport to the
retorting site. After secondary crushing to approximately minus 8 cm (3
inch) the oil shale will be fed to the top of the modular retort. The full-
size Paraho retort will operate in the same manner as the present demonstra-
tion pilot and semi-works retorts. The full-size retort (13 meters, 42-foot
diameter and 30 meter, 104 foot high vessel) is expected to have a maximum
capacity of approximately 11,800 tonnes/day (13,000 tons/day).
Water requirements are to be met by expanding the current facilities,
which include a supply line from the Colorado River, and a small reservoir
on the mesa itself. The present Public Service Co. of Colorado utility line
will be increased in capacity to meet the anticipated 9000 KVA power needs.
It is estimated that a project period of 3 to 4 years will be required to
construct the facilities and demonstrate the retorting process.
The cost of the modular project was calculated in early 1975 to be $76
million (in 1975 dollars). The present work force of 80 would be expanded
to approximately 300. A temporary construction and mine development crew
of 400 to 450 people for about 18 months is anticipated.
The original funds for the ParaHo program were nearly exhausted in April
1976, and the Anvil Point facilities were partially closed down. The Navy is
currently negotiating a contract with DEI to produce 16,000 m3 (100,000 bbls)
of shale oil by 1978 for refining and military testing. The Paraho project
thus has a temporary reprieve. Paraho submitted a request for ERDA funding
of a 50,000 bbl/day demonstration plant at Anvil Points in 1975, but the re-
quest ts awaiting congressional action on synthetic fuels legislation.
Commercial Use of Paraho Technology: Gulf and Standard of Indiana
(Lease Tract C-a) are participants in the Paraho project and intend to use
the process for part of the shale at Tract C-a (20). SOHIO, Sun and Phillips
also plan to use the technology at the Utah lease tracts U-a and U-b except
for retorting fines (21). Development plans at the lease tracts are reviewed
in Section 2.4.
Environmental Programs: No extensive environmental studies have as
yet been conducted on the Paraho process, pending further work on the pro-
cess technology studies now in progress. Some initial emission and efflu-
ent measurements have been conducted by Paraho and by TRW/DRI (under current
EPA contract). The results are to be published by EPA in 1977.
Emission control technologies for the Paraho processes have not as yet
been indicated, since the basic technology is still under development.
(Several retorted shale disposal methods are under investigation).
Retort gases and condensate waters are presently sent to a thermal
oxidizer for incineration/evaporation. It is expected that pollution con-
trols will be more fully delineated, together with the emissions and efflu-
ents involved, as further research proceeds during the next 18-24 months.
32
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A Draft Environmental Impact Assessment statement was prepared by the
U.S. Bureau of Mines in May 1975. Late in 1975, however, it was determined
by ERDA that a new, full Environmental Impact Statement would be required.
Its preparation and approval may take an additional 9 to 13 months from the
present date.
2.2.3 The Union Oil Process (Retort B - Hot Inert Gas Retorting)
History of Technology Development (14,17): The Union Oil Company has been
involved in oil shale activities for several decades, beginning in the 1920's
with the purchase of 12,000 hectares (30,000 acres) of fee property contain-
ing oil shale resources. The development of Union's oil shale retorting
technology was initiated in the early 1940's, and three variations of a ver-
tical kiln retorting process, with upward flow of shale and counter-current
downward flow of gases and liquids, have been developed. These variations
are known as the Retort A, the Retort B, and the Steam Gas Recirculation
(SGR) processes. The first concept, the Retort A process, has been carried
through 1.81 tonnes (2 tons) per day and 45.5 tonnes (50 tons) per day pilot
plants. This was followed by the construction and operation of a large
demonstration plant in the late 1950's. The demonstration plant was designed
for 317.5 tonnes (350 tons) per day capacity, but long-term operability was
demonstrated at rates of 635 to 907 tonnes (700 to 1,000 tons) per day, with
a peak rate of 1,089 tonnes (1,200 tons) per day. Although the demonstration
of the Retort A process was extensive and successful, the Union Oil work,
except for a continuing low level research effort, was suspended because of
a plentiful supply of low-cost Middle East oil and natural gas at the time.
The two improved versions of the Union Oil process, the Retort B and the SGR
processes, were both developed in the 1970's in response to increasing
energy demands and shortage of fuel supplies. Both the Retort B and the SGR
processes have been carried through pilot plant stage. It is the Retort B
process that Union Oil now proposes to construct and demonstrate at the
9,072 tonnes (10,000 tons) per day rate, along with all necessary auxiliary
facilities. The SGR technology may be employed at later stage of development.
Process Technology Summary (17,22,36): In the Retort B process, shov/n in
Figs. 2-14 and 2-15, crushed oil shale in the size range of 3 to 5 cm
(1/8 to 2 inches) flows through two feed chutes to a solids pump. The solids
pump consists of two piston and cylinder assemblies which alternately feed
shale to the retort; the pump is mounted on a movable carriage and is com-
pletely enclosed within the feeder housing and immersed in oil. As shale
is moved upward through the retort by the upstroke of the piston, it is met
by a stream of 510 to 538°C (950 to lOOQOF) recycle gas from the recycle
gas heater flowing downward. The rising oil shale bed is heated to retort-
ing temperature by countercurrent contact with the hot recycle gas, result-
ing in the evolution of shale oil vapor and make gas. This mixture of shale
oil vapor and make gas is forced downward by the recycle gas, and cooled by
contact with the cold incoming shale in the lower section of the retort
cone. In the disengaging section surrounding the lower cone, the liquid
level is controlled by withdrawing the oil product, and the recycle and make
gas is removed from the space above the liquid level. As shown in Fig.
2-15, the make gas is first sent to a Venturi scrubber for cooling and heavy
33
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B F
U>
RETORT HAKE GAS TO
GAS TREATING
RETORTED SHALE TO
DISPOSAL
RUNDOWN OIL PRODUCT
Figure 2-15. Flow Diagram for Union B Retorting Process (36)
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ends removed by oil scrubbing. That portion of the 7109 kcal/m3 (800 Btu/SCF)
gas not recycled is then processed by compression and oil scrubbing to remove
additional naphtha and heavy ends, followed by hydrogen sulfide removal 1n a
Stretford unit. The sweetened make gas 1s used as plant fuel.
The product oil withdrawn from the retort is treated sequentially for .
solids, arsenic, and light ends naphtha removal. The solids removal is accom-
plished by two stages of water washing. The shale fines are collected in the
water phase which is recycled to the water seal. The water seal is a Union
Oil concept shown in Figure 2-15, in which a water level is maintained in a
conveyor system for retorted shale removal to seal the retort pressure from
atmosphere. For arsenic removal, a proprietary Union Oil process employing
an adsorbent is utilized to reduce the arsenic content of the raw shale oil
from 50 ppm to 2 ppm. The dearsenated shale oil is then sent to a stripping
column for stabilization prior to shipment. The resulting crude shale oil
has a 22.7° API gravity, 60°F pour point, 1.7% nitrogen and 0.81% sulfur
content, and low (1.75%) Conradson carbon residue. At the present time,
Union Oil does not envision additional upgrading of the crude shale oil on-
site.
For the Retort B process, all the plant fuel requirements will be met
by the make gas produced. The principal pollution control devices in the
Union Oil design include the Stretford process for hydrogen sulfide removal
from the retort make gas and oil/water separation and sour water stripping
for waste water treatment. The treated waste water is used in the cooling
and moistening of the retorted shale to provide for dust control and proper
compaction.
Development Plans (23): To further the development of the Retort B pro-
cess, Union Oil has proposed to the U.S. Energy Research and Development Ad-
ministration a cooperative $120 million venture to build a 9,070 tonnes
(10,000 tons) per day prototype plant capable of producing 1,240 IIH (7,800
barrels) of shale oil per day. This prototype plant will be constructed on
Union Oil property located on Parachute Creek, north of Grand Valley, Colorado.
Union Oil owns a total of more than 12,000 hectares (30,000 acres) of fee
property containing about 0.32 billion m3 (2 billion barrels) of recoverable
shale oil in the rich Mahogany zone.
The mining and the processing area for the demonstration plant will be
located on a bench on the north side of the East Fork of Parachute Creek.
The mine portal is designed to open on to a bench at the 2,100 m (7,000 ft)
elevation. The conventional room and pillar method will be employed for
production mining, with rooms 18.3 m (60 feet) high by 18.3 m (60 ft) wide
and pillars having an 18.3 m (60 ft) square horizontal section. For the
9,070 tonnes per day prototype plant, the water consumption rate is esti-
mated to be 81 m3/hr (355 gpm) and the power requirement to be 11,300 kw.
Unton Oil filed water right applications as early as 1959, and a conditional
decree has been awarded by the Colorado State Court to Union Oil for claimed
water rights of 200 m3/sec (118.5 ft3/sec or 85,770 acre-feet per year).
35
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All electric power will be purchased from outside the plant and probably be
supplied by the Public Service Company of Colorado.
For the prototype plant, 7,620 tonnes (8380 tons) per day (dry basis)
of retorted shale containing approximately 20 percent water will be trans-
ported to a disposal area in the East Parachute Creek Canyon, where it will
be deposited in windrows proceeding up the south embankment. (See Figure 4-5),
Union Oil has estimated that 32 months will be required to design and
construct the prototype plant with all its auxiliary facilities. The opera-
ting program to assess the technical, economical and environmental feasi-
bility of the Retort B process is scheduled for two years. If the process
proves to be viable, two more retorts would be constructed at the prototype
site, bringing the total plant capacity to 27,200 tonnes (30,000 tons) of
oil shale feedrate per day.
Environmental Programs: Union has conducted studies of the various
environmental impacts to be encountered in a Retort B Prototype Plant.
Among the control technologies to be employed are the following:
Primary and secondary crushing will be done underground. A dust suppres-
sion system will be used for dusts from both mining and crushing operations.
Because of the oil seals and water quench used, the retort is essentially
free of participate emissions. The plant is totally water consumptive. Any
process waters or run-off will be captured in the plant's collecting pond.
t It is not planned to flare excess make-gas, but rather to absorb heavy
ends into the oil product.
0 Retorted, wet spent shale (20% H20) will be conveyed to windrows at the
disposal site, and compacted to 1764 Kg/m3 (90 Ibs/ft3) density for stabil-
ity. Outer slopes and the top of the piles will be revegetated. A leachate
ditch will be constructed to gather leachates from run-off, and discharge
these to the plant water supply pond.
Union Oil is in the process of completing the environmental impact
analysis (EIA). Originally scheduled to be issued in May 1976, release of
the EIA has now been postponed indefinitely pending the outcome of synthetic
fuels commercialization legislation and ERDA's decision to participate
in the demonstration of the Union Retort B process at the 9,072 tonnes per
day capacity.
2.2.4 Superior Oil Process (Hot Gas Retorting, Combustion of Residual Car-
bon) (24,25)
History; Superior Oil has owned some 2,600 hectares (6,500 acres) of
oil shale land in the northern Piceance Creek Basin for nearly 40 years.
In 1967 it began a drilling and geological evaluation program, and found
that the deeper shales on the property contained attractive quantities of
nahcolite (NaHO^) and dawsonite (NaAHOH^CO^) minerals, as well as oil
shale. A research program was therefore initiated to permit integrated
36
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<*>
Figure 2-16. Top View of Superior Retort (25)
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SHAIE BED
MOOO
OPERATING FLOOD
Figure 2-17. Cross Section View of the Superior Retort (Courtesy of Arthur McKee & Co.)
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recovery of these minerals and shale oil. Included were investigations into
the development of a circular grate retort.
A small laboratory unit is being tested in Superior's Denver, Colorado
facilities. A pilot plant unit of 9-18 tonnes/hour (10-20 tons/hr) capacity
is currently under construction in Cleveland, Ohio, to be in operation in the
fall of 1976. If results are successful this will be followed by erection
of a 18,000 tonnes/day (20,000 ton/day) full-scale commercial modular on
Superior's Piceance Creek Basin site.
Meanwhile Superior has proposed to the Bureau of Land Management an ex-
change of 1,000 hectares (2,500 acres) of Superior land for 680 hectares
(1700 acres) of adjacent federal land, in order to provide a more economi-
cally mineable tract with uniform geologic features. The U.S.G.S. has
recently evaluated mineral values of the lands in question and has indicated
that Superior's land has lower mineral values than the lands asked for in
trade. A decision by the Bureau of Land Management on this land trade is
still pending.
Process Technology: The Superior integrated process involves underground
room and pillar mining at a depth of 600 meter (2000 feet); processed shale is
to be returned to the underground mine for disposal. After primary crushing
underground, 80-95% of the nahcolite present will be recovered mechanically
by secondary crushing to minus 7.5 cm (3 in), and screening to remove the
NaHCOs.
The dawsonitic shale from NaHCOs recovery will be fed in 3 streams to
a traveling circular grate retort (Figs. 2-16 and 2-17). A commercial sized
module is expected to be 56 meters (185 ft) in diameter, with a capacity of
21,000 tonnes/day (23,000 tons/day). The doughnut-shaped retort has five
separately-divided sections, through which the shale travels in sequence.
These are a loading zone, retorting zone, residual carbon recovery zone,
cooling zone, and unloading zone. Hot gases are drawn downward through the
bed of shale on the grate, in the retorting zone, producing oil-laden vapors
which are removed and the shale oil condensed. The oil-denuded and cooled
gas stream is next recycled to the cooling zone, and drawn downward through
the spent shale to reduce temperature of the shale prior to discharge. The
cooled shale is fed to the leaching plant for recovery of alumina (Al20a)
and soda ash (Na2C03).
During retorting the dawsonite in the retorted shale is converted to
alumina and sodium carbonate. These are processed in the leaching plant by
dissolution and subsequent recovery of soda ash (NaHCOs) and aluminum hydrox-
ide. The A1(OH)3 is calcined to cell-grade alumina.
The spent s&ale (sodium-minerals and shale oil denuded) is sent to the
underground mine as a wet cake on the production conveyor during its return
run. No revegetation of retorted shale will therefore be required.
Development Plans: As noted previously a 9-18 tonne (10-20 ton) travel-
ing grate pilot retort is to begin operation in Cleveland in the fall of
1976. If successful, this will be followed by construction of a full-scale
39
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~18,000 tonnes/day (20,000 ton/day) modular plant and mine on Superior's
2,600 hectare (6,500 acre) property in Colorado's northern Piceance Creek
Basin. This scale-up is partially dependent on a proposed land exchange
with the federal government (24).
Water requirements for the full-scale plant are to be satisfied by
utilizing the saline water in the "leached zone" aquifer directly above the
proposed mine. Plant cooling waters will be returned to the aquifer. Power
requirements for mining and processing will be purchased off-site. The cost
of the full-scale plant and its manpower requirements have not been esti-
mated.
Environmental Programs; Superior has not released detailed data on the
emissions and effluents to be expected from its process. (Superior has
indicated that a portion of the nahcolite produced could be added to the
retort feed "for sulfur removal.") It can be expected that, in addition to
control of normal shale oil plant emissions and effluents, control of brines
and wastes from the leaching plant and associated mineral recovery activi-
ties will be necessary.
Superior is currently preparing an Environmental Impact Analysis of its
integrated process, but no release date has as yet been established.
2.2.5 Lurgi-Ruhrgas Process (Recycled Hot Solids) (17,26,27)
History: This process was developed jointly by two German firms,
Lurgi-Gesellschaft and A. G. Ruhrgas, in the 1950's for low-temperature coal
carbonization and for cracking saturated hydrocarbons to olefins. Two lig-
nite carbonization units with a combined plant capacity of 1500 tonne/day
(1700 tons/day) began operation in Yugoslavia in 1963. A small 14-23 tonne/
day (16-25 ton/day) plant in West Germany has been used to retort Colorado
oil shale, at a yield of 100 percent of Fischer assay. The Lurgi Company
indicates that a retorting unit of 5000 tonnes/day is technically feasible.
Process Technology: In the L-R process, minus 1.3 cm (1/2 in) shale
is heated by contact with hot, finely-divided solids in a horizontal, cylin-
drical vessel with a screw conveyor- The finely-divided heat carrier may be
sand or coarse shale ash. The products are withdrawn from the top of the
mixer, dedusted, and condensed. The spent shale and heat carrier pass into
a lift line, together with dust from dedusting. Air is added and the carbon
is burned off the spent shale-heat carrier mixture. Thus the carrier is
reheated and is recycled after dust removal.
Because of the direct contact between shale solids and heat carrier, heat
transfer is rapid, leading to high-throughput retorts. Care must be taken
to avoid readsorption of shale-oil vapors on the solids in order to prevent
loss of yield. Patents cover related processes developed by a number of U.S.
companies which have examined this potentially attractive retorting method.
Development Plans (28): In late 1975 American Lurgi presented a proposal
to 14 major owners or leasees of oil shale land to elicit support for construc-
tion of a 4,000 tonne/day demonstration plant of the L-R process. It was
40
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estimated in the proposal that the plant could be operational 36 months
after project approval. This proposal is apparently still active, but no
actual site Is indicated at present.
Environmental Studies: No specific environmental studies have been
published on the L-R process to date; although limited data are available
regarding certain emissions and effluents from the process in pilot scale.
2.3 COMMERCIAL DEVELOPMENT PLANS EMPLOYING IN-SITU TECHNOLOGY
In-situ extraction of shale oil has attracted research interest for
many years. Only recently, however, has commercial interest emerged. Both
"true" and "modified" in-situ projects are included in the commercial pro-
jects discussed below. The major emphasis in this section is placed on the
Occidental process since it is the most nearly commercial of the in-situ
developments.
2.3.1 The Occidental Modified In-Situ Process (29,30,31,32)
History of Technology Development: Occidental Petroleum Corporation's
involvement in oil shale technology is a relatively recent development. In
late 1972, Garrett Research and Development Company (now Occidental Research
and Development), a subsidiary of Occidental Petroleum Corporation, an-
nounced plans for the field testing of a modified in-situ shale oil recovery
scheme which is the subject of U.S. Patent 3,661,423. The actual work began
in the summer of 1972 on the private property (known as the D. A. Shale, Inc.
property) at the head of Logan Wash outside of Debeaue, Colorado. In the
ensuing months, three research retorts, each 9.1 m (30 ft) on a side and
21.9 m (72 ft) high, were prepared and ignited.
At the end of 1974, the project was transferred to an operating branch
of the company, when Occidental Oil Shale, Inc., a subsidiary of the Occi-
dental Oil and Gas Production Division, was created. Concurrently, a deci-
sion was made to initiate the development of a commercial size retort in the
commercial mine, located off the north side of Logan Wash about a quarter
mile below the head of a canyon. The commercial mine is being developed at
a new location because there is insufficient room at the head of Logan Wash
(the research mine location) to permit a large mining operation, and be-
cause the research mine is located just below the Mahogany Ledge and too
high for the construction of commercial size retort columns. The first
commercial size retort (Retort No. 4), with a 36.6 m (120 ft) by 36.6 m
(120 ft) cross section and 76.2 m (250 ft) height and containing 15 gpt
rubblized shale, was ignited from the top on December 10, 1975. A total of
4,300 m3 (27,000 bbls) of oil has been recovered from the retort, and produc-
tion rates of about 80 m3 (500 bbls) per day have been realized.
Process Technology Summary: The modified in-situ process for shale oil
recovery consists of retorting a rubblized column of broken shale, formed by
expansion of the oil shale into a previously mined out void volume. The
Occidental process involves three basic steps. The first step is the mining
41
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out of approximately 20% of the oil shale deposits (preferably low
grade shale or barren rock), either at the upper and/or lower level of the
shale layer. This is followed by the drilling of vertical longholes from
the mined-out room into the shale layer, loading those holes with an ammo-
nium nitrate-fuel oil (ANFO) explosive, and detonating it with appropriate
time delays so that the broken shale will fill both the volume of the room
and the volume of the shale column before blasting. Finally, connections
are made to both the top and bottom and retorting is carried out (Fig.2-18).
Retorting is initiated by heating the top of the rubblized shale column
with the flame formed from compressed air and an external heat source, such
as propane or natural gas. After several hours, the external heat source
is turned off, and the compressed air flow is maintained, utilizing the
carbonaceous residue in the retorted shale as fuel to sustain combustion.
In this vertical retorting process, the hot gases from the combustion zone
move downwards to pyrolyze the kerogen in the shale below that zone, produc-
ing gases, water vapor, and shale oil mist which collects in the trenches
at the bottom of the rubblized column (Fig. 2-19). The crude shale oil and
byproduct water are collected in a sump and pumped to storage.
The off-gas consists of products from shale pyrolysis, carbon dioxide
and water vapor from the combustion of carbonaceous residue, and carbon
dioxide from the decomposition of inorganic carbonates (primarily dolomite
and calcite). Part of this off-gas is recirculated to control both the
oxygen level in the incoming air and the retorting temperature. The off-
gas has a heating value of approximately 580: kcal/m3 (65 Btu/SCF), and the
part of t&e off-gas not recycled is currently flared.
Occidental envisions using the low Btu gas from a commercial retort for
generating electric power. Turbines manufactured by Brown-Boveri of Switzer-
land will be investigated for this application. According to Occidental's
estimate, only 20 to 25 percent of the electric power produced from the low-
Btu gas is required for operating the modified in-situ process.
Occidental has not disclosed any information on the design of surface
oil and gas treatment plants. The minimum treatment required for the crude
shale oil produced from the retorting process will include phase separation
of the oil from the byproduct water and the stabilization of the oil product.
The waste-water effluent from the phase separator may be used for steam
generation after appropriate treatment.
Retort water volume produced from the Occidental process is approxi-
mately equal to shale oil volume. This quantity of water is approximately
equal to in-situ shale processing requirements. It is not known whether
Occidental has investigated the treatment of the retort water for use in
oil shale development.
The crude shale oil produced from the Occidental process has a specific
gravity of 0.904 (API gravity of 250), a pour point of 21<>C (70°F), a sulfur
content of 0.71 weight percent and a nitrogen content of 1.50 weight percent.
The crude shale otl is also reportedly free of solids and may be potentially
usable as boiler fuel without upgrading.
42
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>.oJ»»",»C»-3,/»jC&r 75ir&-1>
Figure 2-18. Schematic of the Occidental Modified In-Situ Process (30j
43
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AIR t RECYCLE GAS
rRETORTIMG AND VAPORIZATION
L
PILLAR
Figure 2-19 Flame Front Movement in the Occidental Modified In-Situ Process
(30)
44
-------
Development Plans: Occidental has invested over $30 million during
the last five years in the development of the modified in-situ process. A
second commercial size retort (Retort No. 5), similar in dimensions to
Retort No. 4, is now being prepared. If the process proves to be success-
ful at the current 79.5 m3/day (500 bbl/day) level, Occidental expects to
attract sufficient support for the construction of a 795 m3/day (5,000 BPD)
demonstration mine and retort. The demonstration mine and retort would pro-
vide the necessary information on the technical and economic feasibility
and the environmental acceptability of advanced mining techniques and multi-
ple in-situ retorts. After the successful demonstration of these concepts,
Occidental plans to expand the shale oil operations to commercial propor-
tions, without the need for federal subsidies or loan guarantees.
The Occidental in-situ experiments have been conducted on private land
controlled by D. A. Shale, Inc., through a three-year lease and option agree-
ment that has since been extended. The D. A. Shale property contains rela-
tively low grade shale (15 gpt) and may be marginal for commercial operation.
Occidental is seeking to enlarge its holdings of land underlain by higher
grade oil shale and has nominated two tracts in Colorado under the Interior
Department's Prototype Oil Shale Leasing Program (Section 2.4).
Environmental Studies and Activities: During its in-situ experiments,
Occidental has contracted Claremont Engineering to conduct ambient monitor-
ing of gaseous criteria pollutants and stack monitoring of selected pollu-
tants in the retort off-gas, such as S02, CO and H2S. The daily averages
of the measured values of the pollutants have been reported to the State of
Colorado on a quarterly basis. The retort off-gas is of special concern
because of the large quantity of gas involved, which eventually must be
vented to the atmosphere after burning (either in turbines to generate
electric power or through simple incineration).
A water problem of special concern is the contamination of naturally
occurring groundwater infiltrating the underground development of an oil
shale zone. At Occidental's present site, there is little or no ground
water (pump tests have yielded less than 2.3 m3/hr or 10 gpm) due to the
geology of the area. According to Occidental, the mining scheme for the
center of Plceance basin should be so designed to keep the aquifers isolated
from the target oil shale below. In this area, the access shaft to the oil
shale zone should also be lined (e.g., with cement) to prevent contamination
of the aquifer. In areas where there 1s saline water below and within the
target oil shale zone, Occidental believes that 1n most cases, it 1s possible
to either seal off the area or to pump the water to the surface and relnject H
1n the same formation downdlp. A closely related area of concern, the potentii
for underground leaching of the spent shale, 1s also not considered by Occi-
dental to be a significant problem. Occidental envisions that leaching of the
spent shale will be limited due to the large size of the shale pieces. The
movement of the water will be slow and probably confined to the spent chimneys
The water quality 1n Roan Creek, Logan Wash and Dry Gulch 1s currently
monitored by Occidental.
There is no retorted or spent shale disposal problem associated with
the Occidental process. The rock mined is not significantly different from
45
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the naturally occurring material in the region and will be dumped into the
canyons near the oil shale mine. A permit for increasing the size of its
mined waste disposal pile from 382,000 m3 (500,000 cubic yards) to 6,500,000
m3 (8.5 million cubic yards) was recently granted to Occidental by Garfield
County Commissioners on January 13, 1976. The approval of this special per-
mit provides Occidental with sufficient mined rock (low grade shale) dis-
posal capacity to expand into the large demonstration phase. The permit
was granted on the basis that the raw shale pile would not be found to de-
grade the water quality of the area. A second stipulation of the permit is
that upon completion of the raw shale pile, Occidental will restore the
vegetative cover to a condition compatible with comparable natural talus
slopes in the vicinity.
Occidental has developed a list of 48 activities for which environmental
effects and permits must be considered, and has assembled a team of seven
people to gather environmental baseline data. The studies conducted include
a meteorological study, fauna and flora studies, the completed paleontolo-
gical and archaeological studies, ambient air and retort vent gas monitoring
studies, water quality monitoring studies, and others. The EIA for the
development of the Occidental process is scheduled to be released in December
1976.
2.3.2 Western Oil Shale Corporation (WESTCO) (16)
Western Oil Shale Corporation (WESTCO) initiated a project in 1975,
with a consortium of 10 companies, to design a modified in-situ project on
a site in the Uinta Basin. Three underground vertical retorts ("chimneys")
are to be investigated, using special DuPont explosives.
2.3.3 Geokinetics. Inc.(16)
Geokinetics has also begun field tests of its "true11 in-situ process
on a site some 15 miles south of federal lease Tracts U-a/U-b. After
explosive fracturing, a horizontal fire flood is to be employed.
2.3.4 ERDA In-Situ Research, Development and Demonstration Project
ERDA has issued a Program Opportunity Notice for in-situ proposals from
private interests. Federal support is indicated through commercial demon-
stration. ERDA is currently negotiating contracts with Occidental, Equity,
Geokinetics, and Talley-Frac.
2.4 FEDERAL OIL SHALE LEASE TRACTS
Late in 1973 the Department of the Interior prepared six oil shale pro-
totype lease offerings on federal land in Colorado, Utah and Wyoming (33).
TaSle 2-1 summarizes the high bids received for the offered tracts (34).
Recently requests for in-situ nominations have been solicited, since no bids
were received for the Wyoming tracts in 1973. The locations of the four
active leases and the four preferred in-situ nominations are shown in Figures
2-1 and 2-2 (35).
46
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Table 2-1. Results of Federal 011 Shale Lease
Offerings (34)
Tract
Colorado
C-a
C-b
Utah
U-a
U-b
Wyoming
W-a
W-b
Area
[Hectares)
i Acres)
2060
(5088)
2062
(5093)
2073 %
(5120)
2073 %
(5120)
2070.
(5113)
2070
(5113)
Recoverable
Resource Estimate
106m3 (106 bbls)
200 (1300)
116 (723)
53 (331)
43 (271)
57 (354)
57 (352)
High Bonus
Bid (106 $)
210
118
76
54
None
None
Original
Lessees)
(Rio Blanco Oil Shale
Project
Standard of Indiana
Gulf Oil Corp.)
(Atlantic Richfield
Ashland Oil
Shell Oil
The Oil Shale Corp.,
TOSCO)
Sun Oil Co/Ph1H1ps
White River Shale Oil
Corp.
(Sun, Phillips, Sohlo)
_
47
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The status of development plans at the federal lease tracts is reviewed
in this section. The developers of tracts C-a, C-b and U-a/U-b have submitted
detailed development plans to the area oil shale supervisor. The in-situ
nominations have been made and final choice for leasing awaits an Environmental
Impact Statement (EIS). In March of 1976 Roxana (Tract C-b) formally requested
a suspension of tract development requirements and a postponement of the 4th
and 5th bonus payments as required by the lease. RBOSP (Tract C-a) and WRSP
(Tracts U-a/U-b) have submitted similar suspension requests to the Department
of the Interior in July of 1976. Althouoh the area oil shale supervisor
(AOSS) is currently reviewing the Detailed Development Plans for each tract,
the Secretary of the Interior granted the suspension of development at C-a and
C-b in August 1976, and at U-a/U-b 1n October 1976.
2.4.1 Tract C-a - Rio Blanco Oil Shale Project (RBOSP) (7)
Project Description: The Rio Blanco Oil Shale Project (Standard of
Indiana and Gulf Oil Corp.) has recently submitted a detailed development
plan (DDP) to the area oil shale supervisor (AOSS) in Grand Junction. This
plan envisions a phased development of Tract C-a using open pit mining (Table
2-2). Mining will commence at the northwest corner of the lease tract and
will have disturbed less than 300 hectares (750 acres) at the end of Phase I.
Phase I will involve the construction and operation of two TOSCO II
retorts, each capable of processing 9,700 tonnes (10,700 tons) of oil
shale per day. During 1982, total crude shale oil production is planned at
1,400 m3/day (9,000 bbU/day) (see Table 2-2). Phase I processing opera-
tions will Include a thermal cracking plant and a sulfur recovery plant.
Phase I support systems include water supply from ground water sources
on the tract (5.3-9 m3/min or 1400-2400 GPM), a power line from an existing
230 KV line near the White River, and an extension of the existing Ryan Bulch-
C-a road to Rangeley. Product oil will initially be pipelined to Rangeley,
thence through an existing AMOCO pipeline to a refinery. Peak manpower re-
quirements during Phase I is expected to be about 700 employees.
In addition to DDP approval by the AOSS, the Rio Blanco project requires
several government actions before development can proceed. Plans call for
location of processing facilities and the retorted shale disposal area outside
the tract (to the north). An amendment to the Mineral Leasing Act of 1920 is
apparently required to allow this use of off-tract federal lands, and such
legislation is now pending in the U.S. Congress (S.2413 and H.11163). RBOSP
also requires approval of rights-of-way for service corridors and State of
Colorado support for the proposed Rangeley access road. Finally, RBOSP envi-
sions its employees living primarily in Rangeley, and has assisted the town
in planning for growth. Urban expansion will probably require access to sur-
rounding federal land; a mechanism for acquiring such land will be required.
Phase II operations at C-a are envisioned to begin in 1985 and will employ
both TOSCO and Paraho (gas combustion) retorting. Open pit mining will expand
to about 108,000 tonnes/day (120,000 tons/day) to feed the retorts Rio
Blanco plans to upgrade crude shale oil at 8,960 m3/dav (56,000 bbls/day) by
delayed coking, and by hydrogenation of naphtha and gas oil distillation
Tractions.
48
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Table 2-2. Tract C-a - Rio Blanco Oil Shale Project Summary (7)
MINING
Type
Production
Ore Haulage
Overburden Haulage
PROCESSING
Retorting
Upgrading
PRODUCTS
Pipelineable Shale Oil
Upgraded Shale Oil
Sulfur
Ammonia (anhydrous)
Coke
Moisturized Processed Shale
WATER DEMAND
POWER DEMAND
PEAK EMPLOYMENT
Construction
Operation
ELAPSED TIME
Construction
Operation
PHASE I
PHASE II
Stage 1
Open Pit
10,000 tonnes/day
Belt Conveyor
Truck
TOSCO II
Thermal Cracking
stage 2
Open Pit
19,400 tonnes/day
Belt Conveyor
Truck
TOSCO II
Thermal Cracking
Open Pit
108,000 tonnes/day
Belt Conveyor
Belt Conveyor
Combination of TOSCO II & Gas
Combustion/Paraho
Delayed Coking & Hydrotreating
Belt Conveyor
720 m3/day (4,500 BPSD) 1440 m3/day(9,OOOBPSD)
11 tonnes/day 22 tonnes/day
8,930 ,i)2/day (55,800 BPSD)
153 tonnes/day
210 tonnes/day
425 tonnes/day
10,000 tonnes/day 20,000 tonnes/day 107,700 tonnes/day
1.76x10^3^(1,390 AFY) 3.5xlo6m3/yr(2,370 AFY) 12.7xlo6m3(10,000 AFY)
17.7 MW 28.8 MW 227 MW
700
300
2 years
3 years
400
500
2 years
3 years
2,200
1,100
3 years
20-30 years
Notes: BPSD = bbls per stream day
AFY * acre-feet per year
MW = megawatts =10* watts
-------
Hydrogen will be produced on site by partial oxidation (gasification) of heavy
shale oil distillatiorr residue. The operation is designed to consume
all gaseous products as plant fuel. Elemental sulfur and ammonia will be
recovered as co-products from gaseous and liquid product streams.
Phase II operations are expected to be supplied by "on tract" ground
and surface water. Expansion beyond 8,960 m3/day (56,000 bbls/day) of shale
oil will require additional water supplies and Rio Blanco has applied for an
8.5 m3/sec (300 «3/sec) water right on the White River.
Environmental Programs: Mining and shale preparation air pollution con-
trol at Tract C-a will include frequent watering at the mine and on trans-
port roads, enclosing and spraying raw and crushed shale at transfer points,
and using baghouse filters with induced-draft fans for crushing and
screening operations.
Process pollution control is to be accomplished by technology similar
to that described in the TOSCO II section (2.2.1). Phase I operations
will include a thermal oxidizer to handle certain ammonia and sulfur contain-
ing gas streams, excess fuel gas, and oil/water separator sludges.
Phase II air pollution control will include technology similar to that
used in Phase I, with the combination of GCR and TOSCO II retorts supplying
the operation with entirely gaseous fuels. Cleaned low and high Btu fuel
gases generally present a lower emissions potential from process heaters
than liquid fuels. Hydrogen sulfide and ammonia removal from in-plant fuels,
the use of wet and dry venturi scrubbers, and incineration of trace hydrocarbons
1n the TOSCO II preheat system are the major air pollution control techniques.
Water quality control at Tract C-a is based on a zero discharge concept.
Rio Blanco plans to collect storm and surface waters, mine waters, and pro-
cess waters for in-plant use or for controlled evaporation. The ultimate
disposition of wastewater is evaporation, or entrapment as a permanent com-
ponent of retorted shale.
RBOSP plans to dispose of retorted shale, mine overburden, and other
solid wastes (spent catalysts, coke, lime sludge, spent zeolites) on a site
called "84 Mesa," north of Tract C-a. This site is sufficient to accommodate
waste for up to 30 years before backfilling of the open pit .is planned. Tests
are currently underway to determine the best revegetation techniques for the
soil and overburden profile which would eventually "cap" the retorted shale
pile.
RBOSP is conducting a two-year baseline monitoring program to define
natural conditions at Tract C-a prior to oil shale development (part of
lease stipulations). Continued monitoring of meteorology, ambient air and
water quality, ground and surface water hydrology, soils and geology, ter-
restrial and aquatic flora and fauna is planned through development stages
of the project. A more detailed description and evaluation of monitoring
activities at C-a and other lease tracts is presented in Chapter VI of this
report.
50
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2.4.2 Tract C-b (Roxana) (6)
Project Description: Tract C-b is a joint venture of Ashland Oil, Inc.
and Shell Oil Company, known as the Roxana Shale Oil Company. Atlantic
Richfield and The Oil Shale Corp. (TOSCO), originally partners in the C-b
venture, have withdrawn from the project. Roxana'* two remaining partners
submitted a detailed development plan to the Area Oil Shale Supervisor
(AOSS) in February 1976. The future of the project is uncertain however,
due to ARCO and TOSCO withdrawal, technical and economic uncertainties about
extraction of deep Mahogany Zone shale on the tract, and lack of a federal
energy policy.
Table 2-3 summarizes the Roxana project plans. The C-b DDP envisions
development mining (Phase I) for about 5 years in order to establish deep
mining technology and define geologfc and hydrologic conditions on the tract.
Coarse ore would be stockpiled until completion of the Phase II construction
of surface retorting and upgrading facilities. Roxana plans to use TOSCO II
technology (both Ashland and Shell are members of the Colony Group), and
surface operations are expected to be similar to those planned by Colony for
use at the Parachute Creek property.
Water produced during Phases I and II may exceed project demand, and
excess waters will be directly discharged if quality is adequate, and rein-
jected or used for spray irrigation if water is of poor quality. Phase III
processing operations will likely require more water than can be obtained
from aquifers on the tract, and Roxana plans to obtain additional water
from the Colorado River (perhaps in conjunction with Colony development)'.
A product pipeline(s) will follow the water supply corridor south from
the tract via Parachute Creek to the Colorado River. An electric power
corridor will extend to the north and east to connect with the White River
grid.
Environmental Programs: During the mine development and construction
phases at C-b, air pollution sources will mainly be fugitive dust, stationary
diesel emissions, and vehicular emissions. Dust control will be accomplished
by watering, by use of chemicals, and by minimizing exposed soil surfaces.
Shale preparation and retorting process emissions and effluents, and
associated pollution control technologies at C-b are the same as those des-
cribed in Section 2.2.1 of this report (TOSCO II process). All process waste
water will be consumed 1n the moisturizing of retorted shale.
Retorted shale and other solid wastes will be disposed of on the east
stde of Tract C-b in Sorgum Gulch (see Section 4.3). During Phase I, a dam
will be constructed below Sorgum Gulch for collection and storage of excess
mine water. Later, the dam will serve to retain any runoff from retorted
shale piles. Colony's experience in revegetating spent shale at Parachute
Creek will be applied at C-b. As was the case with RBOSP, Roxana is conduc-
ting a two-year baseline environmental monitoring program as required by lease
conditions.
51
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Table 2-3. Tract C-b - Roxana 011 Shale Project Summary (6)
01
ro
MINING
Type
Production
Ore Haulage
PROCESSING
Retorting
Upgrading
Processed Shale Haulage
PRODUCTS
Plpellneable Shale 011
Upgraded Shale 011
Sulfur
Amnonla
Coke
Moisturized Processed
Shale
HATER DEMAND
POWER DEMAND
PEAK EMPLOYMENT
Construction
Operation
ELAPSED TIME
Construction
Operation
PHASE I
Nine Development
(room & olllar)
3.5 x 10° total tonnes
To Storage via Belt Conveyer
Excess Hater Produced
5-10 MH
425
5 years
1 year
PHASE II
Development Mining
Stockpiling of Ore
Plant Construction
Plant Construction
Excess Water Produced
20 MH
3300
4 years
1 year
PHASE III
Room and Pillar
60,000 tonnes/day
Belt Conveyor
TOSCO II
Delayed coking,
hydrotreatlng
Conveyor
8000 m3/day (50.000
bbls/day)
175 tonnes/day
136 tonnes/day
727 tonnes/day
60,000 tonnes/day
Total Requirement
435m3/sec(12.3 CFS)
100 MH
1000-1200
20-30 years
-------
2.4.3 Tracts U-a/U-b - White River Shale Project (WRSP) (21)
Project Description
The lessees Of Tract U-a (Phillips Petroleum, Sun Oil) and U-b (Phillips,
Sun, SoBio) have proposed joint development of the two tracts, which adjoin
one another. A Detailed Development Plan for the two tracts was submitted to
the Area Oil Shale Supervisor (AOSS) in April 1976. Final DDP approval is
still pending. In late 1976 WRSP requested a temporary suspension of
operations and further lease payments on both tracts.
The project activities planned for the tracts are expected to occur in
four phases, as summarized in Table 2-4. In Phase I a 335 meter (1100 ft)
deep access shaft for a subsequent room-and-pillar mine will first be estab-
lished near the center of the combined tracts, in order to permit testing of
the shale deposft. Mining will be initiated some six months later. Mine de-
velopment will continue, and extend throughout the following Phase II, with an
expansion of production from 1814 tonnes (2000 tons) to 9100 tonnes (10,000
tons) of raw shale per day.
Phase II will be of 4 years duration, and will involve the construction
and operation of a single modular vertfcal retort with a throughput capacity
of up to 9100 tonnes of shale (10,000 tons) per day. The retort design has
not yet been selected, but could be a Paraho direct-heat design later
modified for indirect heating, or another available verticle-type retort.
At a retort feed rate of 6800 tonnes (7500 tons) of coarse shale per day,
some 750 cubic meters (4700 barrels) of crude oil would be produced daily.
A commercial plant (Phase III), with a first "train" projected capacity
of 72,500 tonnes (80,000 tons) per day, will be constructed for start-up some
2*s years after the successful conclusion of Phase II. This will be followed
by start-up of a second commercial train of the same capacity some 1% years
after the first, thus bringing total plant production capacity to an ultimate
145,000 tonnes (160,000 tons) per day.
It is currently intended that the major portion (85%) of the Phases III
and IV retorting will be carried out in vertical, gas-combustion type-, direct
and tndtrect-mode retorts, but that t&e 15% of crushing fines produced will be
pyrolyzed in TOSCO II-type retorts. It is expected that all of the 15,800
cubic meters (100,000 barrels) of shale oil produced daily at maximum scale-up
will be upgraded in facilities similar to those to be used for the Colony and
Tract C-b projects.
During Phases I and II water for the White River Shale Project will be
obtained from a 146,000 m3 (118,000 acre-ft) reservoir behind a damon the
nearby White River, to be constructed by the State of Utah and the Ute Indians.
Whin commercial production is attained (Phases III and IV) water requirements
will range from 13,000 acre-feet (16,000,000 m3) to 26,000 acre-feet
(32 000 000 m?) per^ year. These could also be obtained from the above-mentioned
multi-purpose reservoir, or alternatively, by pumping from the Green River
and Flaming Gorge Reservoirs.
53
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Table 2-4. Tracts U-a/U-b - White River Shale Project Summary (21)
MINING
Type
Production
Ore Haulage
PROCESSING
Retorting
Upgrading
PRODUCTS
Pipelineable Shale Oil
Upgraded Shale Oil
Sulfur
Ammonia
Liquid Fuels
Moisturized Processed
Shale
WATER DEMAND
POWER DEMAND
PEAK EMPLOYMENT
Construction
Operation
ELAPSED TIME
Construction
Operation
PHASE I
Open Mine
(room and pillar)
Nominal
Truck
None
None
None
None
None
None
None
None
3 megawatts
200
60
1 . 5 yrs .
1.5 yrs .
PHASE II
Development and
Operation
9,100 tonnes/day
Conveyor
Single Vertical
Module
Gas Treating
750 M3/day
None
2.1 tonnes/ day
None
None
6,550 tonnes/day
(includes fines)
870 Iiters/m1n.
13.6 megawatts
800
325
3 yrs.
2.5 yrs.
PHASE III
Commercial Production
72,500 tonnes/day
Conveyor
Gas Combustion/
TOSCO II
Hyd retreating
S, NH3 Recovery
8,000 M3/day
7,600 M3/day
75 tonnes/day
187 tonnes/day
1 ,240 M3/day
58,700 tonnes/day
17 M3/m1n.
100 megawatts
3,900
800
2 yrs.
20-30 yrs.
PHASE IV
Commercial Productloi
145,000 tonnes/day
Conveyor
Gas Combustion/
TOSCO II
Hydrotreatlng
S, NHs Recovery
16,000 M?/day
15,200 M3/day
150 tonnes/day
374 tonnes/day
2,480 M-Vday
117,400 tonnes/day
34 M3/m1n.
200 megawatts
2,000
2,050
2 yrs.
20-30 yrs.
U1
-------
At full-scale production the Project is expected to be self-sufficient
in utilities and fuel requirements. Modest quantities of shale oil initially
produced will be transported to market by truck. In the commercial phases
(III, IV) the upgraded shale oil products will probably be sent by pipeline
northeast to Casper, Wyoming, and thence by conventional trans-continental
pipeline to refiners.
Environmental Programs
During all three operating phases of the White River Project, fugitive
dusts from mining and crushing are to be controlled by the use of water sprays,
baffled settling chambers, and wet scrubbers. Wet scrubbers will also be used
for partlculate emissions control during modular and full-scale retorting.
All of the shale oil produced daily at maximum scale-up will be upgraded
in facilities similar to those used for the Colony Operation. As a result,
some 3% of the wastes disposed will be spent catalysts, sludges, and arsenic-
laden solids from TOSCO II-type shale oil upgrading units. These wastes will
be discarded with the retorted shale. Waste disposal is expected to be at
Tract U-a, in Southam Canyon, to the west of the plant area. The processed
shale pile will be built southward along the eastern half of the canyon, to-
ward the southern limits of Tract U-a. A retention dam at the northern end
of t&e canyon vrill prevent contamtnatton of the White River. The finished
processed shale disposal pile will be contoured to blend with the natural ter-
rain, and revegetated.
It ts projected that the 72,500 tonnes (80,000 tons) per day and 145,000
tonnes (160,000 tons) per day commercial operations will collectively dispose
of a total of about 1,040 million metric tons (1,150 million tons) of processed
shale and plant wastes during the 20 plus years of contemplated full-scale
production. This will result in a disposal pile in Southam Canyon of 727
million cubic meters (950 million cubic yards) volume, occupying some 366
hectares (900 acres), with an average depth of 61 meters (200 ft). A two-year
baseline environmental monitoring program is proceeding at U-a/U-b.
2.4.4 Federal In-Situ Lease Tract Nominations (35)
In April 1975, the Under Secretary of the Interior called for nomina-
tions of areas for leasing to be developed by in-situ technology. Six
tracts in Colorado and three in Utah were nominated, and a tract selection
committee (composed of state personnel and Department of Interior personnel)
recommencWtwo preferred and two alternate tracts. The preferred sites are
shown in Figures 2-1 and 2-2 as "insitu #2" (Colorado) and "in-situ #8" (Utah).
The alternate sites are "1n-situ #7," and in-situ #9," in Utah. Major
criteria for selecting the preferred sites were:
Lack of conflicting mineral leases (or absence of minerals
associated with oil shale).
Shale deposits likely to be available only or primarily by
employing 1n-situ extraction methods.
55
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Absence of ground water
t Socio-economic factors (e.g., local towns likely to be affected)
Accessibility (e.g., existing roads)
Environmental considerations
The tract selection committee submitted its recommendations to OSEAP
in September 1975. The Oil Shale Environmental Advisory Panel reviewed the
selections and recommended four sites for consideration by the Assistant
Secretary of the Interior. Final decision on which tracts to be leased
awaits preparation of an Environmental Impact Statement.
56
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REFERENCES
1. Crookston, R. B., "Mining Oil Shale," Society of Automotive Engineers
(SAE), Seattle Washington, August 11-14, 1975.
2. Cummins, A. B., and Given, I. A., "Mining Engineering Handbook," Society
of Mining Engineers of American Institute of Mining and Metallurgical
Engineers, 1973.
3. Blasters Handbook, 6th Edition, E. I. DuPont De Nemours.
4. Langefurs, U., and Kihlstrom, B., "Rock Blasting, 2nd Edition," Wiley,
1967.
5. Banks, C. E., "Data Compilation for Study of Surface Mining of Oil Shale,"
9th Oil Shale Symposium, Colorado School of Mines, Golden, Colorado,
April 29-30, 1976.
6. Detailed Development Plan, Vols. I and II, Federal Oil Shale Lease Tract
C-b, submitted to Area Oil Shale Supervisor, February 1976.
7. Detailed Development Plan, Vols. I-V, Federal Oil Shale Lease Tract C-a
(Rio Blanco Oil Shale Project), submitted to Area Oil Shale Supervisor,
March 1976.
8. McCarthy, M. E., "The Status of Occidental Oil Shale Development," 9th
Oil Shale Symposium, Colorado School of Mines, Golden, Colorado, April
29-30, 1976.
9. Hoskins, W. N., "Technical and Economic Study of Candidate Underground
Mining Systems for Deep, Thick Oil Shale Deposits," 9th Oil Shale Sympo-
sium, Colorado School of Mines, Golden, Colorado, April 29-30, 1976.
10. Russell, P. L., "Bureau of Mines Oil Shale Reserach," 9th Oil Shale
Symposium, Colorado School of Mines, Golden, Colorado, April 29-30, 1976.
11. Stone, R. B., "Technical and Economic Study of an Underground Mining,
Rubblization and In Situ Retorting System for Deep Oil Shale Deposits,"
9th Oil Shale Symposium, Colorado School of Mines, Golden, Colorado,
April 29-30, 1976.
12. Colony Development Operation, Draft Environmental Impact Statement (EIS),
U.S. Department of the Interior, Bureau of Land Management, December, 1975.
13. Colony Development Operation, An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Part I, 1974.
14. Prien, C. H., "Current Oil Shale Technology: A Summary," in Guide Book
to the Energy Resources of the Piceance Creek Basin Colorado. Rocky
Mountain Association of Geologists, 25th Field Conference, 1974.
57
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15. Whitcombe, J. A. and Vawter, G. R., "The TOSCO II Oil Shale Process,"
Science and Technology of Oil Shale, Ann Arbor Science Publishers, 1976.
16. Cameron Engineers, Synthetic Fuels Quarterly, March 1976, p. B-4.
17. Sladek, T. A., "Recent Trends in Oil Shale - Part 2: Mining and Shale
Oil Extraction Processes," Mineral Industries Bulletin, Colorado School
of Mines, Vol. 18, No. 1, January 1975.
18. Jones, J. B., "The Paraho Oil Shale Retort," 9th Oil Shale Symposium,
Colorado School of Mines, Golden Colorado, April 29-30, 1976.
19. McKee, J. M. and Kunchal, S. K., "Energy and Water Requirements for an
Oil Shale Plant Based on the Paraho Process," 9th Oil Shale Symposium,
Colorado School of Mines, April 29-30, 1976.
20. Op. Cit., 7, Vol. I.
21. Detailed Development Plan, Federal Oil Shale Lease Tracts Ua and Ub
(White River Shale Project), submitted to Area Oil Shale Supervisor,
June 1975.
22. Cameron Lngineers, Synthetic Fuels Quarterly, September 1974.
23. Union Oil Company, data and information provided to TRW in response to
technical inquiries, 1975.
24. Superior Oil Company, Application for Consolidating Oil Shale Lands by
Acreage Exchange #C-19958, Bureau of Land Management, U.S. Department
of the Interior, Denver, Colorado.
25. Weichman, B., "Superior Process for the Development of Oil Shale and
Associated Minerals," 7th Oil Shale Symposium, Colorado School of Mines,
Golden, Colorado, April 18-19, 1974.
26. Schmalfeld, P., "The Use of the Lurgi-Ruhrgas Process for the Distilla-
tion of Oil Shale," Quarterly of the Colorado School of Mines, Vol. 70
(3), July 1975.
27. Lurgi Mineraloltechinek (GMBH), "Development of the Lurgi-Ruhrgas Retort
for the Distillation of Oil Shale," Frankfort (Main), October 1973.
28. Chemical Engineering. December 8, 1975, p. 81.
29. Cameron Engineers, Synthetic Fuels Quarterly. June 1974.
30. McCarthy, H. E., and Cha, C. Y., "Development of the modified in situ
Oil Shale Process," 68th AIChE Annual Meeting, Los Angeles, California
November 16-20, 1975.
31. Ridley, R. D., Testimony on H.R. 9693 "Shale Oil Development Corporation
Act," Subcommittee on Energy, Committee on Science and Astronautics,
House of Representatives, Washington, D.C., May 14, 1974.
58
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32. Cameron Engineers, Synthetic Fuels Quarterly, June 1975.
33. Final Environmental Impact Statement for the Prototype Oil Shale Leasing
Program, Vol. I, Regional Impacts of Oil Shale Development, U.S. Depart-
ment of the Interior.
34. Ash, H. 0., "Federal Oil Shale Leasing and Administration," op.cit. 14.
35. Report by the Interagency In Situ Oil Shale Trace Selection Committee
to the Assistant Secretary of the Interior, Lands and Water Resources,
September 5, 1975.
36. Hopkins, J. M. et.al., "Development of Union Oil Company Upflow Retorting
Technology," 81st National Meeting of the American Institute of Chemical
Engineers, Kansas City, Missouri, April 11-14, 1976.
59
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3.0 THE NATURE AND SOURCES OF EMISSIONS, EFFLUENTS AND SOLID WASTES FROM
SHALE OIL OPERATIONS
The oil shale technologies and development activities reviewed in Chapter
2.0 are likely to be the major contributors to commercial shale oil
production in the near future. Each technology and activity will have asso-
ciated with it certain waste streams and environmental problems. Thus Chapter 3
is a discussion of characteristics of the major technologies which influence
the composition, properties, and quantities of wastes which may be generated
during future commercial operations. The approximate inventories of waste
quantities are presented where information 1s available. Where appropriate,
a brief discussion of planned pollution control practices 1s Included.
Section 3.1 1s a review of the types, sources, and Inventories of
atmospheric emissions. Section 3.2 is a review of process water requirements,
wastewater characteristics, and wastewater treatment alternatives. Section
3.3 includes a discussion of some important characteristics of raw and retort-
ed shales, an identification of non-shale solid wastes, and a summary of the
approximate quantities of such wastes which would be associated with major
development activi ties.
3.1 ATMOSPHERIC EMISSIONS
Atmospheric emissions can arise from several activities or operations
during oil shale processing. A breakdown of the more important sources of
emissions is presented in Table 3-1. The major source of S02, NOX, and CO
is fuel combustion for process heat; S02 is also emitted in the tail gases
of sulfur recovery operations. The use of fuel oils in mobile equipment and
in explosives will result in emissions of CO and NOX. Hydrocarbons are pre-
sent in both combustion emissions and in product storage tank vapors. Emis-
sions of particulate matter can result from 1) blasting, 2) raw and spent
shale handling and disposal, 3) raw and spent shale dust in process gas
streams, 4) fuel combustion, and 5) site activities which generate fugitive
dust.*
Emissions of potentially hazardous substances may occur during the
extraction and processing of oil shale. Silica (quartz) may be present
in dust derived from oil shale and associated rocks and in fugitive dust.
Particulate emissions from fuel combustion and fugitive dust from spent shale
handling and disposal can contain polycyclic organic material (POM) and cer-
tain trace metals. Gaseous ammonia, hydrogen sulflde, and volatile organ1cs
may be released during moisturizing and subsequent cooling of retorted shale.
*Fugitive Dust refers to particulate matter which is discharged to the atmo-
sphere in an unconfined flow stream, generally as a result of mechanical
disturbance of granular material exposed to air.
60
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Table 3-1. The Sources and Nature of Atmospheric Emissions
from 011 Shale Extraction and Processing
Subprocess
0 Oil Shale
Extraction
Raw Shale
Transport
Preparation
Retorting
Operations
Upgrading
and Utility
Operations
Gas Cleaning
Systems
e Product
Storage
Solid Waste
Disposal
Emission Generating Activity
Blasting
Nine equipment use
Fuel use
Fugitives
Equipment use
Tuel us'e
Fugitives
Crushing
Screening
Ore Siprage
Shale Preheat
Fuel use
Shale dusts
Heat Carrier Reheating
Fuel use
Combustion of shale
organic material
Spent Shale Discharge
Moisturizing or dry exit
Process heaters/furnaces
Fuel use
Sulfur recovery and tall gas
cleanup
Hydrogen production
C02 removal
Fuel use
Tank evaporation
Equipment use
Fugitives
Spent snaie transport
and spreading
Coke, spent catalyst.
other wastes - transport
and spreading
Potential
Criteria Pollutants
PM*(1)
dust*(D. CO, NOX, HC
PM*(2). CO. NOX. S02. HC
dust*(1)
PM*(2). CO. NOX. S02. HC
dust*(1)
PM*(1)
PH*{1,2), CO. NOX. S02, HC
HC's Z
PM*(2). CO, MOX. S02. HC
PM*(2). CO, NOX. S02. HC
PM*{3). HC's
PH*(1), CO. NOX, S02. HC
so2
soz
PH*(2). CO, MOX. HC. S02
HC'S
PH*(2). CO, NOX, S02, HC
PH*(3)
PM*(O
Potential
Non-Criteria Pollutants
Kg. Pb salts, silica
silica
silica
silica
trace elements
trace elements, trace
organ Ics
trace elements, trace
organlcs
H2S, NH3, volatile and
trace organlcs
cs2. cos
COS
trace organlcs
metals (N1, Cr. Fe. Ho).
trace organlcs
Suspended particulate matter Is the defined criteria pollutants:
PH 1s broken down Into 3 general categories In this table.
(1) Raw shale and natural soil dusts
(2) Fuel combustion ash and sooty material
(3) Spent shale dust (Including dust from other solid wastes)
61
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Catalyst materials may release participate tter containing trace metals to
the atmosphere during regeneration, handling, or final disposal.
Section 3.1.1 below is a comparison of TOSCO II, Paraho, and Union B
retorting processes for potential emissions of criteria and hazardous pollu-
tants. Section 3.1.2 reviews shale preparation, retorting, and upgrading
emissions inventories or estimates which have been prepared for oil shale
developments. Section 3.1.3 presents an estimate of fugitive dust emissions
associated with the extraction of oil shale.
3.1.1 A Comparison of Retorting Processes for Potential Emissions
Potentially commercial surface retorting technologies fall into three
classes:
Class Examples
(1) Externally heated recycle solids retorts TOSCO II
(2) Gas combustion retorts (GCR) Paraho Direct Mode
(3) Externally heated recycle gas retorts Union B, Paraho Indirect
Mode
Generally, the retorting operation itself does not involve atmospheric
emissions; gaseous, liquid, and solid streams leaving the retort are handled
by downstream systems before reaching an atmospheric interface. However,
certain features inherent in the retorting method influence the nature and
magnitude of emissions from other sources in the associated shale oil plant.
The discussion below focuses on TOSCO II, Paraho, and Union B technologies
with emphasis on process stream composition and quantities. Differences
in potential emissions for criteria pollutants (SOg, NOX, particulates, CO,
and hydrocarbons) and hazardous substances (polycyclic organic material and
trace elements) are discussed.
It should be cautioned that a comparison of processes for potential
emissions (and other wastes)-should consider similar sized operations, and
appropriate control technologies applied to waste streams. Since processes
such as TOSCO II are more advanced and more information is presently avail-
able for such processes, waste streams are more well defined than those asso-
ciated with less developed processes. Conclusions reached in this section
are not intended to endorse or condemn a given process, but rather to high-
light process features.
Sulfur Compounds: Sulfur in raw oil shale amounts to about 0.7% by
weight, approximately 1/3 associated with the organic fraction; and 2/3 as
pyrite (Fe2S) (1). During kerogen pyrolysis, about 40% of the organic sulfur
in shale appears as t^S in the produced gases, and the other 60% as heavier
sulfur compounds in raw shale oil and in the spent shale carbonaceous residue.
Pyritic shale sulfur does not decompose under non-oxidizing retorting
conditions.
62
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JV retort produces about 187 M3 of net gas along with each cubic
iL I S^de,n5alL01-i(1S40^Foper BBLK2,3). The gas contains about 3-5
volume % H2S, and the oil about 0.9 weight % total sulfur. The sulfur is
partially removed from both oil and gas before in-plant use or sale Conse-
quently, S02 emissions from plant fuel use depend upon both the fuel mix and
£hejJfi£e!i ?f su]Jur removal from gas and liquid products. Finally, SO? can
be emitted in sulfur recovery plant tail gases, or in tail gases from
subsequent cleanup operations.
A gas combustion retort (GCR) produces a significantly larger
(~2000 MW) (10,900 SCF/BBL) than a TOSCO II re-
volume
of gas per volume of oil (*
tort (4,5). Sulfur in such retort gases amounts to about O.U by volume
(almost entirely as H2S). The smaller total quantity of sulfur in GCR re-
tort gas compared to TOSCO II gas may partially reflect the higher grade
of raw shale (and associated higher sulfur content) which has been used in
the TOSCO II retort than in the GCR retort. Also, the more rapid pyrolysis
of kerogen and the shorter residence time of organic vapors at retorting
temperatures in the TOSCO II retort may result in more complete conversion
of organic sulfur to H2S. Table 3-2 shows a comparison of total sulfur in
TOSCO II and GCR retort gases.
Table 3-2. Comparison of Total Sulfur in Raw Retort Gases (2,3,5,6)
Process
TOSCO II
GCR (direct
mode Paraho)
Vni.imp M3 gas
Produced M3 oil
187
2000
Sulfur in Gas
(Vol %)
3-5
0.1 - 0.2
Weight Sulfur (Kg) in
Gas per M3 of Oil
8-14
3 - 6
In the combustion zone of a GCR, organic sulfur and pyrite are burned
along with the carbonaceous residue of retorted shale. The oxides of sulfur
are apparently captured by the alkaline oxide/carbonate minerals remaining
in the shale* and are discharged from the retort as sulfite or sulfate salts
with burned shale (7,9).
Externally heated recycle gas retorts (i.e., Union B) produce net gas
of composition similar to TOSCO II gas. Sulfur content of raw shale oil and
of the carbon residue associated with spent shale are also comparable (10,11).
Actual S02 emissions associated with individual retorting processes will
depend upon the degree of sulfur removal accomplished for in-plant fuels,
the extent of on-site shale oil processing, and the degree of control applied
to sulfur recovery tail gases.
Oxides of Nitrogen: Combustion of any hydrocarbon fuel will produce
oxides of nitrogen when air containing elemental nitrogen is used as the
oxygen supply. The extent of NOX formation from oxygen and nitrogen in air
during combustion is related primarily to flame temperature, residence time,
and air/fuel mixture. In addition, organic nitrogen contained in fuel can
63
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be partially oxidized to NO and N02, depending on the above variables and
the level of fuel nitrogen. Generally, gaseous fuels tend to emit lower
quantities of NOX than liquid or solid fuels, given comparable combustion
conditions and fuel nitrogen levels (13).
Most retorting processes require heat supplied by combustion of retort
gases, shale oil, or carbonaceous residue remaining after pyrolysis of shale
organic material. Nitrogen in raw oil shale exists as a chemically bound
component of the kerogen matrix (1). In TOSCO II retorting about 35% of the
original shale nitrogen in shale appears as the sum of ammonia in retort
gases and organic nitrogen in crude shale oil. The remaining 65% is found
in the retorted shale (with carbonaceous residue) (2). Combustion of raw
gas, crude shale oil, or the spent shale carbonaceous residue may result in
a partial conversion of the bound N to NOX.
In the GCR process the residual carbonaceous material associated with
"retorted" shale is burned internally in the retort. The recycle gas is
known to contain some ammonia but very little NOX (5,6). Mass balance calcula-
tions suggest that the organic nitrogen entering the combustion zone of the
GCR is partially converted to elemental nitrogen. However, total ammonia 1n
GCR retort gas and total nitrogen in GCR product oil per ton of Input shale
1s about the same as the totals in TOSCO II gas and oil..
A TOSCO II plant may present a larger NOX emissions potential than a
GCR plant, depending on the quantity and nitrogen level of shale-derived
oil which must be used to supplement gas for process heat. Net TOSCO II
gas is likely to be of sufficient quantity to supply retorting process heat,
but not to supply both retorting and on-site upgrading heat requirements,
and feedstock for hydrogen production (2,3). A GCR retort, on the other hand,
produces a large excess of low Btu gas over retorting heat requirements,
and such gas is available for supplying heat for upgrading processes (it is
doubtful, however, that GCR gas could be economically used as a feedstock
for hydrogen production) (14).
Particulate Matter (2,3,7,9): Generally, processes which require small
sized shale feed (e.g., TOSCO II) will have more uncontrolled particulate
emissions during crushing and raw shale handling operations than processes
which require large feed (GCR-Paraho). Also, the presence of small raw and
retorted shale particles in preheat and elutriator systems of a TOSCO II
plant_result in a greater particulate emissions control requirement than.
would be the case with a similar sized GCR retort. Particulates result-
ing directly from fuel combustion for in-plant purposes are mainly a function
of fuel mix; the GCR retort will produce an excess of fuel gas, a TOSCO II
operation may have to burn some product oil for process purposes. Moisturiz-
ing of retorted TOSCO II shale may require greater particulate emissions
control than moisturizing the larger sized GCR retorted shale.
The feed to a retorting plant always presents a particulate control pro-
blem. Run-of-Mine raw shale commonly contains about five weight percent
of ore of less than 12.7 mm (1/2 inch) size. A sizable percentage of this
segment will become minuslOOy particulate as a result of primary crushing.
64
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^ PPD "n0"5 ^ PreS6nt m°re °f
nn« of ho f Sc ₯?lon process' °re stora9e and handling and dis-
posal of the fine TOSCO II retorted shale are potential fugitive sources.
dSSEn rSSl! r"6- ^ GC5 a?d Un1on will require proper handing and
disposal in order to minimize fugitive emissions.
Site use activities which may generate fugitive dust are generally not
process specific. The use of open pit vs. underground mining will be the
largest factor determining total fugitive emissions associated with the ex-
traction of oil shale (15).
Hydrocarbons (HC's) and Carbon Monoxide (CO): Emissions of HC's and CO
occur curing incomplete combustion of fuels in process heaters and in mobile
equipment. Hydrocarbons may also be vaporized during product storage. Equip-
ment use and evaporative hydrocarbon emissions are not expected to be process
specific.
The TOSCO II retort may present a somewhat greater hydrocarbon emissions
control requirement than direct mode Paraho or Union retorting since pre-
heated TOSCO flue gases contain fresh kerogen derived vapors. Incineration
of these gases can reduce hydrocarbon concentrations to less than 90 PPM (3).
There may be other hydrocarbon sources in Union or 6CR retorting that have not
been quantified.
The largest source of CO in an oil shale operation is mobile equipment
used for mining and transport (3,7). The quantity of such emissions is a
function of mining method and haul distances rather than retorting process.
Polycyclic Organic Matter (POM)*: The pyrolysis of essentially any
type of organic material produces a certain amount of POM, and oil shale
kerogen is no exception (17). Generally, POM compounds have a low volatility
and will be associated with high boiling liquid or solid products, or parti-
culate matter.
Although POM is known to be present in carbonaceous retorted shales, the
biological availability and potential hazard of such material is not accu-
rately known at present. (See Section 3.3)
Release of POM to the atmosphere during oil shale processing can occur
via three major pathways:
(1) Handling and disposal of retorted shale - fugitive particulates
and possible volatilization of hydrocarbons.
(2) Combustion of shale derived oils containing POM.
(3) Flue gases containing entrained retorted shale particulates,
along with retort gas or spent shale coke combustion products.
*POM includes polycyclic aromatic hydrocarbons, their nitrogen and sulfur
heterocyclic analogues, and their oxidized derivatives.
65
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TOSCO II retorted shale is very fine and contains 4-5% carbonaceous
residue. Fugitive emissions may occur during disposal of such shale, and the
small sized suspended particles are those most likely to penetrate into and
be retained by the lung. TOSCO II preheat system and elutriator system flue
gases may contain suspended raw and spent shale particles of very small size
even after controls. The use of product oil to supply process heat may con-
tribute to POM emissions.
Union B spent shale is chemically similar to TOSCO II spent shale, but
may present less of POM emissions potential during handling and disposal due
to the much larger average particle size.
GCR retorting involves the combustion of residual shale carbonaceous
material internally, and little organic matter or carbon remains with the
retorted shale(s). Consequently, POM is found in much lower amounts in GCR
retorted shale than in TOSCO II retorted shale (16). Further, GCR retorted
shale consists of pebble sized solids, and is likely to present a low fugi-
tive emissions potential.
Trace Elements: Green River oil shale contains trace amounts of many
elements. However, for elements other than Si, Fe, Al, Ca, Mg, Na, and K,
the concentrations in oil shale are less than or comparable to those found
in common sedimentary and igneous rocks (18). In contrast, petroleum and coal
contain greater quantities of metals and other trace elements than common
rocks.
Temperatures and redox conditions during retorting are not severe enough
to volatilize most metalic and heavy elements. With notable exceptions such
as arsenic (As) and possibly antimony (Sb), most trace elements (e.g., nickel
(Ni), vanadium (V), Molybdenum (Mo)) remain with the spent sha'le, or are
found as components of raw and spent shale solids entrained in retort gases
and in raw shale oil. Arsenic in raw shale apparently forms a range of
volatiles, oil soluble compounds (perhaps organic arsines) during retorting,
and appears in raw shale oil and all condensible oil fractions (19). If not
removed during upgrading, arsenic will be present in shale oil combustion
products.
Actual emissions of non-volatile trace elements will be in approximate
proportion to raw and retorted shale particulate emissions for an oil shale
extraction and retorting operation. SucEL emissions may not be different in
nature or magnitude from those associated with the extraction and processing
of other fuel and non-fuel minerals (coal, limestone, phosphate rock, etc.).
Further, the dolomitic and/or alkaline nature of shale immobilizes many ele-
ments as relatively inert oxide, carbonate, or silicate salts. Trace element
mass emission rates give no simple indication of bioavailability, chemical re-
activity, or physical properties.
Metals and their compounds are used as catalysts (Ni, Co, Mo, Cr, Fe,
Zn) for hydrotreating, dearsentating, sulfur recovery, and trace sulfur re-
moval (2,3,7,8). Emissions of particulate matter containing catalyst metals
can occur either during on-site regeneration or during handling and disposal.
Catalyst use is, of course, not unique to shale oil processing, and much
6fi
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information and experience in preventing hazardous emissions can be borrowed
from the petroleum and related industries.
3.1.2 Process Emissions Inventories
Quantitative and semi-quantitative emissions information is available for
several oil shale technologies and developments. Emissions from process sour-
ces are generally known with more certainty than emissions from mobile equipment.
use, blasting, and fugitive sources. Process inventories for the Colony Develop-
ment operation and lease tracts C-a, C-b, and U-a/U-b are presented and dis-
cussed below. Less complete estimates of emissions are presented for the
Union and Occidental processes.
Colony Development Operation - TOSCO II: The basic information about
TOSCO II emissions is contained in the Colony Development Operation EIA (1973)
(2) and more recently in the Department of Interior's EIS for Colony (1975)
(3). Other versions of TOSCO II emissions can be found in SRI (1974) (9) and
FEA (1975) (15), although these are based upon data in the Colony EIA. More
recently, detailed development plans (DDP's) for federal lease tracts Ca and
Cb have presented TOSCO II emissions estimates (7,8). The DDP's have relied
heavily upon Colony data similar to that found in the 1975 EIS (3).
Table 3-3 presents four versions of an emissions inventory for TOSCO II
retorting and on site upgrading of shale oil. The first three are based upon
Colony EIA data. Plant emissions result mainly from fuel combustion, with the
preheat system being the largest single source. Colony had assumed a plant
fuel mix consisting of about 50% fuel gas, 21% butane fuel, and 29% fuel oil
(2). S02 and NOX emissions reflect the sulfur and nitrogen content of fuels,
especially the fuel oil. Particulate emissions arise in flue gases both from
combustion processes and from the entrainment of raw and spent shale dust.
Also, large quantities of particulates are generated during ore preparation.
Colony has revised the TOSCO II emissions inventory in the 1975 EIS (the
fourth inventory in Table 3-3). Total S02 emissions are dramatically reduced,
reflecting greater sulfur removal plans for in-plant fuels. Some modification
of the original fuel mix may also be involved, but Colony has not revealed
the assumed fuel schedule (or fuel sulfur contents). Total NOX emissions are
also lower in Colony's EIS emissions inventory. It is not known whether
greater nitrogen removal from fuels or greater combustion control is respon-
sible for the NOX reductions. Total process particulate emissions are about
the same in the 1973 inventory.
Colony has indicated that Claus sulfur plant tail gas is to be handled
by a Wellman-Lord unit for S02 removal. S02 emissions from the sulfur recov-
ery operation are larger in the 1975 inventory than in the EIA inventory,
mainly reflecting an increased H?S load on the Claus plant from more exten-
sive sulfur removal from shale oil products.
Colony has estimated emissions resulting from mobile equipment use in
underground mining, and dust generated during blasting operations. Total
carbon monoxide emissions from the mine are much larger than from in-plant
67
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operations. NOv and particulate emissions from the mine constitute around
10* of the total for their respective inventories.
Tract C-b Inventory (8): The developers of tract C-b (Shell and Ashland)
are partners in the Colony group, and propose to use TOSCO II technology at
the tract. The emissions inventory reported in the recent DDP for tract Cb
is essentially identical to that presented in the Colony 1975 EIS and shown
in Table 3-3.
Tract C-a Inventory (7): The leasees of tract C-a intend to use TOSCO II
retorting for 2/3 of the mined shale and GCR '(Paraho) retorting for the other
1/3 during Phase II operations. Table 3-4 presents the emissions inventory
for C-a phase II operation (8900 M3/day, 56,000 BBLS/day) as described in the
recent detailed development plan. The emissions directly associated with
GCR retorting are those from the shale preheating furnace and from spent
shale moisturizing.
The integrated TOSCO/GCR retorting system for Tract C-a differs in
several ways from the Colony (TOSCO) system:
GCR product gas is used to preheat shale for the TOSCO II
retort - the integrated system uses entirely gaseous fuels.
Hydrogen for upgrading is produced by partial oxidation of
the 480°C+ (900°F+) shale oil distillate bottoms rather
than by the reforming Light hydrocarbons. Process energy
(and associated emissions) for this operation is supplied
by auxiliary boilers.
A lower average grade of shale (.095 M3/tonne or 23 gal/ton)
is extracted and processed. Total shale preparation emis-
sions for the 8900 M3/day operation are therefore higher
than for the Colony operation (using .146 M3/tonne or 35
gal/ton shale).
The overall shale preparation and processing emissions associated with
the tract C-a operation are comparable to Colony EIS emissions for S02.
Total NOX and particulate emissions are lower, reflecting use of low nitrogen
plant fuels, better combustion control, and more efficient particulate col-
lection systems.
Tracts U-a/U-b (23): The White River oil shale project plans to develop
tracts U-a/U-b probably using primarily Paraho type technology. Fines are to be
handled using TOSCO II technology in later phases of tract development.
Table 3-5 presents an emissions inventory for Phase III operations (8000 m3/
day or 50,000 bbls/day). Total NO emissions are comparable to those for
similar sized operations at C-a ana C-b. Total particulate, SOg, THC, and
CO emissions differ somewhat from those associated with other developments
for several reasons including: (1) the inclusion of mining, mobile equipment,
and fugitive dust emissions in the U-a/U-b inventory, (2) a combination of
68
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Table 3-3. Comparison/of TOSCO II Emissions Inventories (8000 m3/day) (50,000 bbls/day)
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MO'O 5WO IM'O «0'0 SOO'O B'C
two 600-0 ;:;-o IM-O ico'o *'»
ico-o ssc-z coo-o «r; tn-i >'<
ȣS'0 Wl IZfl KfN SSS'O til
0) Md )U *ON 2QJ IVO/IVXIgOt
(i«o/n>Mi) ea\mta in«i IVJH
U|4oc v imi 'r^iS" uow]
II i "ON 'os ivo/TO'eOi
(*ya/53v»i) :>.-oi5siH] inai iviu
.fj.VU HI jmiJS OI.'ISJMilN]
WOICUHHJ lOJlUO) l|qf||»f 1M3.
tS'» ft Z'ZZ 9/1
,{/l'l '-"
5»l'0
wo
uro
t:t t c'0 '5
08»'0 5S> 1 ^Z'O '8
JBrZ tlt't 5WZI IM'll 211-
N90'0 5'*
«oo'o 600-0 - tiro two '*
8IO'0 eiO'O - SIB'O I6>'0 t'S
HO'O 819-J - S»Z'l «Z'0 ' '»
Mfo eofi c«l
(IUO|fl|M >UMd|Kb*
lltou) »»A X>tM
[fioi 4*14 «jo
«6uo>s «JO w|j
tKiiuinjj [i^ij
JJ>IU1J1 |«UU11 (IIIMII
J»(»u.Jl U|9 pxj
IfUM JIJIUMI
J»giruj wo KJtO]
l»oi <>noJ^
lu«|j jnjinj
U«||Ct
-------
Table 3-4. Lease Tract C-a Phase II Emissions Inventory (56,000 bbls/day)
(1)
HEAT INPUT
SOURCE \Q« KCAL/DA
Preheat
Elutrlator
Systems
Coker Heater
(vent)
Gas Oil Heater
Gas Oil Furnace
Naphtha Heater
\\2 Production
Aux Boilers
Sulfur Plant
TOSCO Shale
Moisture
Glycol Reboller
(Hi-Gas Plant)
H-Plant CO?
GCR* Preheat
GCR Moisture
Process Total
Ore Prep
Storage
Total
134
7.4
3.7
7.0
6.4
1.9
-
39.5
0
0
5.8
0
5.4
0
211
211
RETORTING/UPGRADING
Y S0?
2.364
0.364
o!o33<4
0.021
0.020
0.005
0
0.072
0.436
0
0.017
0.104
0.015
0
3.427
-
3.427
EMISSIONS
_NOx
6.336
1.345
. 0.209
)
0.400
0.373
0.109
0
1.418
0
0
0.327
0
0.309
0
10.827
-
10.827
(TONNES/DAY)
THC PART.
3.127
0.372
0.020
0.037
0.034
0.010
0
0.131
0
0
0.031
0
0.028
0
3.791
-
0.146
3.937
2.600
1.455
0.013
0.024
0.023
0.006
0
0.131
0
0.764
0.021
0
0.018
0.007
5.064
1.255
-
6.319
Max 15 mln/day
Ref. 7 at end of Chapter 3.
MINE/CRUSHERS ^2)
PARTICULATES
SOURCE (TONNES/DAY)
Primary Crush 0.130
Secondary Stock- 0.218
pile
Primary Ore 0.142
Reclaim
Secondary Crush 0.647
Fine Ore Storage 0.125
Total 1.255
^Based on 2/3 TOSCO .
1 1/3 GCR
I 109,090 tonnes/day ]
mined
TANK STORAGE
PRODUCT
Naphtha
Gas Oil
Diesel
Raw Shale 011
Resld
Raw Napfcha
Raw Gas 011
Sponge Oil
H-plant Feed
Coker Tank
Total
i THC'SVJ'
(TONNES/DAY)
0.044
0.021
.001
.001
.001
.033
.022
0.021
Tank .001
.001
0.146
(3)
Assumes evaporative
component at all stored
products to have a
specific gravity of
0.84 (60°/60°F) or 7 IDS/
gallons
-------
Table 3-5. Lease Tracts U-a/U-b Emissions Inventory (50,000 bbls/day) (23)
Heat Input
Source 108KCAL/Day
Piriho Tjfjje Retorts
Raw Shale Feed
e Retorted Shale
Moisturizing
Gas Heaters 12
TOSCO II Type Retorts
e Raw Shale Feed 0
e Preheat 22.8
e ElutHator 3.9
SvStCK
e Shale Moisturizer 0
Hydrogen Plant 44.1
Crude Shale Oil
Hydrotreater 11.9
Naphtha Hydrotreater 1.7
Utility Boilers
Low BTU Gas 76.7
Fuel Oil 45.3
Sulfur Plant
Process Total 21B
Tonnes/Day
SOz NOX THC Part CO
0
0
.087
0
.015
.0028
0
.286
.074
.0125
.558
.284
0.3
1.6
0
0
.436
0
1.18
.142
0
2.45
.434
.063
2.78
2.27
..
9.76
0
0
.006
0
.089
.0024
0
0.17
.006
--
.042
.170
..
0.485
.031
.025
.039
.01
.409
.034
.009
.573
0.16
.006
0.25
0.367
..
2.11
0
0
.037
0
.118
.012
0
.227
.036
.006
.237
.227
--
0.90
Source
Mining Operations
Nine Fugitive Cost
Blasting
Mobile Equipment
Mine Total
e Coarse Ore Crusher
Ore Transfer
e Storage
Secondary Crusher
Ore Prep Total
Tank Storage
Processed Shale Disposal
e Transfer
Traffic Dust
Mind Erosion
Disposal Total
Heat Input
IQttKCAL/Day
0.72
4.55
5.27
..
2.62
so?
.004
.004
Tonnes/Day
NO, THC Part CO
0.727
2.81
3.537
1.62
Ma
.018
.018
.114
ni
.01
OKI
.013
.0275
.142
.183
.183
.018
.025
.109
.335
0.147
1.58
0.50
0/1A9
2.309
4 93
0.727
.055
.782
mp
.032
1 71
-------
Direct and Indirect Mode Paraho retorting, and TOSCO II retorting, (3) hydro-
treating of crude shale oil, and (4) the use of fuel oil in utility boilers.
A detailed comparison of emission source contributions to the total inventor-
ies for U-a/U-b, C-a, and C-b has not been undertaken for the preparation of
this report.
Union B Process (20): A complete emissions inventory for the Union B
process is not available at present. However, company personnel indicate that
three major emissions sources will be present in the first generation Union B
plant at the Parachute Creek site: (1) flue gas from the recycle gas heater,
(2) sulfur plant tail gas, and (3) flue gas from the arsenic removal preheater.
A normalized emissions inventory for a Union B plant cannot be directly com-
pared to an inventory from Colony or C-a, since Union does not envision on-site
upgrading during initial operation.
Net product gas from the Union retort is expected to be similar in com-
position and heat value to TOSCO II retort gas. After sulfur removal, Union
reports the following emissions from combustion of this gas:
Table 3-6. Union B Fuel Gas Combustion Emissions (20)
Plant Size
M3 oil /day
(BBLS/day)
1260 (7920)
8000 (50,000)
Gas Firing Rate
M3/day
(ft3/day)
1.9x105 (67x1 05)
12.2x105 (430x105)
S02 Emissions
tonnes/dav
(tons/day)
0.33 (0.36)
2.08 (2.29)
NOX Emissions
tonnes/day
(tons/day)
1.0 (1.1)
6.2 (6.8)
A Stretford unit will be used to remove H£S from Union retort gases.
Off gas from the Stretford Unit will contain small amounts of sulfur com-
pounds (C$2, COS, HoS). Union has not disclosed its estimate of such emis-
sions, but the quantity is likely to be small relative to fuel gas combus-
tion emissions.
A small quantity of fuel gas is to be used in a heater in Union's
arsenic removal process. The amount of fuel used (and emissions) is con-
sidered a proprietary part of the process.
The Union B process features spent shale moisturizing and discharge
from the retort via a water seal. Particulates associated with shale
moisturizing are collected in this process with the condensed steam.
The Union B retort accepts a somewhat smaller sized raw shale as feed
than a GCR retort. The quantity of uncontrolled particulate emissions from
shale preparation might be expected to be somewhere between that from a
comparably sized GCR and a TOSCO II operation.
Superior Process: The Superior process combines certain features of gas
combustion retorting (Paraho Direct Mode) and inert gas retorting (Paraho
72
-------
Indirect Mode). On-site use of low and high Btu gas for process and upgrad-
ing purposes will result in emission control requirements similar to those
for Paraho retorts. Superior has not developed its process to the point of
being able to define such emissions to date.
Occidental (In-situ): A modified in-situ operation and associated sur-
face plant would be expected to product uncontrolled emissions similar to
above ground retorting processes. Mining is required and the associated
mobile equipment emissions and dust emissions would be similar to those
associated with the mining for above ground retorting (on a unit mined
shale basis).
Since the in-situ retort is operated in a gas combustion mode, large
quantities of low Btu gas (700 Kcal/M3 or 80 Btu/SCF) are commonly produced
during in-situ retorting (22). Occidental reports that such gas contains
around 0.6% total sulfur and some ammonia (21). The economic practicability
of removing hydrogen sulfide from the retort off-gas prior to combustion,
especially if electric power generation with the low-Btu gas proves to be
feasible, remains to be ascertained. In a previous study for the Federal
Energy Administration conducted by TRW (15), the Quantity of vent gas released
to the atmosphere was estimated to be 625 M3/Sec (1,400,000 ft3/min) for a
5860 M3/day (36,800 BBLS/day) in-situ operation retorting .08 M3/tonne (18 gal/
ton) shale. This is equivalent to a stack gas emission rate of 839 M3/sec
(1,777,000 actual ft3/min) at 95QC (2000F), and comparable in magnitude and
composition with the stack gas emitted from a 500 MW oil-fired electric power
plant.
In-situ produced wastewaters will likely contain NH3 and H2S, which
could be released to the atmosphere if such waters were to be disposed of
by evaporation (i.e., in surface ponds).
If product upgrading is performed on site, emissions will be associated
with such processing. However, Occidental does not envision upgrading at
present. A quantitative estimate of emissions associated with the Occidental
process will have to await the design of surface plant for handling product
oil, gas, and wastewaters. Occidental has filed certain emissions data with
the State of Colorado, but this data is not currently public information.
Summary of Air Pollution Control Technology: Table 3-7 presents the
major sources of $03, particulate, NOX, hydrocarbons, and carbon monoxide
from the preparation and processing of oil shale to upgraded shale oil pro-
ducts. The major proposed air pollution control equipment and/or techniques
to reduce these emissions are listed in the table, along with some comments
about the emissions inventories which have been presented and discussed above.
3.1.3 Fugitive Emissions Inventories
Table 3-8 presents one estimate of fugitive emissions associated with
oil shale operations. Uncontrolled fugitive particulates could constitute
a large fraction of a total parttculate inventory at a development site.
Shale preparation and process partfculate emissions for a 8000 MJ (50,000 bbls)
per day) plant are about 5 to 10 tonnes/day (Tables 3-3 and 3-4), while
73
-------
Table 3-7. Summary of Air Pollution Control Technology for Oil Shale
Preparation and Retorting, and Shale Oil Upgrading
Pollutant
Control
Technology
Comnents About Emissions Inventories
SO, (and total sulfur)
Gas
011
Fuel Desulfurlzatlon
An1ne/amon1a/H20 scrubbing
Stretford sulfur removal/recovery
fClaus sulfur removal/recovery
Sulfur plant tall gas cleanup -
Wei loan Lord
Hydrotreatlng followed by off-gas
HS and annonla removal
Differences In S02 Inventories reflect:
Fuel mix
t Degree of hydrotreatlng
Efficiency of S removal from fuel gas
Sulfur plant tall gas cleanup
Recent Colony and CB Inventories assume cleaner
fuels than earlier Colony and SRI Inventories.
Ca and Union Inventories based on entirely gaseous
plant fuels.
Participates
Retort Feed
Preparation
Retorting/oil
Recovery
Upgrading
, Shale Moisturizing
Covered conveyors
Water spray at transfer points and
at storage.
Baghouses with Induced draft fans.
Dry cyclones
Venturl wet scrubbers
Clean Fuels
Venturl wet scrubber
Hater seal (Union)
Early Colony efficiency lower than SRI assump-
tions. Recent Colony. Ca, Cb Inventories 1n
approximate agreement (unit shale basis).
Early Colony efficiency assumptions differ frar
SRI. Recent Colony Cb, Ca estimates are comparable
on a unit shale basis.
Fuel mix accounts for major Inventory differences.
SRI assumes greater efficiency than Colony, Ca, Cb.
TOSCO II generates more participates during mois-
turizing than does
claims no emissions
.% »soufo
water seat ,
HO.
Gas Fuels
Liquid Fuels
Armenia removal
t Hydrotreatlng/amnonla
off gases
ival from
Early Colony EIS assumed high nitrogen shale oil
used as plant fuel. Recent Colony and Cb Inven-
tories assume low N fuels. Ca and Union
Inventory based upon entirely gaseous fuels.
HC's and CO
Incineration of trace hydrocarbons
1n TOSCO II preheat system
All Inventories comparable for HC's. Diesel
equipment/mine vent rather than process sources
contribute most CO.
74
-------
Table 3-8. Potential Fugitive Dust Emissions3
Type of Mining Operation
Surface Mine (8000 M3 oil/dav)
Mine development
Overburden Disposal
Temporary Storage
Permanent Disposal Processed Shale
Surface Facilities (8 Kilometers of
unpaved road, VMT 80 Kilometers)
Haulage from Mine (3 Kilometers)
Underground Mine (8000 M3 oil /day)
Mine development
Permanent Disposal of processed shale
Surface Facilities (8 Kilometers of
unpaved roads; VMT 80 Kilometers)
True In-SituProcess1ngd(8000 M3 oil/day)
Surface Facilities (8 Kilometers
unpaved road; VMT 80 Kilometers)
Land Required
(Hectares/yr)
10
200
30
30
4
30
-
Particulate
Emissions (Tonnes/Day)
Uncontrolled Controlled
0.17
3.31b
0.075
0.50
0.004
0.070
4.13
0.067
0.50
0.01
0.57
.01
.01
0.83C
O.llc
.003
Amick, Robert, S., et al., Fugitive Dust Emission Inventory Techniques, paper
number 74-58 presented at the Air Pollution Control Assoc. meeting in Denver,
Colorado, June 1974.
Emissions from overburden disposal will likely be much less for the oil shale
industry. Revegetation is planned for the disposal area. This will minimize
fugitive losses from this source.
Assuming an average of 80% control by applying various air pollution strategies
to minimize particulate emissions.
dWithout mining to create void volume. Emissions associated with a 8000
M3/day modified in-situ operation would amount to about .06 - 0.1 tonnes/
day (uncontrolled), depending on the extent of mining.
75
-------
uncontrolled fugitive emissions could amount to 4 tonnes/day for a surface min-
ing operation. As would be expected, underground mining presents less of a
fugitive dust problem than deep surface mining. Estimated fugitive emissions
after control are comparable in magnitude to controlled participate emissions
from shale preparation 1n a TOSCO II operation.
The emissions inventory for Phase III operations at tracts U-a/U-b in-
clude estimates of fugitive emissions from several sources. Approximately 5
tonnes/day of dust are to be attributed to such sources for the 8000 m3 (50,000
bbls) per day operation (Table 3-5).
3.2 WATER REQUIREMENTS AND WASTEWATER PROCESSING
Water is a necessary resource for the development of an oil shale in-
dustry. Water is required for dust control during mining and crushing, for
gas cleaning and air pollution control, for cooling purposes, and for mois-
turizing of retorted shale. Upgrading of crude shale oil, on site power
generation, and revegetation of disturbed land and retorted shale disposal
areas will also consume large quantities of raw water. The total quantity
of water necessary for each of these uses is dependent on the development
options chosen and on the ultimate size of the oil shale development.
In recent years, increasingly stringent wastewater discharge regulations
have been promulgated by both the federal and state agencies. Because of
these regulations, the quality and quantity of wastewater effluents and the
frequency of waste disposal may be limited. Most of the oil shale developers
however, plan no direct discharges to receiving streams.
The following is a discussion of water requirement estimates, sources
and nature of wastewaters, specific process wastewaters, and wastewater
treatment options for the oil shale industry.
3.2.1 Water Requirement Estimates for Oil Shale Development
The water requirements per unit of net product will necessarily depend
on the type of mining, retorting, and upgrading processes utilized. In gen-
eral , the in-situ methods are expected to require less water than convention-
al mining and retorting. Estimated water requirements for an integrated oil
shale industry which have been prepared for various oil shale developments
are summarized 1n Table 3-9.
76
-------
Table 3-9.
Estimates of Process Water Requirements for Full Scale Oil
Production (m? of water needed per m3 of oil produced) (3,
14,22,23)
Shale
7,8,9,
Oil Shale Development
Tract C-a - Phase II
Tract C-b - Phase III
Tract U-a/U-b - Phase IV
Colony Development Operation
Union Oil Development Operation
Occidental
Paraho
Quantity Required
(m3 water/m3 oil
3.5
3.84
5.4.
3.84
1.56
1.0-1.5
3.37
Estimates have been made to categorize water consumption by unit pro-
cesses and operations within a shale oil recovery operation. Table 3-10is
one such estimate of the water requirements by unit processes (4).
Table 3-10. Water Consumption Requirements for Unit Processes Associated
with Oil Shale Processing
A.
B.
Processes
Mining and Crushing
Retorting
Shale Oil Upgrading
Processed Shale Moisturizing
Power Generation
Revegetation
Sanitary Use
Subtotal
Associated Urban Development
Domestic Use
Domestic Power
Subtotal
GRAND TOTAL
AVERAGE VALUE
Water Requirements
m3 water/m^ oil production
0.16 - 0.22
0.25 - 0.31
0.62 - 0.93
1.23 - 1.87
0.31 - 0.43
0 - 0.30
0.01 - 0.02
2.57 - 4.07
0.29 - 0.39
0.03 - 0.04
0.32 - 0.43
2.89 - 4.5
3.69
More than 80% of the estimated water demand is attributable to the pro-
cessing facilities. Of the total process water, approximately 45-50% is con-
sumed in moisturizing processed shale. Shale oil upgrading accounts for
about 25% of the total process water demand. Power generation and retorting
each consumes 10-15% of the water requirement for processing oil shale and
shale oil.
77
-------
3.2.2 Sources and Nature of Wastewater (1,3.7,8,9,12,14,22)
Aqueous wastes from oil shale processing can be broadly categorized as
originating from direct or indirect sources. Direct sources are wastewaters
generated from unit operations and/or processes, including (1) wastewater
from retorting operations, (2) wastewater from upgrading operations, (3)
water from air emission control and gas cleaning systems, (4) cooling water
and boiler water blowdowns, (5) water treatment systems, (6) mine dewatering
wastewaters and (7) sanitary wastewaters. Indirect sources include: (1)
leachate from retorted shale disposal areas, (2) runoff and erosion result-
ing from construction and site use activities, and (3) runoff from mining
and transport activities. The following is a discussion of the characteris-
tics of the wastewaters from each of these sources.
Wastewater from Retorting Operations: Water is a direct product of oil
shale retorting, resulting from the pyrolysis of kerogen, the release of free
and inorganically bound water from raw shale, and the combustion of organic
material in shale. From 4 to 30 liters of water (1-8 gallons) are commonly
produced per ton of input shale feed to a surface retort, depending on the
retorting process and the composition of the shale processed (1,3,14). In-
situ process demonstrations have reportedly produced even greater amounts of
water (22). Some water condenses with crude shale oil during separation of the
oil from retort gases. This water can partially separate from crude shale
oil during storage, or can appear in aqueous waste streams of shale oil up-
grading operations. Water remaining in retort gases after oil separation
can be condensed during cooling or gas cleaning operations, or can appear in
the flue gas stream from retort gas combustion. Water separated from crude
shale oil contains mainly ammonia, carbonate and bicarbonate, sodium, sul-
fate, chloride, and dissolved or suspended organic compounds (phenolics,
amines, organic acids, hydrocarbons, mercaptans). Smaller quantities of
calcium, magnesium, sulfides, and trace elements may also be present, along
with suspended shale fines. Water condensed from retort gases contains
primarily ammonia and carbonates, with traces of organic substances and sul-
fur containing compounds.
Process Water from Upgrading Operations; The quality of the wastewaters
from an upgrading operation varies with the level of on-site upgrading or
refining utilized. In general, a full scale refining operation may include
any of the following wastewater streams: oily cooling water, process water,
and wash water.
Oily cooling water includes all wastewater resulting from quenching,
vessel cleanout, spills, coker blowdown and process steam condensation.
Process wastewater includes condensed steam from stripping operations, wash
water from process drum cleaning operations, wastewaters produced during
chemical reactions, and other in-process sources. Spent caustic streams can
result from extraction of acidic contaminants. Wastewaters from sources
such as ion exchange regeneration, in-plant storm water, hydraulic decoking
and once-through cooling are mostly oil free.
78
-------
The blending of wastewaters from a full scale refining operation may
produce a wastewater high in ammonia, bicarbonates, sulfides, phenols, total
dissolved solids, oil and grease. Such waters may be characterized by high
levels of Biochemical Oxygen Demand (BOD) and Chemical Oxygen Demand (COD).
Water from Air Emission Control and Gas Cleaning Systems: Included in
this category is wastewater collected during retort gas cleaning, tailgas
cleanup, and foul water stripping. Major constituents in such waters are
shale dust particulates, hydrocarbons, H2S, NH3, phenols, organic acids and
amines. Other constituents such as thiosulfate and thiocyanate may also
be present.
Cooling Water and Boiler Water Slowdowns: Cooling water is used in re-
torting and oil upgrading to absorb heat which cannot be economically recov-
ered for use in the complex or absorbed by air fan coolers. Cooling water is
generally circulated through a wet cooling tower system to release this heat
to the atmosphere. Because of evaporative losses, there is a constant build-
up of dissolved solids which requires a portion of this recirculated water
to be discharged as blowdown from the cooling water system. Similarly a
fraction of the.boiler water must be discharged as blowdown to minimize scal-
ing of boilers. Both the cooling water and the boiler blowdown waters con-
tain a high concentration of dissolved solids, and substances such as hexa-
valent chromium used for corrosion control.
Raw Water Treatment System Wastewater: Good quality water is needed to
supply processing, cooling tower, steam generation and other miscellaneous
process uses. Wastes from water treatment systems generally consist of
chemical sludges, backwash water from filtration system and blowdown from
zeolite softening systems. The largest quantity of waste is lime sludge
which is characterized by high hardness and dissolved salts content.
Mine Dewatering Wastewater: Waters found in aquifers encountered dur-
ing mining must be removed by a dewatering system. Mine dewatering could
produce large quantities of low quality water unless groundwater is prevented
from entering the mine. The quality and quantity of this water will vary
with location and processing technique. During a full scale operation, most
of this water willbe used in wetting and compacting retorted shale. Major
constituents of mine water are sodium, carbonate, bicarbonate, chlorides,
fluorides and boron. Reinjection of this water into the aquifer may cause
increased ground water salinity.
Sanitary Wastewater: Included in this category are wastewaters from
domestic sewage, kitchen, bathroom, laundry and toilet uses. In addition
to the mineral and organic matter already present in the water supply system,
human excrement, paper, soap, dirt, food wastes and other substances are
added to wastewater. Because of the unstable organic matter and the enteric
microorganisms present, disposal of this wastewater without pretreatment is
objectionable both from the health, environmental, and esthetic point of
view.
Leachate from Retorted Shale; As discussed in the water requirement
section, approximately 45-50% of the water required for an oil shale plant
79
-------
is used for moisturizing of retorted shale. Much of this water requirement
will be supplied by mine water and process wastewaters. Because of the large
quantities of water utilized and the exposure of retorted shale to rain and
snowfall, a source of indirect water pollution may occur via leaching or run
off from retorted shale piles. However, the bulk of the water applied to re-
torted shale is expected to be held in capillarity or to be bound as simple
hydrates. The suspended and dissolved constituents of wastewaters applied
to retorted shale are expected to be partially immobilized by physical adsorb-
tion and/or chemical reaction with retorted shale. Leaching experiments in
the laboratory and with small plots indicate that inorganic salts - Na, Mg,
S04, Cl~ may be leached from retorted shales. Small quantities of organic
substances and trace elements are also water soluble. Leachates are further
discussed in Section 3.3.
Runoff and Erosion from Construction, Mining, Transport, and Site Use
Activities: Construction, mining and site use activities may potentially
result in increased sediment and dissolved solids loading in surface runoff
and receiving streams. This indirect source of potential water pollution
is not unique to oil shale extraction and processing, but may require care-
ful control due to the magnitude of site activities. Collection and impound-
ment of runoff will likely be necessary.
3.2.3 Specific Process Wastewaters
The following is a summary of the available process wastewater informa-
tion. Waste stream information for some processes are not yet available or
are considered to be proprietary.
TOSCO II Wastewater (3,8): Direct wastewater discharge from a TOSCO
II retorting and upgrading operation is not anticipated. All wastewater 1s to
be reused for in-plant processing and ultimately consumed in moisturizing
retorted shale. Plant process wastewaters will be collected, processed to
reclaim useful components, and combined for in-plant treatment before reuse.
The major process units that generate wastewater are: (1) pyrolysis and oil
recovery units - blowdown wastewater is produced from high energy venturi
wet scrubbers used to remove shale dust from the flue gas; (2) gas oil and
naphtha hydrogenation units - sour water is produced by the washing opera-
tion; (3) ammonia separation and sulfur recovery units - ammonia stripped
water and an acidic wastewater are generated; (4) delayed coking process
units - foul water is produced; (5) utility boilers - blowdown wastewater
is produced; and (6) Wellman-Lord unit - blowdown consisting of alkaline
sulfate/sulfi te wastewaters.
Detailed quantitative characterization of the individual waste streams
has not been performed to date because these streams are combined, treated
in-plant and subsequently reused to exhaustion. However, the combined pro-
cess waste stream has been approximately quantified by Colony and is repro-
duced in Table 3-11. The major constituents present in the combined process
water are organic acids, neutral oils, amines and phenols, and mineral salts
such as sodium, calcium, and magnesium sulfates, chlorides and carbonates.
Data on the exact chemical composition of the organic acid, amine, and
80
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Table 3-11. Approximate Composition of TOSCO II Combined Process Wastewater
(8000 mJ/day upgraded shale oil production) (3)
Component
Mg+2
Na+1
NH/1
Zn+2
As*5
Cr+6
C03-2
HO^1
so4"2
S2°3~2
P04"3
Cl"1
CN"1
Phenols
Amines
Organic Acids
Neutral Oils
TOTALS (Rounded)
Concentration in Water (mg/1)
Added to Spent Shale
i^
280
100
670
16
5
.015 - 0.3
2
360
100
850
90
5
570
5
315
410
1,330
960
6,100
Kg/hr
86
32
204
4.5
1.8
.0045 - .09
.45
109
32
261
27
1.8
175
1.81
98
127
409
295
1,870
In addition to above, elements present in trace quantities (less
than 1 mg/1 are Pb, Ce, Ag, Mo, Zr, Sr, Rb, Br, Se, Cu, Ni, Co,
Fe, Mn, V, Ti, K, P, Al, F. B, Li.
81
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neutral oil fractions are not available. High molecular weight organics be-
longing to the polycyclfc organic materfal (POM) class may also be present.
Twenty-two trace elements have also been identified as constituents of com-*
bined wastewater; none of these, however, is present in quantities greater
than 1 mg/1.
GCR (Paraho Direct Mode) Wastewater: Available information from the
Paraho Demonstration Project indicates that the major constituents present in
process water (condensed or separated from crude shale oil or retort gases)
are ammonia, carbonates and bicarbonates, organic acids, and amines
(1,5,6). Table 3-12 is a summary of the major constituents present in the
Paraho retort wastewater stream and does not reflect any downstream processing
operations. Because of the significant amounts of organic material present,
the biochemical oxygen demand (BOD) and chemical oxygen demand (COD) are
very high.
Table 3-12. Paraho (GCR) Process Wastewater Analysis (1,5,6)
Constituents
Ammonia nitrogen
Organic carbon
Organic nitrogen
Carbonates
Bicarbonates
Parameters
BOD
COD
Concentration Range (mg/1)
2,000-20,000
10,000-29,000
4,000-12,000
2,000-24,000
5,000-26,000
5,000-12,000
17,000-20,000
Levels of approximately twenty metals have also been determined in
Paraho process waters (6), Their concentrations are all less than 1 mg/1.
Upgrading of shale oil is not currently practiced at Anvil Points, and little
is known about wastewaters which may be associated with such practices.
Union Oil Retort B Process (20): The major wastewater streams from
Union Oil's retorting process are: (1) water from make gas compression and
cooling, (2) water from ammonia absorption, (3) water from oil-water
separation, (4) water from first stage solids removal, and (5) water from
oil stripping. According .to Union, these wastewater streams will be com-
bined, stored and reused for retorted shale cooling in the water seal after
oil water separation and some water stripping. The total quantity of waste-
water generated for a 9000 tonnes/day (10,000 TPD) oil shale plant is esti-
mated at 1.32 m3/min (350 gpm). Because of the proprietary nature of the
Union process, quantitative Information on waste stream composition has
not been made available. Limited information released by Union personnel
indicates that the predominant Inorganic constituents present In their com-
bined process wastewater are sodium, calcium, and sulfate. Some magnesium,
potassium, and bicarbonate are also present, and the total dissolved sol Ids
is estimated at 10,000 ppm. No information Is available regarding organic
constituents or trace elements.
82
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Lease Tracts: The characteristics of process wastewater streams have
not been reported for Tracts C-a or C-b. Because of the similarity in re-
torting operations between C-b and Colony (3,8), it is expected that C-b's
process wastewater will be comparable to that reported for Colony. Tract
C-a will utilize 35% Paraho (GCR) retort process and 65% TOSCO II process
in its Phase II development. Consequently process wastewater generated at
C-a will have a composition reflecting both TOSCO II and Paraho retorting.
Developers of Tracts U-a and U-b in Utah plan to process oil shale using
primarily Paraho retorts during Phase III. Some of the reported characteris-
tics of process wastewaters associated with Phase III operations at U-a/U-b are
shown in Table 3-13 (23).
3.2.4 Process Wastewater Treatment
Under current planning, most of the oil shale developers envision zero
discharge of their wastewaters. Reasons for this commitment may be (1) the
relative scarcity of water in the western oil shale regions, which may en-
courage minimum intake and discharge of waters, (2) future pollution control
regulations for wastewater discharge which may be so stringent that cost for
discharge compliance may well exceed the cost of simple in-plant treatment and
subsequent reuse, and (3) control technologies for in-plant treatment which
have been well developed by the oil refining industries can be applied to oil
shale processing without resorting to high cost research. Consequently, it is
anticipated that most of the developments will employ treatment techniques
similar to those developed by the oil refining industries. The final disposi-
tion of wastewater will be evaporation or incorporation Into retorted shale.
The degree of treatment utilized will necessarily depend on the intended
reuse of the wastewater. For the purpose of this discussion, the treatment
techniques will include both the in-plant and end-of-pipe treatment options.
In-plant controls are designed primarily to reduce the volume and quantities
of contaminants discharged in process wastewaters. End-of-pipe controls, on
the other hand, are designed to treat the wastewaters after they have been
generated.
In-plant treatment includes: (1) collection of all process wastewaters
and waters from leaks, drain outs, flushes, washdowns, and runoffs; (2) pre-
processing of certain waste streams to reclaim valuable constituents; and (3)
combining of the various waste streams for solids settling and oil-water
separation. A typical in-plant treatment system will consist of individual
waste collection lines, ammonia stripping, a sulfur recovery system for
specific process streams, a combined waste holding pond, a gravity API sep-
arator,*a chemical dosage tank, a dissolved air flotation unit (DAF) and a
final holding pond for the treated wastewater.
Wastewater from the foul water system will be stripped with steam to re-
move dissolved hydrogen sulfide and ammonia. Gases from the stripped overhead
will be sent to the sulfur recovery plant and to the ammonia recovery system
while the stripped water will be pumped directly to a holding tank or pond for
later use in moisturizing spent shale.
*American Petroleum Institute (recommended design)
83
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Table 3
-13. Approximate Composition and Flow Rates for Selected Wastewater Streams - Lease Tracts'-
U-a/U-b (Phase III, 8000 m3 Upgraded Shale Oil/Day) (23)
Component or
Parameter
Total Dissolved Solids
(TDS)
Suspended Solids
(SS)
Chemical Oxygen Demand
(COD)
Biochemical Oxygen Demand
(BOD)
Oil and Grease
Phenols
Ammonia
Flow Rate
Units
mg/1
ii
ii
M
n
M
mg/1 as N
m^/min
Waste Stream
Sour. Water
Stripper Oily
Bottoms Wastewater'
500-2000
30-55
500-1500 100-2000
50-500
50-100 50-1000
80-1 50
25-50
17.7 4.1
Treated
Low- TDS
Wastewater
1000-2000
30
50
20
<5
<1
10.4
High TDS
Wastewater
5000-10,000
100-500
10.7
-------
All oily wastewaters from processing, including gas condensates, oily
water wash-down from process pads, and process leaks will be collected in a
common sump. Overflow from the sump will be conveyed to an API separator
system, consisting of a surge pond, an API separator, a chemical dosage tank
and a DAF unit. Separated oil will be returned to the raw oil recovery plant
and any sludge collected will be removed periodically and returned to a re-
tort or burned in the thermal oxidizer. Effluent from the API separator will
flow to the chemical tank where it will be saturated with air by pressurizing
the tanks to 40 to 60 psig. After about 1 minute retention, the wastewater
will be discharged through a flotation chamber where air will come out of
solution in minute bubbles. The residual oil and particulates will be
carried to the surface by the bouyant force and will be skimmed and returned
to the raw oil recovery plant. Processed effluent will then be sent to a
holding pond from which the wastewater will be used for moisturizing and
compacting spent shale.
Sanitary wastewaters will be collected and treated in packaged treat-
ment units. Effluent from the treatment unit will be chlorinated and reused
as make-up water for certain processes.
Mine dewatenng wastewater, runoffs, and blowdowns from cooling tower and
boilers will not be treated in the conventional sense. These wastewaters
will be centrally collected for use in dust suppression and/or conveyed to
the holding tank or pond for wetting of retorted shale.
End-of-pipe treatment includes: (1) additional treatment of the process
wastewater after in-plant treatment, (2) treatment of sanitary wastewater,
(3) demineralization of mine dewatering wastewater and boiler and cooling
water blowdown. Process units utilizing end-of-pipe treatment may include any
one or more of the following: biological treatment units such as activated
sludge system, biofiltration, or aerated lagoons, demineralization units such
as ion exchange columns, reverse osmosis or distillation, and soluble organics
removal units containing activated carbon filtration.
85
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3.3 SOLID WASTES ASSOCIATED WITH OIL SHALE EXTRACTION AND PROCESSING
The solid wastes resulting from oil shale processing present one of the
major environmental problems associated with commercial development. Shale
derived solid wastes include fines from crushing and conveying of the raw
shale and the processed (or retorted) shale remaining after retorting. To-
gether these constitute most of the process solids requiring disposal.
Other solids to be discarded depend primarily upon the extent of upgrading
of the crude shale oil which is carried out in conjunction with the retort-
ing operations, and may include shale oil coke if experience shows that such
material is not usable or marketable. Certain non-shale wastes such as
spent catalysts may also be generated during the processing of shale oil.
This chapter deals with the nature and sources of solid wastes from oil
shale processing and presents data on the quantities of solid wastes ex-
pected from the various oil shale processing operations.
3.3.1 Raw Shale Fines
The primary sources of raw shale fines are the crushing operations con-
ducted on the as-mined shale, and dust from raw shale transport within the
mine-plant complex. The composition of the fines, of course, is essentially
that of the mined, raw shale and its contained organic matter. A typical
chemical analysis of the organic matter would include the following (1):
wt % wt %
Carbon 80.5 Sulfur 1.0
Hydrogen 10.3 Oxygen 5.8
Nitrogen
The associated mineral matter in the raw shale has the following typical
composition:
wt % wt %
Dolomite 32 Albite 10
Calcite 16 Microcline 6
Quartz 15 Pyrite 1
Illite 19 Analcite 1
Oil shale is a highly consolidated organic-inorganic rock system, with no
significant micropore structure, pore volume, or internal surface. Over 99%
of the inorganic particles have equivalent spherical diameters of less than
44 microns, 75% are 2-20 microns, and 15% are less than 2 microns.
The size distribution of the raw shale fines or rejects from crushing
depends upon the feed size requirements of the retort. For the Union retort
B.the feed is 3 mm to 5 cm (1/8 to 2 in.), and the fines are therefore minus
3mm (1/8") (20). Paraho fines are typically minus 6 mm, as are also the fines
from the Superior process (5). There are no unusable fines from the TOSCO II
process (3). The size range of the dust collected from the various processes
86
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has not been reported, but can be expected to be less than the average size
of the fines from crushing. Dust will probably normally be disposed of as a
slurry or sludge.
3.3.2 Retorted Shales
Pyrolysis of oil shale results in the conversion of most of the original
organic material in raw shale to gaseous and liquid hydrocarbons (and sulfur,
nitrogen, and oxygen containing organics). Retorted shales containing solid
organic residues can be disposed of directly as a solid waste, or can be
further processed for recovery of heat value of the residue.
Burned Shale (e.g. Paraho Direct Mode (GCR)): After retorting at approxi-
mately 900°F, the remaining processed shale is soft and friable. It usually
has an organic "carbon" content of 2 to 3%, depending upon the retorting pro-
cess. Direct Mode Paraho retorting produces a retorted shale which has been
partially "burned" after pyrolysis of oil shale kerogen. Residual organic
carbon amounts to about 2% by weight, and typically 30% of the contained
carbonate minerals have been calcined (24). Particle size is greater than
1.2 cm (0.5 inch). It is possible, in principle, to oxidize this carbonace-
ous material, as a source of process energy, and to discard a completely
carbon-free shale residue, or ash. A typical composition- of such ash is
shown in Table 3-14 for several retorted shale residues.
Typical shale ash has a composition similar to Portland cement and has
certain cement-like physical properties. The cement forming tendency of burn-
ed shale can be used to advantage to help create a physically and chemically
stable disposal pile (26). Before setting, burned (and moistened) shale ash
behaves like a sandy silt. After setting, it develops sufficient cohesion so
that deep, well-stabilized piles with high slope angles may be constructed.
The strength of burned shale disposal pile depends upon the amount of moisture
added (10% is optimum) and the amount of cohesive hydrates produced. Approxi-
mately 90% of its ultimate stability is reached in the first 16 days of stor-
age. Reduction in ash particle size, by grinding, increases pile strength.
Carbonaceous Retorted Shale (TOSCO II. Union B. Paraho Indirect Mode):
Several retorting processes do not utilize completely the carbonaceous residue
remaining on the shale after pyrolysis, as a source of energy. Therefore, the
retorted shale still contains about 5% organic matter. In addition, the maxi-
mum temperature during retorting is commonly less than that at which the dolo-
mite and calcite in the shale rock decomposes, or at which calcium silicates
form.
Cementation reactions produced by subsequent moisturizing of carbonace-
ous retorted shale do not occur during compaction. There is, therefore, less
opportunity to create a water impervious disposal pile, except through the
cohesion produced by compaction alone. The possibility of leaching of sol-
uble salts from the pile is therefore greater than is the case with burned
shale.
87
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Table 3-14. Ash Composition of Typical Retorted Oil Shales
Component
Si02
Fe2°3
A1203
CaO
MgO
so3
Na20
KgO
TOSCO IIa
wt%
33.0
2.5
6.8
15.8
5.3
-
8.7
3.3
Union B
wt%
31.5
2.8
6.9
19.6
5.7
1.9
2.2
1.6
GCRC
wt%
43.8
4.6
12.2
22.1
9.3
2.2
3.4
2.4
aColony Environmental Impact Analysis, 1974 (data represent
Mahogany zone shale (~35 gal/ton) from Parachute Creek area.
See Ref. 3.
Lipman, S. C., Union Oil Co. Revegetation Studies (data
represent Mahogany zone shale (~35 gal/ton) from Parachute
Creek area. See Ref. 12.
Stanfield, et.al., Data represent Mahogany zone shale (~30
gal/ton) from Anvil Points. See Ref. 25.
-------
TOSCO II retorted shale contains approximately 4.5% organic "carbon,"
and is to be moisturized to about 14% H20 for compaction (3). The retorted
shale has a very small particle size with 60% finer than 200 mesh, and 35%
finer than 325 mesh. The particles are crystalline and bulky, not platy.
A typical ash composition is shown in Table 3-14.
Union B retorted shale is similar in size to that produced by the
Parano process. It is a coarse, gravel-sized black material with about 4.3%
organic carbon (12). Some 74% of the fresh uncompacted spent shale is 4.76 mm
to 25.4*particle size. Uncompacted dry bulk density is 977 kg/cu. meter
(61 Ibs/cu.ft.), and its field moisture content is 16%. The shale can be
compacted to a density of 1440 kg/cu. meter (90 Ibs/cu.ft.) in a disposal
pile. Typical chemical composition of the ash is shown in Table 3-14.
Table 3-15 below lists some typical values for densities, sizes, and
porosities of carbonaceous and burned retorted shales before compaction.
Table 3-15. Properties of Retorted Shales (27)
Geometric mean size, cm
Bulk Density, g/cm3
Solids Density, g/cm3
Porosity (fraction)
Permeability, cm2
TOSCO II
0.007
1.3
2.49
°'47 in
2.5 x lO'10
GCR
0.205
1.44
2.46
0.41
3.46 x
10-9
Tests on field plots consisting of TOSCO II (and GCR) retorted shales
have indicated that in place compaction densities of about 880 kg/m3 (55 Ibs/
ft3) can be attained, and surface compaction densities as high as 1620 kg/m3
(101 lbs/ft3) are possible (26).
Retorted shale from the Superior process will have different properties
than retorted shales from other processes. The raw oil shale found in deep
deposits of the Northern Piceance Basin contains sodium and aluminum minerals,
and these are slated for recovery along with pyrolysis products by the Super-
ior Oil Company. Superior retorted and processed shale may be partially
"burned," depending on the mode of operation, and will have been stripped of
most of the soluble sodium and aluminum salts. Little is known at present
about the detailed physical and chemical properties of such processed shales.
Soluble Salts Associated with Burned and Carbonaceous Retorted Shales:
Processed shales contain mineral components which may be partially dissolved
by water. Laboratory and field experiments have shown that sodium, calcium,
magnesium, potassium, bicarbonate, sulfate, and chloride are present in waters
which have contacted freshly processed shale (27). Table 3-16 presents results
of laboratory leaching experiments of raw and retorted shales. TOSCO II and
USBM retorted shale each contain about 10 kg/tonnes (20 Ibs/ton) of readily
Teachable salts, roughly ten times that Teachable from raw oil shale. Data for
89
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the burned shale from the Union A process (column 4 in Table 3-16) indicates
that total soluble salts depend heavily upon extent of carbon burnoff and
mineral decomposition which occur in the combustion zone of a 6CR.
The rate and extent of soluble inorganic salt leaching of retorted
shale which will occur under field conditions depends on a number of factors
in addition to the type of retorting process employed. Such factors include
the amount of water added, the degree of compaction accomplished, the manner
in which a pile is laid down (eg, slope, depth of pile), the extent of pre-
leaching which is accomplished in connection with revegetation, and the age
or weathered state of the shale pile. Also, burned shales can form partially
cemented barriers to water within a disposal pile which can serve to inhibit
further leaching.
Table 3-16.
Inorganic Ions teachable from Freshly Retorted Shales
(kgs/tonne) - Based on Laboratory Tests (27)
Ion
K*
Na+
Ca~
u -H-
Mg
HCO-
cr
so=
Total (kg/ tonne)
(Ibs/ton)
Raw Shale
0.24
0.48
0.1
0.01
0.75
0.22
0.79
1.95
(3.9)
TOSCO II
0.32
1.65
1.15
0.27
0.20
0.08
7.3
10.96
(22)
GCR (USBM)
0.72
2.25
0.42
0.04
0.38
0.13
6.0
9.94
(20)
GCR (Union A)
6.25
21.0
3.27
0.91
0.28
0.33
62.3
94.34
(188)
Organic Substances in Retorted Shale: The carbonaceous component of
processed shales contains organic substances which can be extracted by or-
ganic solvents (ie, benzene), and by water. From .01 to .1% by weight of
processed shales are benzene soluble, and substances such as phenols, aro-
matic acids, and amines are present in the soluble fraction. Compounds
belonging to the POM class are also present in benzene extracts, including
the suspected carcinogen benzo(a) pyrene (BaP) (16). Recent experiments have
indicated that POM and other organfcs can be extracted by water, along with
inorganic salts. Further, process water to be used for moisturizing retorted
shale prior to disposal contains similar organic substances (Tables 3-12 and
3-13), some of which may be subject to later removal by water running off of
or percolating through disposal piles.
90
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Benzo(a) pyrene (BaP) is a readily measurable member of the POM class of
compounds. Commonly, BaP is used as an indicator compound for potential car-
cinogenicity of materials in which it is found. Table 3-17 lists some BaP
levels in some natural and industrial materials. Carbonaceous retorted shales
contain BaP in concentrations similar to those found in many natural organic
materials (28). Shale oils, in contrast, contain relatively high levels of
BaP. The values shown in Table 3-17 do not necessarily indicate the bioavail-
ability of BaP in individual materials, nor do they reflect the presence of
other potentially carcinogenic substances.
Retorted shales have also been tested for carcinogenic properties using
test animals (28). Although benzene extracts of carbonaceous retorted shale
exhibit carcinogenic activity on the skins of mice, retorted shale itself has
not shown such skin activity in mice exposed to the shale as bedding in long
term experiments. Further conclusions with respect to effects of retorted
shale on internal organs of test animals cannot be made at this time, pending
the results of pathological tests currently underway. POM extracted from re-
torted shale by water may be somewhat more active as an animal skin carcinogen
than retorted shale itself (16).
3.3.3 Other Shale Derived Solid Wastes
Retorting and on-site shale oil upgrading can result in the production
of shale derived wastes such as coke and oily sludges.
Shale Oil Coke: If the crude shale oil produced by retorting is upgrad-
ed on site prior to shipment to market, a possible product is coke.
This coke must be stored prior to sale or will require disposal as a waste.
Shale oil coke is expected to have the typical composition shown in Table
3-18. Storage or disposal piles must provide for non-leaching of soluble
salts and organic substances to the environment.
API Separator Sludges: Oily and tarry material separated from waste-
waters may constitute a semi-solid waste requiring disposal. Such material
may contain suspended solids, hazardous organics, and trace elements.
Handling options include (1) burial with other solid wastes in the processed
shale pile, (2) incineration with air pollution control, and (3) reinjection
into the retort or upgrading units.
3.3.4 Non-Shale Solid Wastes
If substantial upgrading operations are conducted at or near the retort-
ing site, non-shale solid wastes will be generated which require disposal.
Such wastes include spent catalysts from hydrotreating, sulfur recovery, and
arsenic removal operations, lime sludges and other solids from water and
wastewater treatment systems, and spent carbon and diatomaceous earth from
gas and oil treating units. Some of these wastes may contain highly toxic
substances such as arsenic, and/or may result in emission of hazardous
91
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Table 3-17. Levels of Benzo(a)pyrene (BaP) Reported in Selected
Natural and Industrial Materials (28)
Substrate Material
Natural Materials
Benzo(a)pyrene
(parts per billion)
Coconut oil
Peanut oil
Oysters (Norfolk, Va.)
Forest soil
Farm field near Moscow
Oak leaves
Petroleums and Petroleum Products
Libyan crude oil
Cracked residuum (API Smpl 59)
Cracked sidestream (API Smpl 2)
West Texas paraffin distillate
Asphalt
Oil Shale Related Materials
TOSCO II retorted shale
GCR retorted shale
Raw shale oil (Colorado)
Crude shale oil (TOSCO II)
Hydrotreated shale oil (0.25%N)
Hydrotreated shale oil (0.052N)
Coals
High volatile bituminous
Low volatile bituminous
Lignite
Coal tar
43.7
1.9
10 to 20
(based on dry weight)
4 to 8
79
300 max
1,320
50,000
2,000
3,000
1 x 10* to 1 x 105
13 - 100
15
30,000 - 40,000
3,130
6,900
690
4,200
3,150
1,200
3 x 106 to 8 x 106
92
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to 7* arsenic
or dlpola?
for
d1sposa1 or ^Processing. Hydrodenltrlfica
' ma.V°nta1n N>-13* carbon, 8-10* sulfur, and up
Table 3-18. Typical Composition of Shale Oil Coke
Ash, wt %
Moisture, wt %
Carbon, wt %
Hydrogen, wt %
Oxygen, wt %
Total Nitrogen, wt %
Sulfur, wt %
Arsenic, ppm
m
(1)
10-15
7.0
91 (
3.6 J
1.3 (
3.9
0.5
5-10
(0.3 water soluble)
(2)
12.6
N/A
)
82. 5 >
I
4.1
0.8
N/A
- «. yj NX«-W i wwr\ > nppi u i oa i ujf u i i olid I c I abr\
Group, National Petroleum Council, 1972, data are
for shale oil produced by TOSCO II retorting (Ref. 29).
(2)
'Detailed Development Plan, Lease Tract Ca, data are
for combination Paraho and TOSCO II produced shale
oil (Ref. 7).
3.3.5 Inventory of Solid Wastes
The anticipated quantities of solid wastes to be produced by example
retorting processes, to the extent that these are presently known or predic-
table, are discussed below.
TOSCO II - Colony Development Operation (3): A complete inventory of
the solid wastes from commercial shale oil production has been compiled by
Colony for the TOSCO II process, and 1s shown 1n Table 3-19. The basis is
a plant processing 55,000 tonnes (61,000 tons) of raw shale daily, and produc-
ing an average of 50,000 tonnes per day (18.3 million tonnes/year) of waste
for disposal. Some 97% of this waste, or 48,300 tonnes (53,300 tons) per
day, is processed shale (and processed dust). An additional 385 tonnes (425
tons) per day is raw shale dust. The remaining wastes are spent catalyst
materials, sludges, arsenic-laden solids, processed plant sanitary wastes,
and 725 tonnes/day (800 tons/day) of coke.
These wastes (except for the coke) are to be transported by closed con-
veyor to a disposal site in Davis Gulch (north of the plant site at Parachute
Creek, Colorado), transferred to trucks for distribution in a processed shale/
93
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plant wastes embankment-type landfill, and compacted to 1,360 kg/cubic meter
(85 Ibs/cu.ft.).
Paraho - Anvil Points (5,21): The present Paraho lease on the Naval Oil
Shale Reserve provides for the processing of a maximum of 362,000 tonnes
(400,000 tons) of mined shale over a 5-year period. This could produce up to
308,000 tonnes (350,000 tons) of processed shale and other plant wastes from
the pilot plant and semi-works operations currently in progress, over the 5-
year lease period. These modest quantities can be disposed of by Paraho at
the existing (USBM plant) dump site, or the new test site being created by
Paraho.
When the single, full-size modular retort is constructed it will have
a nominal capacity of 11,800 tonnes (13,000 tons) per day of raw shale, and
produce approximately 8,800 tonnes (9,700 tons) per day of spent shale, plus
an additional 520 tonnes (570 tons) per day of raw shale crushing fines; or
9,300 tonnes (10,200 tons) per day of waste. This is equivalent to up to
3.4 million tonnes of waste per year.
There is authorization for the processing of as much as 10 million
tonnes of raw shale through the modular retort. However, it is expected that
closer to 3.6 million tonnes (4 million tons) will be processed over the ex-
pected 30 months of operation of the modular unit, thus producing a total of
3.25 million tonnes (3.6 million tons) of total waste from the modular plant.
It is planned that these wastes will be conveyed to the present Paraho,
canyon-disposal site, compacted, contoured, and revegetated.
Lease Tracts: The quantities of solid wastes produced at Tract C-b will
be similar to those listed in Table 3-19, since retorting and upgrading opera-
tions at that tract.are similar to operations proposed by Colony for the Para-
chute Creek development. Quantities of solid wastes associated with operations
at lease tract C-a will be somewhat larger than those at C-b on a unit product
basis, since a lower average grade of shale will be processed, and overburden
and sub-ore from open pit mining will require disposal. Non-shale solid wastes
at C-a are expected to be of similar magnitude and composition to those re-
ported in Table 3-19. Estimated quantfties of solid wastes for Phase IV opera-
tions at tracts U-a/U-b are listed in Table 3-20 (23).
94
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Table 3-19. Major Solid Wastes from TOSCO II Processing (2)
(Based upon processing 55,000 tonnes of raw shale per day)
Source of Solid Waste
Pyrolysis Unit
Processed Shale
C1ar1f1er Sludge from
Wet Scrubbers-Preheat
System
Ball Circulation System
Processed Shale
Moisturizing System
Total
Crushing Unit
Primary Crusher
Final Crusher
Shale Storage S1lo
Total
Upgrading Units (Hydrotreate
Naphtha
Naphtha
Gas Oil
Gas 011
Hydrogen Unit
Hydrodesul furlzer
Caustic Wash
Guard Bed
Shift Converter
(High Temp.)
Shift Converter
(Low Temp. )
Sulfur Unit
Claus Unit
Tail Gas Hydrotreater
Gas Treating Unit
DEA Filter
DEA Filter
Coker Unit
Water Treatment
Approximate
Quantity
48,400 T/D*
780 T/D*
59 T/D*
39 T/D*
49,200 T/D
23 T/D
295 T/D
68 T/D
386 T/D
nl
0-68 T/2 yrs (max)
55 T/yr
0-236 T/2 yrs (max)
318-432 T/yr
123 T/3-5 yrs
2.2 T/D
14 T/l-3 yrs
45 T/5 yrs
45 T/3 yrs
136 T/2 yrs
9 T/5 yrs
7.5 T/2 weeks
7.5 T/2 weeks
727 T/D
0.5 T/D
.02 T/D
Annual
Production
(tonnes)
17,650,000 T
285,000 T
21 ,570 T
14,268 T
8,300 T
107,800 T
24,900 T
0-34 T
55 T
0-118 T
318-432 T
31 T
800 T
6 T
9 T
15 T
68 T
2 T
390 T
390 T
265.000 T
200 T
8 T
Major
Constituent
Processed Shale
Raw Shale Dust
Processed Shale Dust
Processed Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Spent HDN Catalyst
Proprietary Solid
Spent HDN Catalyst
Proprietary Solid
Spent HDS Catalyst
Spent Aqueous Caustic
Spent ZnS Catalyst
Spent Fe-Cr Catalyst
Spent Cu-Zn Catalyst
Spent Bauxite Catalyst
Spent Co, Ni-Mo Catalyst
Dlatomaceous Earth
Deactivated Carbon
Green Coke
L1me & Alum Flocculants
Proprietary Coagulant Aid
T/D » tonnes/day
*Water Excluded
95
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Table 3-20. Solid Wastes Generated Durtng Construction and Operation of Shale Oil Facilities at
Tracts U-a/U-b - Phase IV (16,000 m? shale oil/day) (23)
Source of Waste
Quantity
Retort Shale
(dry basis)
Raw Shale Fines
Spent Catalysts
Waste Fire Brick and Fines
Type Heat Carrier
Diatomaceous Earth arid
Activated Carbon
Elemental Sulfur
Construction Wastes
118,000 tonnes/day
155 tonnes/day
1550 tonnes/year
640 tonnes/year
90 tonnes/year
80 tonnes/day
27,000 tonnes (total)
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REFERENCES
1. Cameron Engineers, Inc., "Synthetic Fuels Data Handbook," 1975.
2. Colony Development Operation, "An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Part 1," 1974.
3. Colony Development Operation, "Draft Environmental Impact Statement/Pro-
posed Development of Oil Shale Resources in Colorado," U.S. Department of
the Interior, Bureau of Land Management, December 1975.
4. Final Environmental Statement for the Prototype Oil Shale Leasing Program.
Vol. I, Regional Impacts of Oil Shale Development, U.S. Department of
Interior, 1973.
5. Jones, J. B. "The Paraho Oil Shale Retort," 9th Oil Shale Symposium,
Colorado School of Mines, Golden, Colorado, April 29-30, 1976.
6. Data collected by TRW/DRI during sampling at Paraho facility, Anvil Points
(Colorado), March 1976. A detailed discussion of the analytical data and
findings can be found in a report, "Sampling and Analysis Program at the
Paraho Facility," to be published shortly by EPA.
7. Detailed Development Plan, Federal Oil Shale Lease Tract C-a (Rio Blanco
Oil Shale Project, submitted to Area Oil Shale Supervisor, 1976.
8. Detailed Development Plan, Federal Oil Shale Lease Tract C-b (Roxana Oil
Shale Project), submitted to Area Oil Shale Supervisor, 1975.
9. Hughes, E. E., et.al., "Oil Shale Air Pollution Control," Stanford Re-
search Institute, EPA-600/2-75-009, May 1975.
10. Cameron Engineers, Inc.,'Synthetic Fuels Quarterly," September 1974.
11. Cameron Engineers, Inc. "Synthetic Fuels Quarterly," December 1975.
12. Lipman, S. C., "Union Oil Company Revegetation Studies," Environmental
Oil Shale Symposium, Colorado School of Mines, Golden, Colorado, October
9-10, 1975.
13. Compilation of air pollutant emissions factors, 2nd Edition, Environmental
Protection Agency, AP-42, April 1973.
14. McKee, J. M. and Kunchal, S. K., "Energy and Water Requirements for an
Oil Shale Plant Based on the Paraho Processes," 9th Oil Shale Symposium,
Colorado School of Mines, Golden, Colorado, April 29, 1976.
15. Federal Energy Administration, Project Independence Blueprint - Potential
Future Role of Oil Shale Prospects and Constraints, U.S. Department of the
Interior, November 1974.
97
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16. Schmidt-Collerus, J. J. and Bonomo, F., et.al., "Polycondensed Aromatic
Compounds (PCA) and Carcinogens in the Shale Ash of Carbonaceous Spent
Shale from Retorting of Oil Shale," Science and Technology of Oil Shale.
Ann Arbor Science Publishers, PI 15, 1976.
17. National Academy of Sciences, "Particulate Polycyclic Organic Matter,"
Washington D.C., 1972.
18. Cook, E. W., "Elemental Abundances in Green River Oil Shale," Chemical
Geology. Vol. II, p. 321-4, 1973.
19. Burger, E. D., "Prerefining of Shale Oil," American Chemical Society,
Division of Petroleum Chemistry, Chicago, Illinois, August 24-29, 1975.
20. Data and information provided to TRW by Union Oil Company, 1976.
21. Cameron Engineers, Inc. Synthetic Fuels Quarterly, June 1975.
22. McCarthy, H. E. and Cha, C. Y., "Development of the Modified In-Situ Oil
Shale Process," 68th AIChE meeting, Los Angeles, California, November
16-20, 1975.
23. Detailed Development Plan, Federal Oil Shale Lease Tracts U-a and U-b
(White River Oil Shale Project), submitted to Area Oil Shale Supervisor,
June 1976.
24. Data provided to TRW by Development Engineering Inc. (operations contrac-
tor for Paraho Project at Anvil Points, Colorado), January 1976.
25. Stanfield, K. E., et.al., "Properties of Colorado Oil Shale," U.S. Bureau
of Mines, Report of Investigations No. 4825, 1951.
26. Nevens, T. D., Culbertson, W. J., Hollingshead, R. D., "Disposal and Uses
of Oil Shale Ash," U.S. Bureau of Mines Project SWD-8, 1967.
27. Ward, J. E., et.al., "Water Pollution Potential of Rainfall on Spent
Shale Residues," Colorado State University, prepared for the EPA under
grant #14030EDB, December 1971.
28. Coomes, R. M., "The Health Effects of Oil Shale Processing," 9th Oil
Shale Symposium, Colorado School of Mines, Golden, Colorado, April 29-30,
1976.
29. U.S. Energy Outlook, Appraisal by Oil Shale Task Group, National Petroleum
Council, 1972.
98
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4.0 POTENTIAL IMPACTS OF EXTRACTION AND PROCESSING ACTIVITIES ON THE
PHYSICAL ENVIRONMENT
Assessment of the potential environmental impacts of oil shale develop-
ment is the central issue to be addressed by this chapter. The assessment
includes a description of the baseline environmental conditions and a review
of the environmental impact studies performed to date by the various developers
and organizations. The air quality section includes a discussion of the
existing meteorology and air quality in and around potential development sites,
and a review of modeling studies which have been undertaken to predict air
quality impacts. The discussion of the impacts on water quality and hydrology
includes descriptions of existing surface and gilund water quality and yields,
the relationship of ground and surface waters in the development areas, the
effects of the consumptive use of water, and the potential effects of waste-
water disposal practices on surface and ground waters. Spent shale and solid
waste disposal plans are summarized, including descriptions of the physical
settings of proposed disposal sites and an identification of potential hazards
and pollution problems.
4.1 AIR QUALITY IMPACTS OF OIL SHALE EXTRACTION AND PROCESSING
This section includes a baseline characterization of the air quality and
meteorology of the Piceance Creek and Uinta Basin areas, and a review and
evaluation of modeling efforts undertaken to predict the impact of oil shale
mining and processing activities on ambient air quality.
4.1.1 Baseline Characterization of Meteorology and Air Quality
The size of the region, its sparse population and its topography will all
have a strong effect on the meteorology and ambient air quality of the region.
Meteorology: At the present meteorological data are not available for
every potential oil shale site; measurements are only now being made at cer-
tain sites. Meteorological measurements are currently available for the
Parachute Creek Valley and Roan Plateau of Western Colorado as well as for the
Piceance Creek Basin. Parachute Creek Valley and Roan Plateau data have been
taken by Dames and Moore and by Battelle Northwest Laboratories under contract
to the Colony Development Operation (1). Piceance Creek Basin data have been
taken by the Rio Blanco Oil Shale Project (2). Data and information from these
two sources will be used to illustrate those features which are especially
important to the transport and dispersion of pollutants in the atmosphere.
In general, sunshine prevails over the region, and precipitation and
relative humidity are low. Precipitation is highest during the winter, and
occurs in the form of snow at high altitude terrain and in the form of rain
99
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at lower altitudes. Temperatures generally range between -40° to 100°F in
the lower regions.
Surface winds are variable with strong spatial, diurnal and seasonal 'de-
pendence, as to be expected, with the prevailing wind in the region being
southwesterly. In Parachute Creek, Colorado River Valley and White River
Valley little information is available on air stagnation, but studies at near-
by Grand Junction show the region to have one of the highest frequency of in-
versions anywhere in the United States (14).
Topography has an important influence on local meteorology. The presence
of rugged terrain causes turbulence within the planetary boundary layer (3).
This favors high dilutions which have, in fact, been observed (4,5). Topo-
graphy especially influences the mountain-valley systems, resulting in dif-
ferential heating and cooling. In the presence of radiational cooling at night,
as would occur under clear skies, a drainage circulation is often set up in
which flow occurs down the side of a mountain or down a slope. During the
daytime, the direction is reversed and flow becomes up-slope or up-valley.
This system is commonly referred to as the mountain-val1ey breeze system.
From an air pollution standpoint, this is a very important system in the oil
shale region (6).
The mountain-valley systems are typically weak, local circulations, with
the drainage flows characteristically weaker than the up-slope flows. Even
at peak intensities, velocities seldom are greater than a few meters per
second. Both up-slope and down-slope flows tend to be confined near the
Ground surface, being around 100m thick and only seldom thicker than 200m.
The foregoing estimates represent drainage flow thicknesses in other regions
at latitudes similar to the oil shale region. At the time of preparation of
this report no detailed drainage data were available for the study region.) A
drainage flow initiated at the top of a slope starts out very shallow and
gradually thickens as the air mass flows downhill. An up-slope flow shows a
similar thickness variation, being shallow at the base of the slope and thick-
est at the top. These flows are very local and, in general, are not strongly
coupled to the mean flow within the Ekman layer.*
There are other types of air flows which owe their origin to the com-
bined effects of meteorology and topography. These, conceivably, may have a
deleterious effect on air quality. One special flow can occur when a plume,
emitted close to the base of a stable layer, encounters a highly unstable
lower layer. In this case, rapid mixing takes place, potentially producing
high levels of ground concentration (fumigation) which .may be intensified by
the presence of elevated terrain. However, like other special flows (fanning,
coning, lofting and looping), fumigation requires the right set of conditions
of atmospheric turbulence structure and plume emissions.
To summarize, limited meteorological measurements have been made for the
oil shale region, and site specific information is generally lacking except
for the lease tracts. In another year or two more data may become available
*That part of the lower atmosphere in which surface induced stress decreases
with height, the Ekman layer usually extends to between 100 and 1000 meters
above ground level.
100
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from on-going baseline measurement programs. The data which are now available
show prevailing winds to be from the southwest, and inversions to occur fre-
quently at Grand Junction. Local flows are characterized by the mountain-
valley breeze systems. A plume emitted within the drainage flow of such a
system may lead to elevated concentrations at downwind receptors along the
valley floor. Other special flows such as fumigation may also pose a problem
but these require the right combination of turbulence conditions and emissions.
The most important circulation influence on ground level concentrations is
probably the drainage flows.
Air Quality: At present, there are very few anthropogenic emissions in
the oil shale region. Nevertheless, ambient levels of air pollution exceed
some state and federal standards. Measurements taken to date at Tracts U-a
and U-b in the Uinta Basin (21), show that ozone and nonmethane hydrocarbon
sometimes exceed the primary National Ambient Air Quality Standards (NAAQS).
However, the levels of most other pollutants are usually below the limits of
detection of common air monitoring instruments. At tracts C-a and C-b, parti-
culates, ozone and nonmethane hydrocarbons (NMHC) currently exceed NAAQS. The
most recent data (see Table 4-1) collected at Tracts C-a and C-b show that the
24-hour primary particulate standard was exceeded between 4 to 5 times, the
one hour oxidant standard was exceeded 5 times and the 6-9 am NMHC standard
was exceeded 94 times.
At Tracts C-a and C-b in the Piceance Creek Basin, the air quality is
generally similar to that in the Uinta Basin (Table 4-1). Based on periodic
measurements taken over several years (1) in the Piceance Creek Basin total
suspended particulates average 15yg per m3 annually, N02 averages 7yg per m3
annually, and SC^ less than 20yg per m3. These values are much lower than the
NAAQS (annual average of 75yg per m3 for particulates, lOOyg per m3 for N02,
and 80yg per m3 for S02). Hydrocarbon concentrations show seasonal fluctua-
tions with a maximum during the growing season. Tracts U-a and U-b show
similar annual averages: 22 yg per m3 for TSP, 10 yg per m3 for N0£ and 10
yg per m3 for S02-
A significant amount of haze has been observed in Parachute Creek Basin
and along the Colorado River Valley (2,17). The origin of this haze is unknown
at the present, but four mechanisms of formation have been suggested. First,
in both the Piceance Creek and Uinta Basins, relatively high levels of non-
methane hydrocarbons have been observed. These have been attributed to natural
sources such as sagebrush and other vegetation. Hydrocarbon and the N02 con-
centrations (low though they are) could contribute significantly to the high
photochemical oxidant values whTcfi are sometimes observed in the Uinta Basin.
The photochemical process, if it involves the 03-N02>cycle, may be accompanied
by visibility degradation. Second, under high relative humidity ( 50%) parti-
culates in the air could serve as condensation nuclei which can grow by hetero-
geneous nucleation into "visible" sizes of a few microns. The light scattering
of such "mixed" aerosols could explain the haze observed. Third, long range
transport of anthropogenic hydrocarbons and NOX, potential percursors of oxi-
dant (and haze), is also possible. Fourth, the intrusion of stratospheric
ozone into the lower troposphere is also a possibility especially at mid
latitudes where there is a break in the tropopause.
101
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Table 4-1. Existing Air Quality Data Summary for Federal Oil Shale Lease
Tracts (2,17,21)
Criteria Pollutant
Parti cul ate
Maximum 24 hour (yg/m3)
Annual mean (yg/m3)
No. occurrences
exceeding NAAQS*
S02
Maximum 3 hour (yg/m3)
Maximum 24 hour (yg/m3)
Annual mean (yg/m3)
Annual mean (yg/m3)
CO
Maximum 1 hour (yg/m3)
Maximum 8 hour (yg/m3)
NMHC**
Maximum 3 hour (yg/m3)
No. occurrences
exceeding NAAQS*
Oxidant
Maximum 1 hour (yg/m3)
No. occurrences
exceeding NAAQS*
Primary
National
Standard
150
75
1,300
365
80
100***
40,000
10,000
160
160
Tract
C-a
469
18
5
345
82
19
4
6,823
4,824
505
94
177
5
Tract
C-b
178
11
4
88
43
1
10
2,841
1,659
2,316
160
Tracts
Ua-Ub
127
22
40
25
10
10
5,200
3,900
1,970
138
190
42
*Nationa1 Ambient Air Quality Standards
**Nonmethane hydrocarbons
***Standard applies to N02
102
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4'1'2 rc1'*" M°de1 App1icat1on to 0" Shale Related Emissions in Colorado
4«.,*.!eC!!Itlyi.fev?rf1 "19delin9 efforts have been undertaken to predict the
impacts that oil shale mining and processing might have on ambient air quality.
The modeling concept most widely used in these studies has been the Gaussian
model which is described in several standard references (7, 8,9). In this model,
the basic equation describing concentration, X, from a continuous emissions
source at effective stack height, H, is given by:
X = "- H " pvn r- ' y'2 "-- [- i (^"-)2 ] + exp [- I (^)"]| (4-1)
where Q is the emissions rate, ay and a, the standard deviation of the plume
distribution in the horizontal arid vertical respectively, U the mean wind
speed, y the horizontal coordinate distance reckoned from the plume center-
line, and z the vertical coordinate distance reckoned from ground level.
The effective stack height, H, is related to the actual stack height, h,
by
H = h + AH (4-2)
where AH is commonly referred to as the plume rise height. Several methods
(10,11) have L,een developed to estimate this quantity. Typically, H depends
on stack parameters (effluent velocity and temperature, and stack radius), and
environmental conditions (atmospheric lapse rate of potential temperature
and temperature differential between plume and environment). The plume rise
formulation has long been a source of controversy, and the matter is still not
settled to the satisfaction of all.
Ap:lication of diffusion modeling must be done with all due care. The
problem being modeled is often times complex and requires simplifying assump-
tions in order to make the problem tractable. Uncertainties are frequently
associated with the source input data (meteorology and emissions). These
simplifying assumptions and uncertainties have led to the commonly held view
that "most model results are generally good to within a factor of two."
Battelle, Northwest Laboratories, conducted one of the earliest oil shale
modeling studies (12) for the Colony Development Operation. A model was
applied to a typical oil shale plant situated in the Parachute Creek Valley
and to Roan Plateau using diffusion data collected by Battelle and meteorolog-
ical data provided by Dames and Moore. Engineering Science, Inc. has also
conducted a study (13) of the Piceance Creek Basin for the Federal Energy
Administration to assess the air pollution potential of future oil shale dev-
elopment. Stanford Research Institute completed a similar study (14) for the
U.S. Environmental Protection Agency, but with the emphasis on controls. Most
recently, three other studies have been completed: Detailed Development Plan
(DDP) for Tract C-b submitted by the C-b Shale Oil Project (Roxana), DDP for
Tract C-a submitted by the Rio Blanco Oil Shale Project, and the DDP for tracts
U-a/U-b submitted by the White River Oil Shale Project (2,17,21).
103
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Battelle's Study of Parachute Creek and the Roan Plateau:(12) In the
modeling study of the Colony Development Operation in the Parachute Creek
Valley and on the Roan Plateau, Battelle used the exact form of the equation
shown earlier in equation 4-1. The standard deviations in plume distribution
oy and oz, were expressed in terms of observables, such as standard deviations
in anemometer and propeller wind vane fluctuations following methods developed
by others (8,15). Buoyant plume rise was formulated after a method developed
by Hanna (11).
The wind speed input for equation 4-1 was obtained from a 60m tower
measurement, while temperature and potential temperature lapse rates were
obtained from the Grand Junction radiosonde data. Total peak emissions for an
8000 m3/day TOSCO II plant (in kg per hour) were assumed to be: 65 SOg. 332
NOX, 136 THC (total hydrocarbons), and 583 PM (particulate matter).
The model was applied to a potential site in the Parachute Creek Valley,
and to another on the Roan Plateau. Model results indicate that for the
Valley site, N0£ concentrations will exceed NAAQS while S02 and particulate
concentrations will be just under standards. THC levels will be considerably
under NAAQS. For the plateau site, all concentrations are predicted to be an
order of magnitude less. Based on these results, Battelle recommended that
the proposed oil shale plant be located on Roan Plateau instead of in the
Valley.
Stanford Research Institute's Study of the Piceance Creek and Uinta
Basins (14)In a study to assess oil shale air pollution impact in the
Piceance Creek and Uinta Basins, SRI used the Climatological Dispersion Model
(CDM). Topographic effects were recognized as a potential influence, but were
not incorporated in the model. Pollutants treated were S02» THC and NOX.
Averaging times selected were those corresponding to air quality standards.
Meteorological inputs were obtained from observations at Grand Junction,
Colorado, for the Piceance Basin simulation and from Salt Lake City, Utah, for
the Uinta Basin simulation. For the worst case conditions, a meteorological
regime comprised of neutral atmospheric stability and a light wind of 1.5m
sec'l was assumed. Such conditions are found to persist over 24 hour periods
in the oil shale region and occur an average of 15 days/year.
In the actual modeling exercise the emissions from a 16,000 m3/day (or
100,000 barrels/day) TOSCO II type plant, assumed to be equipped with best
controls, were in kg per hour: S02 1400, NOX 1850, THC 272, and PM 295.
Following the recommendation of the Battelle study (12), SRI assumed that the
proposed plant would be located on a plateau. The results of the modeling
exercise show that a TOSCO II type plant equipped with best available con-
trols will not violate the federal ambient air quality standards for criteria
pollutants.
Under more stringent ambient air quality standards, such as those pro-
posed for a Class II region, (which seek to prevent significant deterioration
of ambient air quality in unpolluted areas) additional controls will be re-
quired. To meet the 24-hour particulate standard, 85% additional control will
104
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be requ1red;while the annual average S02 standard can only be met with 72%
additional control. No additional controls are required for hydrocarbons and
oxides of nitrogen.
SRI evaluated control technology for the Colony Development Operation
(TOSCO II type plant) and concluded that when best-available controls (cyclones,
baghouses and wet scrubbers) are employed, particulars and sulfur oxide emis-
sions can be reduced to one-third of the levels previously calculated by
Colony.
Federal Energy Administration Study (Piceance Creek Basin) (13): Modeling
of air pollution levels associated with oil shale development was conducted
by Engineering Science, Inc. under contract to the Federal Energy Administra-
tion. Three separate models were used in determining ground level concentra-
tions: up-valley wind model, gradient wind model and a fumigation model. All
of these models are Gaussian in nature. The up-valley model, APMAX, was used
to calculate short-term concentrations (3-10 minutes) which were then extended
to 1-hour averages using an empirical expression. The gradient wind model,
APSIM, was used to simulate annual averages by incorporating the wind flow
pattern and a stability frequency distribution function. In the fumigation
model, it was assumed that the plume would move down the valley at night with
the drainage flow and would be contained in a stable layer above the valley
floor. Then, with solar heating in the morning, the ground-based inversion
would be eroded upwards to the plume layer; whereupon, the plume would mix
within the ground-based layer to produce elevated ground level concentrations
(fumigation).
Emissions data were obtained from the developers and operators of the
proposed oil shale plants, from the Department of Interior, from the Environ-
mental Protection Agency emission factors, and from estimates by contractors.
Total emissions, in kg per hour, at a proposed plant site (TOSCO II process
at 8000 m3/day) were: 604 S02, 664 NOX, 144 THC, and 336 PM. Meteorological
data were obtained from the Atomic Energy Commission, Department of Commerce,
and Colony Development Operation. However, available meteorological data were
not adequate for defining important diffusion parameters in the Piceance Creek
Basin. Engineering Science, Inc., therefore, synthesized a wind-flow pattern
and frequency distribution for use in calculating dilution and dispersion of
released air contaminants.
The study evaluated the primary pollutants - S02, NOX, THC and PM. It
was found that under the Accelerated Development (which would produce up to
200,000 m3/day during the period 1980-1990), the primary and secondary stan-
dards for S02 as well as those promulgated for particulate matter and nitrogen
oxides would^e met. However, if the Colorado SO? annual standard* of 10 Mg/
m3 wire implemented, then a production limit of 32,000 m3/day would be required
unless more stringent emission controls could Be employed. The proposed EPA
Class II incremental limits for SOg and particulate matter will result in a
production limit of 56,000 m3 per day without better emission controls.
*This standard has since been changed to 15 wg/m3.
105
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The FEA study also considered a hypothetical plant based on Union A pro-
cessing technology. But the results are not reviewed here because Union B
technology, on which current plans are based, has emissions different in
nature and magnitude than those associated with Union A technology.
Colony Development Operation: The Colony Development Operation study (1)
used the modeling methods of the Battelle study (12) but with revised emis-
sions estimates. Average emissions for normal emissions, in kg per hour, were:
128 S02, 819 NOX, 147 THC and 376 PM; peak emissions were calculated to be
144 S02, 792 NOX, 138 THC and 382 PM.
The results of the study indicate that the proposed Parachute Valley plant
can cause an increase in concentrations (above background values) of 14% SOg,
0.01% HC, 25-100% NOX and 3-6% particulate matter. Higher ambient concentra-
tions may occur during plant start-up or during abnormal operating conditions.
Predicted annual mean concentrations due to plant emissions will not ex-
ceed Colorado's ambient air quality standards. The twenty-four hour S02 con-
centration may, however, exceed the State's short term concentration of 15yg
per m3 (24-hour average, not to be exceeded more than once in a 12-month
period). Also, the 24-hour predictions of 171 yg per m3 particulates (see
Table 4-3) will exceed the national secondary standard of 150 yg per m3.
C-b DPP (2): The Detailed Development Plan submitted by the lessees of
C-b lacks the details necessary to make a proper assessment as to the adequacy
of the modeling effort. However, the following information has been provided.
A Gaussian plume model was used to estimate concentration of S02» NOX, THC and
PM. Average meteorology was used, and the Brigg's (10) method was used for
treating plume rise.
Emissions assumed, in kg per hour, were: 121-160 SO?, 741-859 NOX, 119-
142 THC, and 352-439 PM. The results of the study indicate that plant opera-
tions will result in maximum increments over a 24-hour period of 9yg per m3
SO?, 34yg per m3 NOX, 5pg per m3 THC and 19yg per m3 PM. The authors of the
DDP concluded that based on the limited study "the best estimate is that com-
pliance with federal and state standards is achievable," and indicated that in
Phase II of the modeling study, "the entire modeling process is to be repeated
in more depth."
EPA, in a review of the DDP (16), identified three areas of deficiency:
too few details with respect to air pollution emissions and controls, inade-
quate modeling exercise, and the neglect of "fugitive" emissions. In attempt-
ing to provide guidance to C-b, the EPA ran their C7M3D model which includes
topographic effects, using Colony emissions data. The results indicated that
"state and federal air quality standards are predicted to be violated." The
developers of tract C-b are presently re-evaluating emissions control and are
doing further "worst-case" modeling.
Tract C-a DDP (17): The EPA Valley model (C8M3D) was used for simulating
air quality, with modification as necessary for making short-term (3-hour and
106
-------
24-hour) predictions. Plume rise was treated by Brigg's method (10). Emis-
sions for two phases of operations were considered. It was assumed that Phase
I operations wi 1 begin in 1979 with a small open-pit mine and a single TOSCO
II retort capable of processing 10,000 tonnes of oil shale per day and producing
approximately 720 nv* of pipelinableshale oil daily. It was further assumed
that by 1982 this capacity would be doubled to 1440 m3 per stream day
Phase II operations were assumed to begin by mid-1985, with a total processing
capability of 108,000 tonnes per stream day. Delayed coking and hydrotreating
is to be employed to produce upgraded shale oil at the rate of 8,98.2 m3 per
stream day. Emissions, in kg per hour, for Phase I were: 12 SO?, 146 NOX, 51
NMHC and 67 PM; and for Phase II: 120 S02, 451 NOX, 84 NMHC and 260 PM.
Modeling results indicate that Phase I operations will meet the NAAQS
and state standards for all criteria pollutants, except nonmethane hydrocar-
bons. The impacts of Phase II operations were found to be similar to Phase I,
except that the short-term ambient standards set by the State of Colorado
would be violated unless the area were classified Category II.
Ambient air quality was also simulated under fumigation conditions using
a multiple-source adaptation of the fumigation model (19). The predicted air
quality under these conditions was less sevendy affected than previously de-
scribed primarily because baseline monitoring has indicated fumigation to be
a transitory state (1 hour duration).
Tracts U-a/U-b (51): Two models were used for simulating air quality at
Tracts U-a and U-b. Short term (24 hours and less) concentrations were simu-
lated with EPA's PTMTP model while long term predictions were made with EPA's
C9M3D "Terrain" model. In the PTMTP application, 10 minute averages were cal-
culated and extended over longer averaging times (up to 24 hours) using statis-
tical concepts developed by Larsen (52). The "Terrain" model assumed as inputs
the actual terrain features in the vicinity of the proposed plant site. Both
model applications were conservative in their choice of meteorology, emissions,
stack height and other parameters so that predictions would represent worse
case conditions.
Detailed modeling was done for Phase IV type operations (100,000 barrels
per day of raw shale oil). Phase IV involves emissions (in kg per hour) of:
134 S02, 1242 NOX, 50 NMHC and 410 PM. Phase III production rate and emissions
will be one half those of Phase IV.
The model results indicate that, with the exception of hydrocarbons and
particulates, all short-term NAAQS will be met by large margins. Further, the
hydrocarbon emissions include those from the fines-type retort preheaters,
which may contain as much as 80 percent methane. If this were true, downwind
nonmethane hydrocarbon concentration may be as low as 11.8 yg per m3. Maximum
24-hour particulate levels were found to be 257 yg per m3 but exceeds the sec-
ondary NAAQS 150 yg per m3. Modeling results predict that all annual NAAQS
will be met.
Since ambient levels are directly proportional to emissions, Phase III
operations will lead to ambient levels which are roughly one half of those
predicted for Phase IV operations.
107
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4.1.3 Assessment of Models and Model Concepts Applied to Oil Shale Emissions
All of the studies reviewed in Section 4.1.2 have utilized the basic
Gaussian equation in one form or another. In the simplest of applications(12),
ground level concentrations were estimated using meteorological data measured
at a tower, and turbulence data collected during special diffusion studies.
The most ambitious modeling exercise to date (17) simulated long- and short-
term concentrations in the presence of topographic influences using input
meteorological data collected during baseline monitoring at tract C-a.
There are, however, several limitations of the Gaussian model. It is
known to overestimate ambient concentrations under calm conditions and at long
distances from the source, while underestimating near surface levels (19).
The overprediction under calm conditions may be attributed to the inverse de-
pendence of concentration on wind speed in equation 4-1 which physically re-
presents the neglect of convective mixing under calm conditions. To overcome
this limitation, similarity theory can be applied to the boundary layer (3).
In this method the standard deviation in plume distribution (oy and oz) would
be expressed in terms of mean wind speed, ground roughness and heat flux. Such
a parameterization would have the effect of removing the u-1 dependence (equa-
tion 4-1) since this will be coupled with the u dependence in the ay and az.
Overestimation at long distances probably reflects the absence of a mea-
sure of plume meander in the turbulence parameterization. Plumes traveling
over great distances commonly meander along the way, especially in the pre-
sence of topography. Such meandering will enhance plume dilution. Under-
estimation near the ground surface may be due to the mis-application of the
Gaussian concept rather than to shortcomings inherent in the concept. It is
well known that special meteorological conditions such as fumigation, looping,
etc. can cause high concentrations near the ground. Therefore, an acceptable
modeling exercise should incorporate such effects.
In its present form the Gaussian concept is difficult to apply to rugged
terrain. Such terrain has two effects on air pollution: first, it physically
alters air trajectory; and second, it increases the turbulence level. Tra-
jectory effects can take the form of streamline contouring around elevated
terrain or the form of down-siope-up-valley flows induced by mountainous ter-
rain. Streamline modifications due to topography are currently handled mech-
anistically as in the EPA Valley Model (C8M3D). The only convincing method of
treating the enhanced turbulence which results from rugged terrain has been
direct observation. However, direct measurements are all too often quite
expensive and could produce undesirable delays in making environmental assess-
ments .
In addition to the above mentioned limitations of the Gaussian model,
several other simplifying assumptions are implicit or explicit in model pre-
dictions. In the early model applications upper air data collected at Grand
Junction and Salt Lake City were applied to the Piceance Creek and Uinta
Basins, respectively. This is a Questionable use of data even though they
represent upper air measurements (especially over rugged terrain). This pro-
blem has been partially remedied by the site-specific measurements taken as
108
-------
part of the on-going baseline monitoring programs. In some models the time
averaged wind speed and prevailing wind direction are used. These quantities
are assumed to be constant over time. Also, wind measurements taken at one
point are frequently used to characterize the flow of the diffusing layer.
These represent obvious shortcomings which must be addressed prior to and dur-
ing model application.
Atmospheric diffusion modeling in general is limited in its ability to han-
dle particulates and reactive (or secondary) pollutants. When applied to parti-
culate emissions, a wide range of particle sizes must be considered. Particles
smaller than 20ym may be treated as a gaseous species while the larger ones
must recognize gravitational settling as an important removal mechanism.
Fugitive dust remains difficult to model for these reasons and also because
the emissions themselves depend on meteorology. Secondary pollutants such
as photochemical oxidant and aerosols cannot be handled by simple Gaussian
models, since formation of such substances in the atmosphere depends on sun-
light as well as precursor (and/or catalyst) concentrations.
Finally, all models are useful only to the extent that emissions data
are accurate and representative. Differing assumptions regarding emission
factors, plant size, sources covered, and normal vs. transient operations can
lead to dramatically different predicted concentrations of pollutants.
4.1.4 Comparison of Modeling Results
The emissions (kg per hour) used In the various modeling studies are
tabulated in Table 4.2. A comparison of modeling results is difficult be-
cause of the different assumptions with respect to processes (TOSCO II,
Paraho, etc.), plant configuration and size, and meteorological emissions fac-
tors. Certain generalizations may, however, be made. A typical shale oil
plant with a production capacity of 8000 nn per day can be expected to have an
hourly emissions of 100-150 kg SOe, 400-800 kg NOX, 80-150 kg THC and 250-400
kg PM.
The Colony Development Operation study used the modeling methods devel-
oped by Battelle, but with a different set of emissions (as may be seen in
Table 4.2). Of the two, Colony's emissions are the more recent (reported in
December 1975 versus October 1973 for the Battelle emissions), and are there-
fore, more realistic since they incorporate the most recent data. Colony
also estimated the average maximum emissions of the proposed shale oil plant
for Roan Plateau. These estimates were reported in 1974 (20), and in kg per
hour, are 144 S0£, 792 NOX, 382 PM and 138 THC.
The summary of the air quality modeling predictions are presented in
Table 4-3. Ambient air quality standards for major criteria pollutants are
likely to be violated according to the predictions. Sulfur dioxide will meet
federal ambient air quality standards at all sites but will exceed the federal
significant deterioration standard and Colorado's maximum allowable increments
at certain sites.
109
-------
Table 4-2. A Comparison of A1r Pollutant Emissions (kg per hour) Used 1n Modeling Studies
STUDY
Battelle (Parachute Creek and
Roan Plateau)
FEA (Plceance Creek
Basin)
SRI (Plceance Creek and
Ulnta Basins)
Colony Develop Operation (Parachute
Normal Creek and
Peak Roan Plateau)
C-b DDP (Plceance Basin)
C-a DDP (Plceance Basin)
Phase I
Phase II
U-a/U-b DDP (Ulnta Basin)
Phase II
Phase III*
PRODUCTION
mfyday
8,000
8,000
16,000
10.000
7,200
960
8.900
1,600
8,000
so2
KG per HR
65
604
1411
128
144
121-160
12
120
3.8
67
NOX
KG per HR
332
664
1850
819
792
741-859
146
451
49
621
THC
KG per HR
136
144
272
147
138
119-142
51
84
0.4
25
PM
KG per HR
583
336
295
376
382
352-439
67
260
31
205
*Phase IV Involves doubling of production and emissions from Phase III at Ua/Ub.
-------
Federal particulate ambient air quality standards are currently exceeded
at the lease tracts. Particulate increment increases forecast to occur at
these sites will also exceed the federal significant deterioration standards.
The measured hydrocarbon levels are currently quite high and occasionally ex-
ceed federal 6-9 am standards. Likewise, the forecast levels are also high at
all sites.
Although the modeling studies reviewed in this section differ in complex-
ity and assumptions, all studies have predicted that certain ambient air qual-
ity standards will be violated if oil shale development occurs. Currently,
levels of suspended particulates and non-methane hydrocarbons approach and
occasionally exceed short term ambient standards in the oil shale region, and
additionally emissions due to oil shale development will worsen the situation.
Significant deterioration and incremental increase standards for S02 may also
be violated. It might be commented that the emissions assumed in some of the
modeling exercises do not include sources such as fugitive dust emissions,
blasting emissions, and transient releases (such as would occur during plant
upset). Although difficult to quantify, these uninventoried contributions to
oil shale emissions suggest that the predictions in Table 4-2 are probably
underestimates of ambient levels.
Much can still be done to reduce ambient air quality levels resulting
from oil shale development and therefore to mitigate the impact on the air
environment. Better emissions controls in the future would directly reduce
ambient levels. Increased stack heights would provide a thicker diffusing
layer for plant effluents; and this, in turn, would lead to lower ground con-
centrations. Reduced plant size would lead to proportionately lower emissions
and therefore, lower ambient concentrations. Plants may be sited on terrain
which would favor diffusion and transport. One or more of the above features
may be combined to provide even greater reduction in ambient levels.
Ill
-------
Table 4-3.
Comparison of Modeling Results with Applicable Standards All Quantities in yg per m3
(References shown in parentheses) M
Pollutant
Sulfur Oxtdei
Nitrogen Dioxide
Partlculetes
(Corrected for
National Aablent
Annual b
24-hour
3-hour
1-hour
Annual
24-hour
Annual*
24-hour
3-hour
<6-9e»)
Maary
60
365
.
-
100
*
75
260
160
Air Quality Standard*
Secondary
.
-
1300
-
100
60
ISO
160
i1o.Deter1oratlonc
Clan 1
2
S
25
.
-
5
10
Clii* 11
IS
100
700
-
.
-
10
30
Colorado Aafctent Air Quality Standard*
Max. Alia
Category 1
3
IS
75
-
.
-
45*
ISO*
able Increment*
Category 11
IS
100
700
-
.
-
.
-
Category 111
60
260
1300
-
-
.
-
HaitM Aafctent Concentrations Predicted by Modeling
Battalia1
111)
-
25
-
-
12Sf
-
.
-
29
OJ)
10
so
240
300
10*
20
29h
Wi
<44
77
-
-
23*
"
<49
392
11
Colony
..
25
-
-
.
157.2'
.
171
47
C-b OOP* (2)
l/n Tract
-
9
-
-
-f
M
-
19
S
Off Tract
.
6
-
-f
28
-
IS
4
C-a POP1 (17)
rRalal
(Staga 2)
10
23
91
~
16
16
34
221
mate u
11
28
103
*
10
22
41
129
""JoT" (51)
12.66
46.9
156
-
19.93
"
SS
257
538.9"
ro
itrlc man.
Arlthmtlc mn.
NaxIwB alloMbla Fadaral IntraHnti for area clatiai (Plctanca Cratk Batln
tubjtct to Clui II regulation*).
NaxIwB alloxabla arttlMtlc van Ineraamitt ovar battllna.
Na>1>uB allombla aslant air concantratlon.
Rapreiaoti HO,
tepraiants THC.
Includai a background valua of 14 «g par m3.
Eicludn background conctntratton
Ineludts background concantratlon,
Plant contribution (Sb.9 ug par >) Includti unknown aaount of aatnana; background contribution (480 ug par a3) auludat CHy
Pradlcud off tract ooncwtratlon Incluilvt of background
ConotntratlOM, Including background. Hda at 100-SOOO downwind. Concentration! asiuaD Phata IV typ* optratlon (100,000
barreli par day). Concentrations froa Phaia III typa oparattoni will ba roughly ona naif thota of Phaia IV
" Rtpratantt projactloni for tno onUi of July, excluding background.
-------
4.2 IMPACTS ON WATER QUALITY AND HYDROLOGY
Commercial development of Green River oil shale can have impacts on local
and regional surface and ground water quality and flows. Diversion of water
for consumptive use in the upper Colorado basin can adversely affect the aver-
age discharge and quality of water in the lower Colorado basin. Direct and
indirect wastewater discharges may degrade local water quality and change the
existing hydrologic regime. This chapter includes a review of existing sur-
face and ground water quality and flows in northwestern Colorado and north-
eastern Utah, a summary of predicted affects of consumptive water use for oil
shale development, a summary of water pollution control plans for major devel-
opments, and a discussion of potential indirect and accidental sources of water
pollution associated with the oil shale extraction, processing, and waste dis-
posal activities.
4.2.1 Existing Surface Water Quality and Flow
The major rivers and streams in the oil shale region are the White River
and its tributaries - Piceance and Yellow Creeks, and the Colorado and its
tributaries - Roan and Parachute Creeks.
4.2.1.1 Upper Colorado River Basin
The oil shale regions of Colorado and Utah are located in the Upper Colo-
rado River basin and includes all of the drainages of the Colorado River above
Lee's Ferry, Arizona and encompasses an area of approximately 50,000 sq. km
(19,500 square miles). In the upper basin, 77 percent of the area receives
less than 50 cm (20 inches) of precipitation, and 42 percent receives less
than 30 cm (12 inches) (22).
Water quality and discharge are monitored by the U.S. Geological Survey
at more than 50 stations in the Upper Colorado River basin on the larger tri-
butaries and main stem of the Colorado River. Basic data are published annu-
ally for each state. Table 4-4 summarizes discharge and water quality data on
the White and Colorado Rivers at location nearest the Colorado and Utah oil
shale regions.
4.2.1.2 Piceance Creek Basin
A major east-west trending topographic divide just south of the Rio
Blanco-Garfield County line separates the streams draining the Piceance Creek
basin into two drainage systems. The northern part of the basin is drained
by tributaries of the White River (Piceance and Yellow Creeks). The southern
part of the basin is drained by tributaries of the Colorado River (Parachute
and Roan Creeks). Figure 4-1 shows the location of proposed oil shale devel-
opment activities relative to the surface drainage systems.
Streamflow in the Piceance Creek basin is typical of those regions where
the main source of water is snowmelt. Starting in March or April, snowmelt
produces a period of high runoff that extends to June or July. During the
remainder of the year, streamflow is maintained almost entirely by ground
water discharge. The surface-water/ground-water systems in the Piceance Creek
113
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Table 4-4. Water and Dissolved Solids Discharge at Selected Stations in
Upper Colorado River Basin C22)
Dissolved Solids
Location
White River
near Meeker,
Colo. (1)
White River
near Watson,
Utah (2)
Colorado River
near Glenwood
Spr., Colo.
(loc.off map)
(3)
Colorado River
near Cameo, C
Colo. (4)
Drainage
Area
(sq.km)
(sq.mile)
1974
(762)
10400
(4020)
11600
(4486)
20900
(8060)
Average
Weighted Annual
Average Annual AF Average Discharge
(m3/min) (109 m3) Concentration (tonnes/yr)
(cfs) (acre-ft) (mg/1) (tons/yr)
1080
(638)
1300
(764)
4080
(2399)
4138
(4138)
0.57 224
(462,200)
0.68 439
(553,500)
2.14 270
(1,738,000)
3.7 387
(2,998,000)
139,000
(153,400)
300,000
(330,000)
581 ,000
(639,200)
1,430,000
(1,578,000)
( )See Fig. 4-1 for location
basin are intimately related; ground water discharge accounts for about
80 percent of the volume of stream flow (23).
Piceance and Yellow Creeks: Flows in Piceance and Yellow Creeks are
highly variable and strongly influenced by irrigation practices. Table 4-5
summarizes stream flow records at four locations on Piceance Creek and one
location on Yellow Creek. Mean annual discharge of Piceance and Yellow Creeks
into the White River i.s 14,520 and 1,130 acre feet, respectively.
The upper reaches of both Piceance and Yellow Creeks surface waters can
be classified as a mixed bicarbonate type, grading to a sodium bicarbonate
type in the lower reaches. Concentrations of dissolved solids, sodium, chlo-
ride, and fluoride all increase in the downstream direction. In general,
water quality is best during periods of high discharge but the chemical char-
acter remains about the same. The total dissolved solids (TDS) concentration
in Piceance Creek ranges from 440 to 5700 mg/1; the TDS content in Yellow
Creek ranges from 1400 to 3000 mg/1 (25). The sulfate and dissolved solids
concentrations exceed the public water supply limits in the upper reaches of
both creeks and water in the lower reaches has fluoride concentrations of more
than twice the limit of 1.0 mg/1 established by the U.S. Public Health Service
(27).
114
-------
OUTCROP
MAHOGANY
LEDGE
PARACHUTE CR
OUTCROP
MAHOGANY
LEDGE
SHOWING LOCATION OF
SELECTED STREAM GAGING
STATIONS AND CONTEMPLATED
OIL SHALE DEVELOPMENTS
A STREAM GAGING STATION
Figure 4-1. Location of Selected Stream Gaging Stations and 011 Shale Developments
-------
Table 4-5. Summary of Piceance and Yellow Creek Stream-flow Records (25)
Location
Piceance Creek
at Rio Blanco
(4)
Piceance Creek
below Rio Blanco
(5)
Piceance Creek
below Ryan Gulch
(6)
Piceance Creek
at White River
(7)
Yellow Creek
near White
Ri-er (8)
Period
of Record
10/52-9/57
10/40-9/53
10/64-9/67
10/64-9/66
10/64-9/66
Drainage
Area
(sq.km)
(sq. miles)
23
(9)
396
(153)
1256
485
1629
(629)
668
(258)
Average
Discharge
m3/min (cfs)
2.4
(1.4)
35
(20.3)
21
(12.2)
29
(17.0)
2.3
(1.37)
Extremes of
m-Ymi n
Max
39
(23)
731
(430)
680
(400)
935
(550)
1802
(1060)
»
Discharge
(cfs)
Min
0.2
(0.1)
0.2
(0.1)
1.4
(0.8)
1.3
(0.9)
0.0
(0.0)
i
( ) See Figure 4-1 for location
Roan and Parachute Creeks: Roan and Parachute Creeks have peak flow
during spring snowmelt and low flows during autumn and winter (26). Although
Roan Creek flows throughout the year, Parachute Creek is often dry from Dec-
ember through April. Table 4-6 summarizes streamflow records at three loca-
tions on the Parachute Creek drainage and three locations on the Roan Creek
drainage. Average annual discharges of Parachute Creek and Roan Creek into
the Colorado River are about 14,000 and 26,000 acre feet of water, respectively.
Chemical analyses of waters from Parachute and Roan Creek show the streams
to have similar water quality characteristics. Dominant ions are calcium,
magnesium, sodium, bicarbonate and sulfate; TDS content increases in the down-
stream direction. Disproportionate increases in sulfate content are observed
in the lower reaches of both streams.
4.2.1.3 Uinta Bastn
The oil shale deposits of the eastern Uinta basin are drained by the
White River. Most of the flow in the White comes from snowmelt in the Colorado
mountains. Local streams contribute very little water to the White. Stream-
flow records for the White River near Watson, Utah show a mean discharge of
about 750 cubic feet per second. Dissolved solids concentration ranges from
209 to 2380 mg/1 (24); the discharge-weighted mean is about 426 mg/1.
116
-------
Table 4-6. Summary of Roan and Parachute Creek Streamflow Records (25)
Station Location
(Number refers
to Fig. 4-1)
W. Fork Parachute
Creek (9)
Parachute Creek
near Union
Operation (10)
Parachute Creek
near Grand Valley
(11)
Roan Creek above
Junction with
Clear Creek (12)
Clear Creek above
Junction with
Roan Creek (13)
Roan Creek near
De Beque (14)
Period
of Record
10/57-9/62
10/48-9/54
10/64-9/67
4/21-10/27
10/62-9/67
7/66-9/67
5/21-9/26
Drainage
Area
(sq.km)
(sq. miles)
124
(48.1)
374
(144)
518
(200)
391
(151)
287
(in)
831
(321)
Average
Discharge
m3/min (cfs)
7.43
(4.37)
30.0
(17.7)
51.5
(30.3)
25.2
(14.8)
«__
68.0
(40.0)
Extremes of
m^/min
Max
250
fc» W W
(147)
1255
(738)
1550
(912)
1360
(800)
2618
(1540)
2074
(1220)
Discharge
(cfs)
Min
n
V
o
o
1.7
(i.o)
0
5.4
(3.2)
Streams in the Ujnta basin, which originate in the area of the oil shale
deposits* drain relatively low elevation watersheds. Consequently, except
during periods of snowmelt or thunderstorms, local streams are dry or almost
dry. Water quality of the local streams is generally poor. Boron, hardness
and sulfate concentrations are high. IDS content is highly variable as a func-
tion of flow, and during late summer and autumn often exceeds 5000 mg/1 (31).
Lease Tracts: The existing surface water quality at the federal lease
tracts is summarized in Table 4r7. Maximum dissolved solids levels have ex-
ceeded the proposed water quality criteria at all the lease tracts. Fluoride
has exceeded drinking water standards at tracts C-a and C-b; boron has exceed-
ed agricultural standards at C-a. However, in many cases, the data in Table
4-7 represent a small number of samples. Mean annual discharges of Piceance
and Yellow Creeks into the White River are 14,520 and 1,130 acre feet, respec-
tively.
4.2.2 Existing Ground Water Quality and Yields
4.2.2.1 Piceance Creek Basin
t Bedrock Aquifers: Two bedrock aquifer systems are present in the
Uinta and Green River formations of the Piceance Creek basin. The upper
aquifer is present over the entire basin and is comprised of the fractured
117
-------
Table 4-7. Maximum Values for Dissolved Constituents of Surface Waters on
and Around Federal Oil Shale Lease Tracts (31,40,41)
Parameter
Dissolved
Solids
Boron
Copper
Cyanide
Arsenic
Ban* urn
Cadmi urn
Chromium
Lead
Mercury
Nitrate as N
Selenium
Silver
Fl uoride
Units
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Water Quality
Criteria1
i 500-1000 I(sH
12000-50001 (t)J
0.51
IO-.2I)
11. OM/
f0.005A\
10. 2M J
Drinking Water
Regulations *
0.05
1.0
0.010
0.05
0.05
0.002
10
0.01
0.05
(3)
C-a
2470
0.77
0.008
0.02
0.009
0.40
0.003
0.080
0.009
0.001
2.2
0.006
0.002
10
C-b
1450
0.330
0.010
0.03
0.005
0.20
0.006
0.020
0.011
0.0008
1.9
0.005
1.3
Ua-Ub
536
0.090
0.013
0.01
0.002
0.140
0.004
0.010
0.005
0.0002
0.38
0.002
0.000
0.3
1) Proposed Criteria for Water Quality, Volume I, October 1973, U.S.
Environmental Protection Agency
2) Federal Register, Wednesday, December 24, 1975, Environmental Protection
Agency, Water Programs, National Interim Primary Drinking Water Regula-
tions Maximum Contaminant Levels.
3) Limits on fluoride depend upon annual average air temperature. Allow-
able fluoride concentration range: 1.4 mg/1 @ 90.5°F to 2.4 mg/1 @ be-
low 53.70F.
I = Irrigation (t) tolerant crops; (s) sensitive crops
M = Municipal drinking water
A = Aquatic life
118
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lean oil shales of the Green River formation and overlying fractured marl-
stones, siltstones and sandstones of the Uinta formation, above the Mahogany
zone. The lower aquifer consists of fractured and leached oil shale below
the Mahogany zone and is best developed in the north central part of the basin
where it is commonly called the "leached zone." The Mahogany zone appears to
impede flow between the two aquifers over most of the basin.
The total amount of ground water in the Piceance Creek basin has yet to
be accurately determined. However, the Department of Interior estimates that
the basin may contain as much as 25 million acre feet of water in the upper
aquifer (24). Weichman estimates that the lower aquifer may contain as much
as 25 billion cubic meters (20 million acre-feet) of water (28).
Ground water movement in the basin parallels surface stream flow. North
of the topographic divide that separates the Piceance-Yellow Creek and Para-
chute-Roan Creek drainages, surface and groundwater movement is to the north.
South of this divide, ground water movement is toward the south.
Most of the aquifer system recharge comes from melting of the heavy snow-
pack found at higher elevations around the margin of the basin. In these re-
charge areas water percolates downward into the upper aquifer through the
Mahogany zone and into the lower aquifer charging both aquifers. The ground
water then moves laterally to the discharge areas.
In the northern part of the basin, water moves upward from the lower
aquifer through the Mahogany zone and into the upper aquifer, and is then dis-
charged into the alluvium of Piceance and Yellow Creeks, ultimately reaching
the surface. At the southern margin of the basin, most of the water is dis-
charged by springs along the sinuous line of cliffs near the top of the Mahog-
any zone.
Using limited hydrologic data obtained from test wells, the USGS and
others have made model studies of the hydrologic system of the Piceance Creek
basin to estimate the quantity of water that will be produced in conjunction
with mine dewatering, and to determine the effects of dewatering on the sur-
face and subsurface hydrologic regimes. It is estimated that in the northern
part of the basin, discharge rates of more than 1.7 m3 (50 ft3) per second may
be required to keep the mine workings dry (23,30). The net result of this water
removal over a period of years will be to locally reduce spring and streamflow.
In the southern margin of the basin, the quantity of water produced by dewater-
ing will be considerably smaller by comparison and the effects will be more
localized.
Although the chemical quality of the groundwater in the Piceance Creek
basin varies widely, both the upper and lower aquifers can be classified as
containing sodium bicarbonate type water, and the concentration of dissolved
solids generally increases in the direction of flow.
In the recharge areas, the dissolved solids content of upper aquifer
waters average about 500 mg/1. At the northern discharge area the dissolved
119
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solids content of upper aquifer water averages about 2000 mg/1. At the south-
ern discharge areas, the dissolved solids content of the upper aquifer aver-
ages about 1000 mg/1. Fluoride content of the upper aquifer often exceeds 10
mg/1 in the northern part of the basin; but averages less than 0.5 mg/1 at the
southern margin.
The dissolved solids content of the lower aquifer increases both with
depth and in the direction of flow. In the recharge area the dissolved solids
concentration of the lower aquifer is of the order of 1000 mg/1. This in-
creases to more than 30,000 mg/1 at the discharge area at the northern margin
of the basin. In individual wells in the north central part of the basin,
the dissolved solids content of water taken near the top of the lower aquifer
is as low as 2000 mg/1 while in samples taken near the base of the "leached
zone" the dissolved solids content is more than 80,000 mg/1. The ground water
in the lower aquifer contains exceptionally high concentrations of dissolved
fluoride, with an average level of nearly 10 times the recommended value for
most uses. The areal distribution of fluoride has no discernible pattern.
Alluvial Aquifers: The alluvial aquifers in the Piceance Creek basin
are limited to valley bottoms along creeks. These aquifers are generally less
than .8 KM (0.5 mile) in width and less than 43 M (140 feet) thick. Although
the alluvium is capable of transmitting and storing more water per unit
volume than the bedrock aquifers, the areal extent is small. Consequently,
high discharge rates can only be maintained briefly. Water 1n the alluvium
occurs both under water-table and artesian conditions, depending upon the
occurrence of clay beds.
The alluvial aquifers are recharged by precipitation, applied surface
water, streams and infiltration from bedrock aquifers. The aquifer discharges
to streams, springs, and wells and to the atmosphere by evapotranspiration.
Water in the alluvium has about the same chemical character as water in
the stream, but usually exhibits a higher dissolved solids concentration.
Along Piceance Creek, dissolved solids content ranges from less than 500 to
more than 8000 mg/1. Water in the alluvium of Yellow Creek and Parachute
Creek includes calcium, magnesium, sodium, bicarbonate and sulfate. The
dissolved solids concentration of the water is sometimes as much as 7200 mg/1.
The sulfate concentration of a water sample near the mouth of Roan Creek was
4200 mg/1 (25).
Table 4-8 summarizes the groundwater quality data which have been col-
lected at lease tracts C-a and C-b. Dissolved solids, fluoride, and boron
levels in the lower aquifers exceed water quality criteria and/or drinking
water standards at both tracts. Boron and copper in the alluvial aquifer at
tract C-a exceed irrigation standards while cadmium and lead exceed drinking
water standards. The data in Table 4-8 represent a limited number of analyses
for many constituents, and may not be completely representative.
120
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Table 4-8. Mean Values for Dissolved Constituents in Groundwater on Federal Oil Shale Lease Tracts
C-a and C-b (15,17,40)
Water c"a
Parameter Units Quality Criteria1 Alluvial Aquifer 011 Shale Aquifers
Dissolved mg/1 500-1000 I(s)
Solids 2000-5000 l(t)
Boron mg/1 0.5 I
Copper mg/1 0.2 I
1.0 H
Cyanide mg/1 0.005 A
mg/1 0.2 M
Drinking
Water Regulations2
Arsenic mg/1 0.05
Barium mg/1 1.0
Cadmium mg/1 0.010
Chromium mg/1 0.05
Lead mg/1 0.05
Mercury mg/1 0.002
Nitrate as N mg/1 10.
Selenium mg/1 0.01
Silver mg/1 0.05
Fluoride mg/1 (3)
1. Proposed Criteria for Hater Quality, Volume
1190.000
1.250
.524
.524
.002
.002
.000
.003
.028
.000
.398
.000
6.600
.000
.006
.367
I. October 1973, U
2. Federal Register, Wednesday, December 24, 1975, Environmental
Water Regs, Maximum Contaminant Levels
3. Limits on fluoride depend upon annual average air temperature.
to 2.4 mg/1 0 below 53.7oF.
I Irrigation (t) tolerant crops; (s) sensitive
M « Municipal drinking water
A - Aquatic life
*Mean chemical concentration based on swab tests
crops
Upper Lower
1140.000 1550.000
.692 1.830
.027 .018
.027 .018
.000 .005
.000 .005
.004 .001
.000 .000
.002 .001
.005 .000
.353 .647
.000 .000
.534 .765
.000 .000
.007 .003
4.090 13.700
C-b
Alluvial Aquifer 011 Shale Aquifers
1000.000
.720
__..
.006
.090
....
.026
.003
3.100
.97
Upper
560.000
1.500
.014*
.100*
.013*
.001*
.470*
18.000
Lower
750.000
3.000
----
.030*
1.000*
.034*
.001*
.700*
.
19.000
.S. Environmental Protection Agency.
Protection AGency, Water Programs, National
Allowable fluoride
concentration range: 1
Interim Drinking
.4 mg/1 3
90.50F
of saturated sequence In question.
ro
-------
4.2.2.2 Uinta Basin
Little information is available on the ground water hydrology of the
Uinta basin. Hydrologic test information from a few scattered wells indicate
that groundwater can be found in the sandstone and si Itstone beds above and
below the oil shale and within fractures of the oil shale. However, based
on current data, it is unlikely that any of the aquifers contain significant
amounts of water.
The Green River formation probably contains more water than any other
formation in the Uinta basin. Several aquifers have been identified in
test wells, but the lateral extent of these zones has yet to be determined.
Hydrologic investigations in connection with the U-a and U-b baseline
studies have established the presence of an aquifer about 100 feet thick
lying about 350 feet above the Mahogany zone (21). The aquifer crops out along
the White River and Evacuation Creek and extends an undetermined distance
northwestward beyond the tract boundaries. The aquifer is recharged along
the outcrop; the discharge area is not known. Ground water movement is to
the northwest. Pump tests run in 4 holes yielded from 18-6500 liters (5 to
1750 gallons) of water per minute, with dissolved solids content of the pro-
duced water ranging from 1000 to 3500 mg/1 (31). Elsewhere in the basin, the
Green River formation has yielded only small quantities of water with up to
72,000 mg/1 dissolved solids content.
4.2.3 Effects of Water Withdrawal by Oil Shale Development on the White and
Colorado Rivers
One estimate of the total supply of surface water available to the oil
shale developments is estimated at 526 million m3 (427,000 acre-ft) per year
(13). This supply of water would be derived primarily from two river basins,
the White River and the Colorado River. The major potential developments that
may utilize water from the White River basin are: Colorado federal oil shale
lease tracts C-a and C-b, Utah federal oil shale lease tracts U-a and U-b,
TOSCO (sand wash), and Superior Oil Company. The developments that will
likely obtain thefr water from the Colorado River Basin are: Occidental Oil
Company (modified in-sttu development}, Colony CTOSCO II) development, Union
Oil Company of California and the Paraho Gas Combustion demonstration plant at
Anvil Points near Rifle, Colorado.
Although the exact water requirement for each of these developments at
their full scale operation is uncertain at the present time, it has been esti-
mated that for every cubic meter of oil produced, an approximate average of
3.7 cubic meters of water will be required (see Section 3.2.1). If this
approximation is realistic, then surface water might support an oil shale in-
dustry producing about 390,000 m3/day (2.4 million barrels/day) of shale oil.
However, the shale industry will Rave to compete with agriculture, mining, In-
dustry, and urban users for this surface water.
Some of the water requirements for development will be met by ground-
water sources in the Piceance Basin. Deeper aquifer water may be considered
"geologic" water and its withdrawal for consumptive use may have little or
122
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«?n! I I* ace °WS' However» shallow aquifer water withdrawal for
mine dewatering purposes and process needs will likely diminish local surface
flows, and ultimately, the flows in the White and Colorado Rivers. For the
nrst phases of oil shale development, lease tracts C-a and C-b, Superior Oil
Company will use entirely or primarily groundwater to supply process needs.
The extent to which surface water must supplement groundwater for expanded
operations is not known at present.
One effect of withdrawing water from the White and/or Colorado Rivers is
a potential salinity increase downstream. Since the White River merges with
the Green River and ultimately the Colorado River, the effects of increased
salinity will be seen at downstream reservoirs on the Colorado River (e.g.,
Hoover or Imperial Dam). In general, salinity of the water will increase
progressively from the head waters to the lower reaches of the Colorado River.
Two factors contribute to increased salinity: (1) increased salt loading, and
(2) salt concentration. Salt loading is caused by both natural and manmade
sources which contribute salts to the rivers. Salt concentrating effects are
produced by removing and consuming relatively high quality water or by eva-
poration in reservoirs and in irrigation systems, thereby concentrating salts
into a lesser volume of water.
Several estimates have been made of the effects of individual oil shale
development projects on the salinity in the Colorado River. Results of these
estimates indicate that the salinity increase due to the individual with-
drawals in no case exceeds 7.0 mg/1 of total dissolved solids at Imperial Dam
(13). One estimate for a 40,000 m3/day (250,000 bbl/day) oil shale industry
shows a salinity increase of 1.0 mg/1 at Hoover Dam (14). According to the
final EIS of the Department of Interior for a prototype oil shale leasing pro-
gram, the salinity at Hoover Dam will increase by about 10 to 15 mg/1 for a
1,000,000 bbl/day (160,000 m3/day) oil shale industry requiring 149 million m3
(121,000 acre-ft) to 233 million m3 (189,000 acre-ft) of water per year (24).
It is possible that certain oil shale withdrawals may actually enhance
water quality in the Colorado system by consuming high dissolved solids water
which would otherwise reach surface waters. Consumptive use of Piceance Creek
water (for example, by Superior Oil Company in the Northern Piceance Basin)
may improve the quality of the White River below its confluence with Piceance
Creek. (Tables 4-4 and 4-7 show the approximate dissolved solids levels for
the White River and for Piceance Creek near tract C-b, respectively). The
Rio Blanco oil shale project (tract C-a) has indicated that oil shale develop-
ment on that tract will actually cause a decrease in salinity in the lower
Colorado system via use of saltne groundwater which would otherwise reach the
White River (see Table 4-8 and Reference 17).
Based on the above estimates, salinity increase due to consumptive with-
drawal for oil shale development is expected to have minimum impact on exist-
ing water users (including municipal, industrial, agricultural, hydroelectric,
recreational users). More significant water Quality impacts on either the
White or the Colorado Rivers may result from (1) uncontrolled leachate reach-
ing groundwater or draining into surface streams leading to the rivers and
(2) failure of holding ponds or disposal pile. A discussion of these poten-
tial impacts may be found in other sections of this report.
123
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4.2.4 Effects of Development on Local Surface and Groundwater
All of the proposed programs for oil shale development announced to date
have set forth a policy of no direct discharge of wastewaters during commer-
cial operations. However, even if this policy is strictly followed, other
potential sources of pollution may exist. Some activities, which have no
effluent products, may indirectly affect water quality. Accidents may also
cause the release contaminates into the ground or surface waters.
Water can be indirectly contaminated by activities which unbalance the
existing hydrologic regime. Water can also be indirectly contaminated by the
failure of systems designed to contain or confine direct effluents. Acci-
dental leaks, spills, and dam overflows may contaminate surface streams.
Most of the activities that could cause or lead to indirect water pollu-
tion are common to several or all of the proposed developments. These non-
site specific activities along with the proposed plan for mitigating water
quality degradation are discussed below. Site specific activities and pro-
posed mitigation plans are discussed in the succeeding section. Accidental
sources of water pollution and control plans are discussed in the last section.
General Indirect Water Pollution Sources and Control Plans (1,2,17,24)
Construct!'on Activities: Irrespective of location, construction acti-
vities will be a necessary part of all oil shale developments. Construction
activities include the development of the mine and plant sites, establishment
of the processed shale and overburden disposal areas, development of ore stock-
piles, upgrading of existing roads, and construction of new roads, service
corridors, dams, reservoirs, etc. The major effects of these landscape modi-
fications will be to increase runoff which will, in turn, lead to increased
erosion and sediment load in local streams. Concentration of dissolved solids
in the runoff may also be higher than that from undisturbed terrain, depending
upon the nature and properties of the surfaces that are exposed.
In order to prevent runoff waters from modified land surfaces from enter-
ing streams, dams will be built downstream of the construction activities.
The waters collected by these structures will be used on site. Other water
control structures will be built to prevent erosion and control sedimentation
as needed. In general, stream sediment load and siHation will be minimized
by disturbing vegetation and soil as little as possible by contour grading
and by installing catchment basins and initiating restoration activities as
soon as feasible.
Mining Activities: The mining of oil shale can indirectly affect
water quality in several ways. Mining will necessitate dewatering when opera-
tions make contact with the aquifer. Dewatering has two important aspects:
(1) groundwater produced by the dewatering could pollute streams if not con-
trolled and (2) dewatering could reduce or dry up spring and stream flow.
Also, subsidence of underground workings is a threat to the surface and sub-
surface waters. Rupturing of strata that naturally impedes vertical flow
124
-------
could allow poor quality water to reach the surface. Subsidence of the land
surface would alter stream course and increase sediment and dissolved solids
content.
Proposed development plans indicate that during full-scale operations, all
water from dewatering operations (supplemented by water from outside sources)
will be utilized in processing and for retorted shale disposal. During pre-
commercial development, however, surplus water may be obtained from the de-
watertng operations. Depending upon amounts and location, several techniques
will be used to handle this surplus water. These include: (1) storage with
eventual later on-site reuse, (2) treatment to stream water quality standards
and release, (3) use in construction, and (4) reinjection into the aquifers.
Because dewatering may diminish or dry up spring or stream flow, natural
surface water augmentation is planned where necessary. Several options are
available for providing this water such as: (1) release of supplemental water
from upstream sources through natural stream channels, (2) additional develop-
ment of groundwater sources, and (3) haulage, pipelines, or canals.
The effects of subsidence on surface and subsurface water quality are not
fully understood at this time. Consequently, underground workings have been
designed to minimize subsidence.
Processing Activities: Processing produces a variety of waste mater-
ials that potentially could degrade water quality. The sources and character-
istics of these solid and liquid wastes and plans for their disposal so as to
prevent effluent discharge from directly entering surface waters are described
in previous sections of this report (Sections 3-2 and 3-3). Generally, pro-
cess wastewaters are not planned to be directly discharged. During plant up-
sets or accidental equipment failure, process wastewaters may be directly dis-
charged to surface waters.
t Retorted Shale Disposal: Contamination of surface and groundwaters
by salts, organic substances and trace constituents can occur as a result of
erosion of, runoff from, and percolation through retorted shale. Such con-
tamination may adversely affect the quality of water from other uses in the
upper Colorado Basin (e.g., Irrigation) and add to the salt loading of the
lower Colorado Basin.
Like natural terrain, a disposal pile will be subject to surface erosion
and runoff during storms and snowmelt. Soluble substances, particularly in-
organic salts can be mobilized from retorted shale along with suspended mater-
ial during the erosional process. About 10 kg/tonne (20 Ibs/ton) of salt
(primarily sodium sulfate) is water soluble in fresh, carbonaceous retorted
shales (Table 3-14). Burned shales may contain larger quantities of soluble
salts. Further, additional soluble substances are added to retorted shale in
the form of process water (about 1 kg soluble salts/tonne of processed shale
(D).
Natural erosion in the Piceance Creek basin averages about 7 tonnes/
hectare/year (3 tons/acre/year), although wide variations occur as a function
of slope, storm frequency and intensity, vegetative cover, and properties of
125
-------
the local soils (44). Retorted shale subject to "average erosion" in the
Piceance basin might contribute 70 kg (150 Ibs) of salt along with 7 tonnes
per hectare of suspended material to surface waters annually.
Although retorted shales have low permeability (Table 3-13), water has
been shown to penetrate into retorted shale piles (43). Winter freeze-thaw
cycles can significantly reduce compaction densities, creating greater per-
meability in the upper portion (! meter) of a pile than was originally the
case.
Water will be normally applied to the surface of a disposal pile as part
of the revegetation program (to supply water requirements of vegetation and
to leach soluble salts to below the root zones). Such water applications en-
courage the establishment of capillary structure in TOSCO II retorted shale
which allows both upward and downward migration of water. Salty deposits
(mainly sodium and calcium sulfate) are occasionally observed as a thin crust
on the surface of disposal piles between irrigation applications, particularly
during hot weather when surface evaporation is high. These salty deposits
will be partially dissolved by rain or snow and will add to the salt load of
surface runoff.
Salts may also be solubilized by water percolating through retorted shale.
Laboratory experiments have demonstrated that less salt is generally Teachable
from freshly retorted TOSCO II in percolation tests than in "blender" or
"bottle" tests. The hydrophobic nature of carbonaceous retorted shale is
thought to encourage channeling and inhibit thorough water-shale contact in
the percolation tests. If TOSCO II retorted shale is wetted and then allowed
to dry, a capillary structure is established which allows a more complete
re-wetting at a later time. Upon prolonged water saturation, carbonaceous
retorted shale loses some of its hydrophobic properties.
TOSCO II retorted shale can apparently allow percolation of water to
occur, even when the pile is under-saturated with water. Freeze-thaw induced
permeability increases in the surface layer of a pile over time, and the
ability of the shale to allow downward water migration may contribute to deep
water infiltration and capillary structure development (42). Water migrating
through a pile can continue to dissolve salts until a concentration of about
1400 mg/1 is attained in the interstitial solution. Percolate water, with a
steady state dissolved solids content, may eventually mix with other ground-
water, and/or reach surface waters.
Burned shales (e.g., gas combustion retorting) have little or no carbon-
aceous coating, and carbonate minerals have been partially calcined. Such
shales are less hydrophobic than TOSCO II retorted shale, and contain salts in
a more readily soluble form (42,43). Although fewer runoff and infiltration
experiments have been conducted with burned shales than with TOSCO II shale,
the results indicated that salts can be leached to below the root zone of
most plants by repeated application of water to pile surfaces. Commonly, a
cemented zone is established about 1-2 meters down after repeated water appli-
cations (37). This zone greatly reduces pile permeability and inhibits further
downward migration of water. During the leaching process and the establish-
ment of the cemented zone, runoff and any percolate waters will contain large
amounts of dissolved salts.
126
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In addition to the potential for mobilizing common inorganic ions from
retorted shales, water running off of or migrating through a disposal pile
may dissolve organic and trace inorganic constituents. Other solid and liquid
wastes likely to be contained in a disposal pile (Sections 3.2 and 3.3) in-
clude process wastewaters, oily sludges, spent catalysts, and shale coke.
Water contacting such materials may dissolve toxic or carcinogenic organic
substances (phenolics, organic acids, POM) and hazardous trace elements
(arsenic, nickel, molybedum, chromium). Since small scale experiments conduc-
ted to date have generally not included materials other than retorted shale,
the potential for waterbornetransport of suspended or dissolved substances de-
rived from the above mentioned wastes is largely speculative.
Salts and other soluble substances, and suspended solids mobilized by
water contacting retorted shale can be potentially controlled or contained.
Minimizing pile slopes, constructing drainage systems, and providing impound-
ments below disposal areas can in principle decrease the extraction of salts,
etc., and contain those which are extracted. Some of the site specific plans
for such control are discussed in section 4.3. Despite controls, however,
some runoff and percolate waters may eventually reach other ground and sur-
face waters. Actual effects such as the salt loading of surface waters, will
depend on a number of factors, including storm intensity and frequency, snow-
fall rates, distance which leachate waters must travel to reach groundwater
or a surface water interface, and the rate of groundwater movement. Ground-
water in the Piceance basin is thought to ultimately discharge into the alluv-
ium of Piceance and Yellow Creeks in the northern part of the basin (Section
4.2.2). Movement of groundwater may be slow on the average, but periodic
storm runoff and stream discharge may periodically flush salts into the White
and Colorado River systems (indeed this is probably occuring naturally at
present (44)).
Pollution Control Activities: The attempt to contain wastewaters may
create an indirect source of water pollution. Leakage of poor quality water
from impoundments is possible if the bottoms or dams of these impoundments
are permeated. Eventual return of any of these contaminated waters to the
surface through springs or baseflow would pollute streams in the area.
Infiltration of poor quality water from dams and reservoirs can be
controlled in several ways. Reservoirs and other water control structures
can be lined with impermeable material. Poor quality water that infiltrates
into the groundwater system can be partially recaptured by shallow wells.
If the reservoir is within the area of significant drawdown caused by mine
dewatering, infiltrates may be collected by the mine dewatering system.
Site Specific Indirect Uater Pollution Sources and Control Plans
(2,17,46,48,51)
Variations in hydrology over the Piceance and Uinta Basins coupled with
differing proposed methods of development create unique indirect sources of
pollution. These are discussed below along with proposed control methods.
The Superior Oil Company lands are located at the northern margin of the
basin near the junction of Piceance Creek and the White River (Figure 4-1).
127
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It is Superior's Intention to mine oil shale and associated sodium and
aluminum minerals from the lower oil shale zone of the Green River For-
mation. As the proposed mine zone is below the lower aquifer and 1s
indicated to be dry, dewatering of the mine zone may be unnecessary.
Superior proposes to dispose of the processed shale in the m1ned-out zones,
which may constitute an Indirect source of pollution, however. Eventual
percolation of groundwater through the underground processed shale disposal
area could contaminate surface and groundwater of the area. However, it
is envisioned that this would be controlled by compacting the processed
shale to render it impermeable or by sealing off the mined-out areas with
barrier pillars.
Superior intends to use groundwater from the lower aquifer as the princi-
pal source of process water. This may reduce spring and streamflow in the
area. However, as the spring and creek water in this part of the basin have
a high dissolved solids content, this may actually Improve water quality in
the White River. If necessary, Superior intends to augment any water lost to
the stream system as a result of their activities via release of purified
process water (condensed process steam).
Tract C-a is located in the headwaters of Yellow Creek near the western
margin of the basin (Figure 4-1). Stream water quality in this area is
generally good. Both the upper and lower aquifers are moderately well-devel-
oped in the vicinity of the tract and contain water in the order of 1300 mg/1
total dissolved solids with high fluoride content (Table 4-8).
The open pit mine contemplated for Tract C-a would remove the strata that
presently restricts vertical movement of waters. As long as the pit is kept
dry this would not create a problem. However, if the dewatering operation is
permanently halted, the pit may fill with poor quality groundwater. It is
possible that such groundwater could enter surface streams.
In order to prevent stream pollution, the pit could be lined with a layer
of impermeable material or semi-impermeable retorted shale. Total backfilling
or grouting is another option. A third option is to continue dewatering
operations in perpetuity.
Tract C-b is located in the southcentral part of the Piceance basin. In
this area surface water has a TDS content of about 1000 mg/1; fluoride content
is moderate. Both the upper and lower aquifers are reasonably well-developed
in this area. The TDS concentration of the water in both aquifers is about
the same as the stream but fluoride content is higher (Tables 4-7 and 4-8).
Sprinkler irrigation and reinjection are two methods proposed for disposal
of surplus mine water during construction. Both these methods could indirectly
pollute ground and surface waters.
Evapotranspiration of high TDS and fluoride content water from the sprink-
ler system will build up salts in the soil that could be carried into the sub-
surface during periods of high precipitation. Eventual return of any of these
128
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contaminated waters to the surface through springs or baseflow would pollute
streams in the area. Sprinkler irrigation would be used only in the area that
is to be later occupied by the processed shale pile.
Data are insufficient to predict the total effects of reinjection on the
hydrologic regime. However, if the water is reinjected into the same aquifer
from which it came (as proposed), the potential for pollution is substantially
reduced. Because the injected water will be later withdrawn as part of the
dewatering scheme, the reinjection program may be considered as temporary stor-
age rather than a permanent solution of the water disposal problem.
The present Occidental Oil Company operation is located in an oil shale
outcrop area at the southern margin of the Piceance basin. Streamflow in
this area only occurs during spring snowmelt and during thunderstorms. Limit-
ed amounts of groundwater are present in the upper aquifer; the lower aquifer
is very poorly developed in this area.
Although Occidental proposes to develop the oil shale by in-situ methods,
many of the water pollution problems associated with processed shale disposal
are the same as for surface projects. Surface or ground water may percolate
through the underground processed shale pile and become polluted. If this
water is allowed to reach the streams in the area, severe water pollution
and/or degradation may result.
It is assumed that a water retention facility will be built so as to col-
lect any water that has filtered through the underground retort. This water
could eventually be reused in the processing and mining operation.
The White River Oil Shale Project proposes to obtain water for development
as tracts U-a and U-b from the White River. A dam has been proposed as a
joint project of the state of Utah, the Ute Indians, and the Uinta Water Con-
servation District, to have a total dead storage capacity of 145 million m3
(118,000 acre-feet) at completion. The impacts of dams on water quality in
the arid west include evaporative losses (and salt concentrating effects),
the deposition of sediment, erosion and dissolutionof bank material, the crea-
tion of new groundwater systems, and changes in downstream temperature regime
and erosion potential. These and other potential impacts are not unique to
the proposed White River dam, nor unique to oil shale development.
Accidental Sources of Water Pollution and Control Plans
Accidental sources of water pollution are the result of catastrophic
events. These include dam failure and accidental spills of oil or other
hazardous materials. Since spill contingency plans for oil and other hazard-
ous materials must be submitted to the federal government and such plans are
now in operation throughout the oil and chemical industries, no further dis-
cussion of this subject is included. The probability of sudden and complete
dam failure, while remote, warrants further discussion, however.
Leachate from freshly retorted shale tests have a maximum TDS content
of about 1400 ma/1 (42) More typical concentrations of runoff waters are in-
dlcSd to be about 20 percent of this value (1). While the quality of waters
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retained below processed shale embankments is highly variable depending upon
dilution and evaporation, it appears that the TDS level of leacbate water
itself may be approximately the same as streams in the oil shale area. How-
ever, organic and trace inorganic constituents could be higher in leachate
waters than in the streams.
Sudden dam failure would release the stored processed shale runoff and
leachate water into the streams. Because the 70S of the stored water may not
be dramatically greater than that of stream waters, dissolved solids content
of the latter would not necessarily increase. Since the concentration of
trace organic and inorganic constituents has not been quantified, it is pre-
sently not possible to determine the effects of these substances on water
quality. Studies are in progress to determine the levels of trace materials
in runoff and leachate from processed shale (1).
Sudden dam failure would send large quantities of water at high velocities
along the stream channels. Extensive damage to the stream system in the form
of erosion and siltation could occur. Suspended sediment levels would be in-
creased both during and subsequent to the flood. Dwellings and other struc-
tures might be inundated. Much of the aquatic habitat and life could be de-
stroyed. Damage and destruction caused by failure of a processed shale water
retention dam would be similar to that caused by flash flooding of the same
magnitude anywhere.
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4.3 POTENTIAL IMPACTS ASSOCIATED WITH SOLID WASTE DISPOSAL
Solid waste streams are the largest by mass and volume of any waste
streams encountered in the extraction and processing of oil shale. The bulk
of these wastes are processed shale, raw shale fines, and dusts (as sludges)
collected during processing. In addition, spent catalysts from shale oil up-
grading operations, and sludges from plant water and wastewater treatment con-
tribute to solid wastes requiring disposal. Also, retorted shale will commonly
serve as the repository for process wastewaters which are used for moisturizing
and compacting purposes. The sources and characteristics of solid and aqueous
wastes were reviewed in Sections 3.2 and 3.3. This chapter is a review of
solid waste disposal plans proposed by major oil shale developers. A discus-
sion-of the potential physical and vegetative stability of disposal piles and
of solid wastes as an intermedia source of air and water pollutants is included.
4.3.1 Solid Waste Disposal Plans for Oil Shale Development
The developers of private oil shale lands (e.g., Colony, Union, Superior,
Occidental) and of the federal lease tract lands (RBOSP-C-a, Roxana-C-b, and
WROSP-U-a/U-b) have presented plans at varying levels of detail for handling,
disposal, and stabilization of solid wastes from commercial operations. This
section summarizes these plans and the physical setting of individual sites
proposed for the disposal of wastes. All of the plans discussed below have
the objective of creating a stable disposal pile, suitably contoured and reve-
getated, with provision for protection against leaching of substances into
ground and runoff waters.
Colony (1): The Colony Development Operation has selected a canyon-type
disposal site in Davis Gulch, near the Middle Fork of East Parachute Creek,
in the northwest corner of the Dow West property. A schematic of the 800
acre disposal site is shown in Figure 4-2. An estimated 363 million tonnes
(400 million tons) of waste will be placed in Davis Gulch and its side drain-
ages during the first 20 years of Colony's planned plant operations.
Placement will be by means of 150 ton dump trucks spreading a layer 45 cm
(18 inches) deep across the fill at one time. This will be followed by com-
paction to either 1360 kg/cu. meter (85 Ibs/cu.ft.) in the pile interior or
1520 kg/cu. meter (95 Ibs/cu.ft.) on frontal slopes, using a 12% average pile
moisture content. A drainage system will be provided, together with a catch-
ment basin and dam.
After final contours are established, contained salts in the top of the
pile will be leached down into the pile, a 15 cm (6.0 inch) layer of topsoil
added, and a revegetation program initiated. The latter will include the re-
quisite chemical fertilization and irrigation over a period of several years
to insure a stable, self-sufficient soil cover of about 45% grasses, 40%
shrubs, and 15% forbs.
Tract C-b (2): The Roxana group (Ashland, Shell), which holds the federal
lease of Tract C-b, intends to use TOSCO II retorting technology, and would
therefore produce a processed shale and associated wastes similar to those de-
scribed previously for the TOSCO II process (Section 3.3). The lessees would
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12345678 9 10
I BE Tout ING AND UPGRADING WHS 2 PTOOLtSlS 3 SECONDART CRUSHER 4 COARSE ORE
STORAU ^ COABW ORE CONVEYOR FROM TUNNEL TO FINAL CRUSHING * PLANT MINE BENCH
JCCf 55 lukn 7 MIDDLE FORK OF PARACHUTE CREEK 8 COAHSE ORE CONVEYOR THROUGH TUNNEL.
FHnu MINI BiNCH 9 MIVE BENJt AND PHIUART CAuSHMi « MIDDLE FORK DAM II ACCESS
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13 POOCESSCD SHALE CONVEYOR M DAVIS OULCH DAM IS DAVIS GULCH
Figure 4.2.
Aerial View of Colony Development Operation Disposal
Site - Davis-Gulch (located at the upper reach of
Parachute Creek, Colorado) (1)
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prefer off-tract disposal of spent shale south of Tract C-b, but this currently
is not likely for legal reasons. For on-tract disposal, a site in Sorghum
Gulch has therefore been selected.
The disposal pile will eventually encompass some 486 hectares (1200 acres)
after 20 years of plant production in an area over two miles long and over
one-half mile wide, and have a pile height of 61 meters (200 ft). Processed
shale will be produced at the rate of 49,000 tonnes (54,000 tons) per day
(dry basis), or a total of 335 million tonnes (370 million tons) over the
first 20 years. Disposal compaction procedures and provisions for runoff will
be similar to those described for the Colony Operation.
Tract C-a
JRBOSP) (17): Open pit extraction of oil shale for processing
at Tract C-a will create several types of solid wastes requiring disposal.
In addition to the processing wastes (retorted shale, catalysts, etc.), mar-
ginal quality oil shale (sub-ore), overburden rock, and soil material will
require handling, relocation and/or disposal.
RBOSP indicates that materials removed from the open pit must be placed
outside the pit for the first 2 phases of operation (about 30 years) so that
maximum resource recovery from the tract can be realized and rehandling of
material can be minimized. During Phase I operations, RBOSP proposes to dis-
pose of overburden, sub-ore, and TOSCO II retorted shale at a site north of
Tract C-a called "84 mesa". Figure 4-3 shows the proposed disposal location
and a side view of the pile as envisioned.
The 144 hectare (355 acre) disposal area of Phase I will be segregated
into sections containing soil, overburden, processed shale, and sub-ore.
This segregation allows for later use of soil in revegetation operations, and
potential recovery of sub-ore should it become economic. The top soil (and
sub-soil) will be stripped from both the pit on Tract C-a and the disposal
site on 84 mesa. RBOSP intends to use freshly stripped topsoil where possible
to facilitate revegetation of disposal pile surfaces.
During Phase II, the disposal area will be expanded east and north to
accommodate expanded solid waste generation on the tract (Figure 4-4 ). The
nature of the wastes will change, since GCR retorting as well as TOSCO II re-
torting is envisioned. As in Phase I, overburden, sub-ore, processed shale,
and topsoil will be segregated. All processed shale will be compacted as it
is laid down, and exterior slopes of 4:1 will be established. An artificial
soil profile, using freshly stripped topsoil where possible, will be placed
on final surfaces. During Phase II, about 111,000 tonnes (120,000 tons) of
moisturized process shale will be produced daily. At the end of Phase II the
total volume of compacted processed shale and sub-ore/overburden will amount
to 700 million cubic meters (915 million cubic yards) and 450 million cubic
meters (593 million cubic yards), respectively.
Surface runoff from the pile will be collected by ditches around the pile
perimeter. The outside of the shale pile will be highly compacted so as to
minimize potential infiltration into the pile (with subsequent leaching). All
runoff and possible leachate waters will be diverted to a lined collection
133
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-------
RETORTED
' SHALE
ELEV. 6200' (5 YEARS)
-SLURRY TRENCH
EAST PARACHUTE CREEK
Figure 4-5. Schematic of Union Oil Company Retorted Shale Disposal Plan for Operations
at Parachute Creek Site (45)
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evaporate or be later used f°r d"st control or com-
The 9,000 tonnes (10,000 tons) per day modular plant proposed
by Union Oil Company to be constructed on its land in Parachute Creek, will
produce some 7,600 tonnes (8,360 tons) of retorted shale (dry basis) daily.
This is approximately 2.8 million tonnes (3.1 million tons) per year, or 14
million tonnes (12.7 million tons) over the expected five years of operation
of the modular plant.
Retorted shale from the processing plant at 2130 meter (7000 ft.) eleva-
tion will be conveyed downward through an ore pass to the 2010 meter (6,600
foot)level (see Figure 4-5), loaded into trucks, and transported to a dis-
posal area in East Parachute Creek canyon. Here, it will be deposited in
windrows up the south embankment of the canyon and compacted to a density of
1,440 kg/cu. meter (90 Ibs/cu.ft.).
Runoff from the disposal pile will be caught in a leachate collection
ditch at the top of the embankment. The East Fork of Parachute Creek will be
re-routed around the embankment through a by-pass ditch.
If a full-scale commercial plant is later constructed by Union Oil it
would produce some 47,000 tonnes (52,000 tons) of spent shale per day, or 15.5
million tons per 330 day stream year.
Tract U-a, U-b:(51) The joint development of Tracts U-a and U-b is in-
tended to proceed through an initial modular plant stage with a throughput of
9,100 tonnes (10,000 tons) of raw shale per day, to a first commercial plant
processing 72,500 tonnes (80,000 tons) per day, and finally to a projected
plant handling 145,000 tonnes (160,000 tons) of shale per day. The latter
plant will produce some 118,000 tonnes (130,000 tons) of processed shale daily
or approximately 39 million tonnes (43 million tons) per stream year.
It is currently intended that the major portion (85*) of retorting will
6e carried out in vertical, Paraho direct and/or indirect type retorts, but
that the crushing fines (15%) will be pyrolyzed in TOSCO II-type retorts. The
processed shale will therefore be primarily of the Paraho-type, with some 15%
of it having the properties previously described for TOSCO II spent shales.
It is expected that all of the 16,000 cubic meters (100,000 barrels) of
shale oil produced daily will be upgraded in facilities similar to those used
for the Colony Operation. As a result, some 3% of the wastes will consist of
spent catalysts, sludges, and arsenic-laden solids from shale oil processing.
Spent shale and waste disposal is expected to be on Tract U-a, in Southam
Canyon, to the west of the plant area. The processed shale pile will be built
southward along the eastern half of the canyon toward the southern limits of
Tract U-a. A retention dam at the northern end of the canyon will prevent
contamination of the White River. The finished processed shale disposal pile
will be contoured to blend with the natural terrain, and revegetated.
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It is projected that the combined 72,500 tonnes/day and 145,000 tonnes/
day commercial operations will produce of a total of about 1,040 million tonnes
(1,150 million tons) of retorted shale during the 20 (plus) years of contem-
plated full-scale production. This will result in a disposal pile in Southam
Canyon of 727 million cubic meters (950 million cubic yards) volume, occupying
some 366 hectares (900 acres), with an average depth of 61 meters (200 ft.).
Superior (28,46): The Superior multi-mineral process is unique in that
it permits return of all processed (e.g. leached) shale underground, as a wet
cake, for compaction into the void spaces remaining after room-and-pillar
mining. It is expected that the 22,000 tonnes (24,000 tons) per day commercial
operation will dispose of some 4.2 million tonnes (4.6 million tons) of leached
spent shale annually.
The leached shale wet cake will be returned to the mine and converted
into a slurry, which will be pumped into the empty underground rooms and allow-
ed to drain to approximately 25% moisture content. Because of the dipping
beds on the Superior property in the northern Piceance Basin in Colorado, it
is claimed that the slurry can be emplaced up to the ceiling, by proper with-
drawal of the slurry discharge pipe as each room fills.
As shown in Figure 4-6, the rooms will be grouped into a series of "cells"
460 meters x 820 meters (1,500 ft. x 2,600 ft.) with each cell enclosed by a
rib pillar (barrier wall). Cells within a given level will be aligned with
corresponding panels above and below. In the event of leakage, therefore, a
given cell can be sealed off from the balance of the mine.
It is projected that each "cell" could contain up to 4.3 million tons of
leached spent shale, which is approximately the amount expected to be disposed
of annually from the commercial plant. No revegetation, of course, of the dis-
posed shale will be required.
Occidental (47.48): In the modified vertical in-situ process currently
under investigation by Occidental Oil Shale some 20% of the underground deposit
must be mined out, in order to produce the requisite void space for subsequent
rubblization. This mined rock must be disposed of, if it is too lean for sur-
face retorting, or at least stored above ground if subsequent surface retort-
ing is contemplated.
In a commercial Occidental in-situ operation using oil shale with an
average assay of .06 m3 /tonne (15 gallons/ton),'and producing some 7,950
cubic meters (50,000 barrels) per calendar day, it is estimated that 51,400
tonnes (56,700 tons) of "rock" must be mined and removed daily, or approxi-
mately 18.8 million tonnes (20.7 million- tons) annually. If this rock is very
lean or nearly barren shale, it is proposed to dump it in canyons and gullies
near the in-situ operations and restore a vegetative cover. The disposed
material would be essentially the same as the parent rock from which local
soils were derived. It is estimated that up to 16 to 24 hectares (40-60 acres)
of typical canyon disposal area could be required annually for such purpose.
If the mined rock were richer in oil shale the above 50,000 barrel/day
plant would produce, for example, only 31,000 tonnes/day of mined material for
138
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Figure 4-6. Backfilling of Mined Out Shale Zone with Processed
Shale - Superior Oil Company (28)
139
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a 25 gallon/ton deposit. This mined rock would most probably be stored tem-
porarily and subsequently processed by surface retorting, producing some
26,000 tonnes/day of retorted shale for disposal. A canyon disposal area of
some 8-12 (20-30 acres) annually would be required.
4.3.2 Potential Hazards and Pollution Problems
The disposal of processed (retorted) shale involves the transport and
surface emplacement of large quantities of solids on a scale only rarely
attained to date in the mining industry. The resulting disposal piles should
be stable, resistant to substantial erosion, and essentially impervious to
leaching by the normal rainfall and snowfall encountered in the shale region.
Provision should be made for protection against the flash flooding which might
rarely occur. A suitable, permanent vegetative cover should be established.
The spent shale will contain potentially Teachable salts and in some cases
a carbonaceous residue from retorting. In addition, if upgrading of shale
oil is carried out in conjunction with retorting, spent catalysts, sludges,
arsenic-laden solids, and other plant wastes might also be present in a dis-
posal pile. The latter could include process waters which might be used to
aid in compacting the processed shale.
In the light of the above it would therefore appear that potential
hazards exist relating to (a) pile stability, (b) airborne partlculates,
odors, and/or organic vapors, (c) leachates, both inorganic and organic, as
a result of precipitation and/or ground waters, (d) transfer of possible haz-
ardous organics or trace elements to the biosphere, and (e) trans-locations
of toxic substances to vegetation.
Pile Stability
Most of the proposed major oil shale developers, as previously discussed,
plan to dispose of processed shale and also, perhaps, associated plant wastes
in canyon (or gully) locations. Colony has selected a 325 hectare (800 acres)
site in Davis Gulch, Middle Fork, East Parachute Creek. Union's disposal area
will be in East Parachute Creek Canyon. The Roxana Group (Tract C-b) will
utilize a 490 hectare (1200 acre) on-tract site in Sorghum Gulch (Piceance
Basin). RBOSP plans to use "84 mesa" north of Tract C-a. Tracts U-a/U-b
will utilize 366 hectares (900 acres) in Southam Canyon on Tract U-a.
Among the surface process developers only Superior Oil will not use a
canyon disposal site, but rather return its retorted (leached) shale to its
underground mine. Occidental will, of course, leave its retorted shale in-
place after in-situ retorting, but may dispose of mined lean shale or barren
rock on-surface.
The large volumes of material which will be present in a disposal pile
can create pollution problems should the pile experience mass movements.
Slope stability and liquefaction studies have been conducted for TOSCO II pro-
cess shales (49,50). Large scale flow type failure of a pile is predicted to
be an unlikely occurrence. However, local slumping or building is a more prob-
able event. The angle of internal friction for TOSCO II retorted shale is
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about 20°, suggesting that slopes of 3:1 (18.50) would be stable in principle.
Slopes of 4:1 are generally proposed for the sides of shale embankments, cor-
responding to a 140 angie Of internal friction. The safety factor is not
extremely high, and uncertainty exists regarding degree of saturation of some
shale zones during part of the year. Several potential interfaces between
different materials are present 1n proposed disposal piles including Valley
floor - pile side Interfaces, compacted - non-compacted interfaces, over-
burden - processed shale interfaces, and topsoll - processed shale
Interfaces. These Interfaces may promote lubrication, particularly when
water saturated, and allow mass movement to occur.
Mass movement could adversely affect water quality. Sediment and salts
can be added to local surface waters, or to catchment structures. Also,
changes in pile drainage systems due to slumping, etc. may encourage infiltra-
tion. A destabilized pile surface will also be difficult to keep vegetated,
and both increased surface wind and water erosion may result.
Since no large disposal piles have been constructed to date, little is
actually known about stability of such piles in real situations. Further,
most of the work to date has dealt with carbonaceous shales; burned shales
are likely to have significantly different stability properties.
Intermedia Transfer of Pollutants from Disposal Piles
In order to control fugitive dusts, and also to provide moisture for com-
paction and stabilizing the disposal piles, retorted shale will be wetted
prior to transport and distribution. Whether this will be sufficient to mini-
mize particulate emissions at the scale of operations contemplated at each
site is currently not completely known. The characteristics of the spent
shale and the micro-meteorology for a given site are among the pertinent vari-
ables involved.
Indirect water pollution resulting from runoff from and infiltration into
disposal piles has been discussed in Section 4.2.4. It is planned to route
natural drainage at each disposal site around the pile or through the pile in
conduits. Provisions must be made for drainages from side gullies, if present,
and for protection of ground waters from leachate contamination. Whether the
absorptive properties of the individual spent shales and the catchment basins
planned by most developers are sufficient to insure environmental protection
against water quality degradation is not yet clear.
4.3.3 Experience in Establishing Vegetative Cover on Retort Shale Piles
The surface of a disposal pile is subject to natural erosion by wind
and water. In principle, non-vegetative protection or stabilization of pile
surfaces is possible, but the large areas involved in commercial shale oil
operations make vegetative stabilization the preferred or economic alternative.
Further, successful vegetation programs can create a biotic habitat similar
to or consistent with that of surrounding areas.
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Several greenhouse and field experiments or tests have been conducted to
investigate the potential of retorted shale to support plant growth. The re-
sults of these experiments indicate that successful establishment of vegeta-
tion directly on the surface of retorted shale piles is partially limited by
inherent properties of retorted shale itself, including the high soluble salt
content of the shale, the alkalinity of Burned shale, the dark heat absorbing
color of carbonaceous retorted sfiale, and the lack of nutrients needed for
plant growth. Studies have shown that germination and growth of most plants
are adversely affected when conductivity levels of soil saturation extracts
exceed 4 mmhos/cm, and that high pH values are a detriment to plant growth
(33,35,36). Direct exposure of carbonaceous retorted shale to sunlight can
result in surface temperatures of up to 650C (1500F), and such temperatures
can prevent seed germanation (34). Retorted shale usually lacks sufficient
available nitrogen and phosphorus to support vegetation.
Some of the properties of retorted shales which limit plant establishment
and growth can be overcome. Retorted shale's salinity and alkalinity levels
can be reduced by leaching the material prior to revegetation. However,
channeling and incomplete wetting could result in pockets of unleached shale.
Also, upper layers can become resalinized via the capillary movement of salts
upward through the shale. Large accumulations of salts in the upper 3-5
inches of surface soil may be toxic to plants, even those with established
root systems (38). For those retorted shales which have undergone significant
carbonate decomposition (due to high retorting temperatures), the addition of
granular sulfur effectively decreases alkalinity (37). But the effectiveness
of this treatment is dependent on the adequacy of the moisture and temperature
conditions at the site. The use of a light colored mulch, such as straw, de-
creases the heat absorbtion by the shale, and therefore, results in lower sur-
face temperatures. However, straw has the disadvantage of being occasionally
contaminated with weed seeds, and is also subject to dispersal by the strong
winds that frequent some locations. The addition of a complete fertilizer has
been shown to be a successful means of compensating for spent shale's lack of
available nutrients.
Local climate, slope angle, and slope direction can have a large influ-
ence on the success of vegetative establishment. Precipitation in the Pic-
eance Creek Basin in Colorado ranges from 30-40 cm (12-16 inches) per year,
with the higher values occuring at higher elevations (mainly in the form of
snow). In contrast, the Uinta Basin is essentially desert except where the
White or Green Rivers form local riparian habitats. Rainfall is well below
25 cm (10 in)/year and vegetation is fairly sparse. Most of the oil shale
related revegetation experiments to date have been conducted in the Piceance
Basin (32,37,38,39). Only recently has revegetation been attempted in the
harsher desert environment. The Research Foundation of Utah State University
is performing an ambitious program of revegetation research for U-a/U-b (see
Chapter 6) .
Also, some of the earlier revegetation projects were conducted in rela-
tively flat areas along river valleys. Slopes, particularly south facing,
are much more difficult to revegetate than flat terrain or slopes facing north,
east or west. Jute netting and various polymers are effective in decreasing
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surface erosion and thus are an aid in the initial establishment of plant
cover on sloping surfaces.
An alternative to attempting establishment of vegetation directly on re-
torted shale is to construct a soil profile more conducive to plant growth.
Developers of Tract C-a plan to place a layer of crushed rock and gravel be-
tween the spent shale and the soil layer in order to combat the capillary re-
salinization problem. But regardless of how the re-salinization problems are
handled, the soil layer should be thick enough to (1) accommodate plants with
extended root systems, and (2) be able to store adequate moisture for plant
growth during dry periods. Retorted shale heat absorption problems could also
be overcome with the placement of a layer of soil over the surface of the
shale. However, at some locations there is not an adequate soil supply and
the use of soil/retorted shale mixtures instead of soil alone may be neces-
sary.
Some additional problems or areas of uncertainty have been identified in
connection with revegetation experiments, including the following:
A retorted shale pile will be compacted for physical stability.
This practice, plus the cementation tendency of some shales may
make portions of the embankment impenetrable to plant root
systems and to percolating water. It may be difficult to estab-
lish deep rooted shrubs or trees on retorted shale piles.
t Success of revegetation may be hampered by foraging mice, rabbits,
and deer. Such foraging may be partially controlled by fencing
(for large mammals), but in any case the problem is not unique
to the revegetation of retorted shale.
Plants growing on retorted shale may contain higher levels of
trace elements than plants growing on native soils. One study
has indicated that zinc and molybdenum levels in vegetation
growing on retorted shale exceeds that recommended in forage
for cattle (38).
Weedy species (eg, Russian Twistle) may invade revegetation sites.
Initially, such invasion may not necessarily be undesirable, as
"weeds" are commonly the first class of plants to become estab-
lished in natural plant succession sequences. If a shale pile
surface is particularly conducive to the growth of certain unde-
sirable species, herbicides or other controls may be necessary.
Although some small retorted shale piles have been revegetated
and some have sustained vegetation for over 10 years without
extensive management(1,37), the longer term stability and succes-
sional characteristics of such plots are not accurately known at
present.
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REFERENCES
1. Colony Development Operation, Draft Environmental Impact Statement (EIS),
U.S. Department of the Interior, Bureau of Land Management, December 1975.
2. Detailed Development Plan, Vols. I and II, Federal Oil Shale Lease Tract
C-b, submitted to Area Oil Shale Supervisor, February 1976.
3. P. B. MacCready, Jr., L.B. Baboolal and P. B. S. Lissaman, "Diffusion and
Turbulence Aloft Over Complex Terrain," presented at American Meteorolo-
gical Society Symposium on Atmospheric Diffusion and Air Pollution,
September 9-13, Santa Barbara, 1974.
4. E. I. Hovind, T. C. Spengler and A. J. Anderson, "The Influence of Rough
Mountainous Terrain upon Plume Dispersion from An Elevated Source,"
presented at American Meteorological Society Symposium on Atmospheric
Diffusion and Air Pollution, September 9-13, Santa Barbara, 1974.
5. G. E. Start, C. R. Dickson and N. R. Hicks, "Effluent Dilutions over
Mountainous Terrain and Western Mountain Canyons," presented at American
Meteorological Society Symposium on Atmospheric Diffusion and Air Pollu-
tion, September 9-13, Santa Barbara, 1974.
6. Meyer, L. and Nelson, R., "Adequacy of Regional Atmospheric Data for
Specific Predictive Purposes in the Piceance Creek Basin," Quarterly of
the Colorado School of Mines, Vol. 7, No. 4, October 1975.
7. D. Bruce Turner, Workbook of Atmospheric Dispersion Estimates, Public
Health Service Publication No. 999-AP-26, U.S. Department of Health Educa-
tion and Welfare, 1969.
8. F. Pasquill, Atmospheric Diffusion, D. Van Nostrand Co., Ltd., London,
1962.
9. David Slade, ed., Meteorology and Atomic Energy. 1968, U.S. Atomic Energy
Commission, 1968.
10. Briggs, Gary A., Plume Rise. U.S. Atomic Energy Commission, Office of
Information Services, 1969.
11. Hanna, Steven R., "Fog and Drift Deposition from Evaporative Cooling
Towers," Nuclear Safety. Vol. 15, No. 2, March-April 1974, pp 190-196.
12. Battelle Pacific Northwest Laboratories and Dames and Moore: Air Studies.
Environmental Impact Analysis. Appendix 13. prepared for Colony Develop-
ment Operation, October 1973.
13. Federal Energy Administration, Project Indepenqence Blueprint, Final Task
Force Report. Potential Future Role of Oil Shale: Prospects and Con-
straints, under direction of U.S. Department of Interior, November 1974.
144
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n'i cu i9«*' n',?' Buder' C' B- F°J°' R- 6- Murray and R. K. White,
uil Shale Air Pollution Control, prepared for the Environmental Protection
Agency by Stanford Research Institute NTIS PB-242-858, May 1975.
15. H. E. Cramer, G. M. Desanto, K. R. Dumbauld, P. Morganstern, R. N. Swanson,
Meteorological Prediction Techniques and Data Systems, Report GCA-64-3-G,
Geophysics Corporation of American, Bedford, Massachusetts, March 1974.
16. EPA correspondence (Region VIII), letter of Mr. C. H. Wayman, Director,
Office of Energy Activities, to Mr. Darrell Thompson, Regional Director,
Bureau of Outdoor Recreation, Denver Federal Center, Denver, Colorado,
March 1976.
17. Detailed Development Plan, Vols. I-V, Federal Oil Shale Lease Tract C-a
(Rio Blanco Oil Shale Project), submitted to Area Oil Shale Supervisor,
March 1976.
18. EPA correspondence (Region VIII), letter of Mr. C. H. Wayman, Director,
Office of Energy Activities, to Mr. R. L. Bolmer, Mining Engineer, Denver
Mining Research Center, U.S. Bureau of Mines, Denver, Colorado, May 14,
1976.
19. Carpenter, T. L. Montgomery, L. M. Leavitt, W. C. Colbaugh, and F. W.
Thomas, "Principal Plume Dispersion Models; TVA Power Plants," Journal of
Air Pollution Control Association, 21_, 8, 1971.
20. Colony Development Operation, An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Part I, 1974.
21. White River Oil Shale Project, Federal Oil Shale Lease Tracts Ua-Ub,
Quarterly reports 1 through 6, 1974 through February 1976.
22. Irons, W. V., Hembree, C. H., and Oakland, G. L., "Water Resources of the
Upper Colorado River Basin," U.S. Geologic Survey Prof. Paper 441. 1965.
23. Weeks, J. B., Leavesley, G. H., Welder, F. A., and Saulnier, G. J., "Sim-
ulated Effects of Oil Shale Development on the Hydrology of the Piceance
Creek Basin, Colorado," U.S. Geological Survey Prof. Paper 908, 1974.
24. U.S. Department of Interior, Final Environmental Statement for the Proto-
type Oil Shale Leasing Program, 1973.
25. Coffin, D. L., Welder, F. A., and Glauzman, R. K., "Geohydrology of the
Piceance Creek Structural Basin Between the White and Colorado Rivers,
Northwestern Colorado," U.S. Geological Survey Hvdrologic Investigation
Atlas HA-370, 1971
26 Coffin, D. L., Welder, F. A., Glauzman, R. K., and Dutton, X. W., "Geo-
hvdrologic Data from the Piceance Creek Basin Between the White and
Colorado Rivers, Northwestern Colorado," Colorado Ground Water Circular
No. 12, 1968.
145
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27. U.S. Public Health Service, "Drinking Water Standards," U.S. Public
Health Service Publication 956, 1962.
28. Weichman, B.E., "Depositional History and Hydrology of the Green River
Oil Shale, Piceance Creek Basin, Rio Blanco County, Colorado," proceedings
102nd Annual Meeting of the AIME, 1973.
29. Hem, J. D., "Study and Interpretation of Chemical Characteristics of
Natural Water," U.S. Geological Survey Water Supply Paper 1473, 1970
30. Coffin, D. L. and Bedenhoeft, J. E., "Digital Computer Modeling for Esti-
mating Mine-Drainage Problem - Piceance Creek Basin, Northwestern Colorado,"
U.S. Geological Survey Open File Report, 1969.
31. Andrews, C., et.al., "Oil Shale Development in Northwestern Colorado:
Water and Related Land Impacts," Water Resources Management Workshop,
Institute for Environmental Studies, University of Wisconsin, Madison,
Wisconsin, July 1975.
32. Cook, C. W., Study Coordinator, "Surface Rehabilitation of Land Distur-
bances Resulting from Oil Shale Development" Technical Report Series No.
1. Colorado State University, June 1974
33. Richards, L. A., ed., "Diagnosis and Improvement of Saline and Alkali
Solids," U.S. Department of Agr. Handbook 60, 1954.
34. Striffler, W. D., Wymore, and W. A. Berg, "Characteristics of Spent Shale
Which Influence Water Quality, Sedimentation and Plant Growth Medium,"
Technical Report Series No. 1, Colorado State University, 1974.
35. Black, C. A., Soil-PIant Relationships, John Wiley and Sons, New York,
1957.
36. Arnon, D. I., and Johnson, C. M., "Influence of Hydrogen Ion Concentra-
tion on the Growth of Higher Plants Under Controlled Conditions," Plant
Phys. Vol. 17, pp. 525-539, 1942.
37. Lipman, S. C., Union Oil Company, "Revegetation Studies," Environmental
Oil Shale Symposium, Colorado School of Mines, October 9-10, 1975.
38. Halbert, H. P. and Berg, W. A., "Vegetation Stabilization of Spent Oil
Shale," Colorado State University, 1974.
39. Bloch, M. B;, and Kilburn, P. D., "Processed Shale Revegetation Studies,"
Colony Development Corporation, 1965-1973.
40. C-b Shale Oil Project, "Environmental and Exploration Program," Summary
Reports No. 1-7. through May 31, 1976.
41. Rio Blanco Oil Shale Project (Tract C-a), Progress Reports No. 1-7,
through May 1976.
146
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42. Ward, J. E., et.al., "Water Pollution Potential of Rainfall on Spent Shale
Residues, prepared under EPA Grant No. 14030 EDB, December 1971.
43. Ward, J. C., et.al., "Water Pollution Potention of Snowfall on Spent Shale
Residues,1 Bureau of Mines Open File Report No. 20-72. June 1972.
44. Ficke, J. F., et.al., "Hydrologic Data from the Piceance Basin, Colorado,"
U.S.G.S. Colorado Water Resources Basic Data Release No. 31, 1974.
45. Hopkins, J. M., et.al., "Development of Union Oil Company Upflow Retort-
ing Technology," 81st meeting AIChE, Kansas City, Missouri, April 11-14,
1976.
46. Superior Oil Company, Application for Consolidating Oil Shale Lands by
Acreage Exchange #C-19958, Bureau of Land Management, U.S. Department
of the Interior, Denver, Colorado.
47. McCarthy, H. E., and Cha, C. Y., "Development of the Modified In Situ Oil
Shale Process," 68th AIChE Annual Meeting, Los Angeles, California,
November 16-20, 1975.
48. McCarthy, M. C., "The Status of Occidental Oil Shale Development" 9th
Oil Shale Symposium, Colorado School of Mines, Golden, Colorado, April
29-30, 1976.
49. Dames and Moore, "Liquefaction Studies of a Proposed Processed Shale
Disposal Pile, Parachute Creek Colorado," study for the Colony Develop-
ment Operation, 1971.
50. Dames and Moore, "Slope Stability Studies of a Proposed Processed Shale
Embankment, Parachute Creek Colorado," study for the Colony Development
Operation, 1971.
51. Detailed Development Plan, Federal Oil Shale Lease Tracts U-a/U-b, sub-
mitted to Area Oil Shale Supervisor, June 1976.
52. Larsen, R. I., "A Mathematical Model for Relating Air Quality Measurements
to Air Quality Standards," EPA Publications No. AP-89, 1971.
147
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5.0 THE REFINING AND END USE OF SHALE OIL PRODUCTS
The commercial success of shale oil will depend in part on the ultimate
end use of the oil and on the refining steps necessary to produce a competitive
product. This chapter is a brief review of shale oil upgrading and refining
experiences to date, waste streams and hazards associated with refining and
handling of shale oil, and emissions from the combustion of shale oil products.
5.1 UPGRADING AND REFINING OF SHALE OIL
Crude shale oil is a high nitrogen, moderate oxygen and sulfur contain-
ing oil having a relatively high pour point and viscosity. It contains a
large fraction of unsaturated and aromatic compounds, and tends to form gums
during storage. Compared to most conventional crude oils, shale oil yields
less light ends upon distillation. Crude shale oil contains ash in the form
of raw and retorted shale fines. Most trace elements in shale oil are
associated with the ash fraction, and concentrate into higher boiling fractions
and coke upon distillation. An exception is arsenic, which is found in
essentially all distillate cuts. A summary of the properties of currently
produced crude shale oils are presented in Table 5-1.
5.1.1 Upgrading Plans for Oil Shale Developments
The oil shale developments planned to date do not envision processing
crude shale oil into a full range of refined products as would be the case
with a modern petroleum refinery. Rather, various levels of upgrading or
prerefining are planned in order to: 1) render crude shale oil transportable
and/or suitable as a refinery feedstock and 2) produce fuel oil and other
petroleum equivalent cuts for direct use. Table 5-2 summarizes the major
prerefining or upgrading steps planned by oil shale projects. Some of the
details of these steps are reviewed in Chapter 2 of this report.
Crude shale oil can be upgraded by employing variations of conventional
petroleum refining techniques. Solids removal is accomplished by either
filtration (diatomaceous earth) or by concentration of solids during coking.
Saturation of olefins and removal of organic sulfur, oxygen, and nitrogen
is accomplished by catalytic hydrogenation, although severe conditions must
be employed with shale oils due to the high nitrogen content. Catalyst
poisons such as arsenic are removed prior to hydrogenation, commonly by use
of an adsorption catalyst.
5.1.2 Experiences in Oil Shale Refining
Essentially all major oil companies which have an interest in or hold
mineral rights to oil s-hale have conducted research or demonstration programs
148
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Sn«!I2 1 the refining of shale oils. Generally, the results of such
programs have not been published and are considered proprietary. Experiences
from two relative y large scale refining runs with shale oil have been pub-
lished and are briefly reviewed here.
Union Oil Company - 1961 (4)
The crude shale oil obtained from the Union Oil Retort A process is a
waxy, intermediate gravity (specific gravity of 0.943), high in nitrogen (2.0
weight %), intermediate sulfur (0.9 weight %) crude, with a pour point of
26.7°C (80°F) and a viscosity of 46 centistokes (210 SUS) at 37.8°C (100°F)
Early in 1961, approximately 3,180 m3 (20,000 bbl) of the crude shale oil
Inventory at Union's Retort A demonstration plant were processed in the
American Gilsonite's refinery near Fruita, Colorado. The basic operations
in the refinery included delayed coking, thermal cracking, gasoline hydro-
genation and catalytic reforming, light gasoline sweetening, and coke calcin-
ing. All of these operations were reported to be successfully applied to
the Union Retort A shale oil in the refinery test run. The refined products
were marketed by American Gilsonite through marketing outlets in the
Grand Junction area.
The detailed results from shale oil refining at the American Gilsonite
refinery are not available. According to Union Oil, the test results are
similar to those obtained from the bench scale and pilot plant tests on shale
oil refining performed by the Bureau of Mines. Based on the results of
American Gilsonite refinery and Union's pilot plant test runs, preliminary
process designs for producing and refining commercial shale oil were proposed
by Union. The processes proposed included delayed coking to reduce pour
point, Unifining*of the full range distillate to reduce nitrogen and sulfur
content, and conventional refining processes of primary distillation, cataly-
tic cracking, additional Unifining, reforming, alkylation and treating to
produce LPG, gasoline, stove oil, jet fuels, heating oils, and diesel.
Paraho Shale Oil at Gary Western (1975) (5)
In 1975, a program under Navy Contract N00014-75-C-0055 was carried out
by Applied Systems Corporation to demonstrate the production of military fuels
from shale oil. Paraho crude from Anvil Point, Colorado, was selected as the
raw material. Contractors included Applied Systems Corporation (ASC); SOHIO;
Development Engineering, Inc., (DEI); Gary Western Co.; and Petroleum
Analytical Research Corp., (PAR).
Using the Gary Western facility, at Gilsonite, Colorado, 9,956 barrels
of crude Paraho processed shale oil were refined into the following quantities
of military fuels:
*Unifining is a hydrodesulfurization and hydrodenitrogenation process jointly
licensed by Union Oil and Universal Oil Products Co.
149
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Table 5-1. Summary of Crude Shale 011 Properties
Retort Type:
Data Source:
OIL PROPERTIES
Gravity (°API)
Specific Gravity (60°F/60°F)
Pour Point (°F)
Pour Point (°C)
Viscosity (Centlstokes)
Viscosity (SUS)
Weight % Carbon
Weight % Hydrogen
Weight % Nitrogen
Weight % Oxygen
Weight % Sulfur
Weight % Ash
C/H Ratio
Fischer Assay of Feed (gpt)
011 Recovery (% of Fischer)
ASTM DISTILLATION
Initial Boiling Point, °F
10% Over
20*
30%
40%
50%
60%
70%
80%
90%
End Point
Fischer
Assay
Ref. 1
20.7
0.930
75
23.8
23.72
113 at 100°F
85.23
11.38
1.80
M
0.98
7.49
26.7
100
192
336
430
518
655
685
705
Cracked
--
*
TOSCO
Ref. 1
21.2
0.927
80
27
22
106 at
85.1
n;e
1.9
0.8
0.9
7.34
-_
100
200
275
410
500
620
--
775
850
920
--
~
Para ho
II Direct Mode
Ref. 4
19.3
0.9383
85
._
100°F --
84.90
11.50
2.19
1.4
0.61
0.66
7.38
270
520
600
675
750
815
845
860
__
__
--
Union
011 "B"
Ref. 3
22.7
0.812
60
__
98.2
84.8
11.61
1.74
0.90
0.81
0.005
^
24.2
91.0
139
400
731
960
1077
Occidental
In-S1tu
Ref. 2
22.5
0.904
70
21.
13.1
70.
84.86
11.80
1.50
1.13
0.71
7.19
f i «/
15.25
440
600
700
770
920
en
-------
NATO Gasoline 116 m3
JP-4 72 m3
JP-5/Jet A 104 m3
725 barrels)
454 barrels)
650 barrels)
1,167 barrels)
DFM/DF-2 187 m3 .,., _,_,
Heavy fuel oil 442 m3 (2.765 barrels)
Total 917 m3 (5,732 barrels)
The fuels met a majority of ASTM specification requirements. However,
they did not meet specifications with respect to particulate matter, gum con-
tent, wax content, storage stability, and thermal stability. The opinion has
been expressed that more rigorous hydrotreating (at 100-200 kg/cm2 or 1500 to
3000 psi) and clay treatment might have allowed the final products to meet all
ASTM specifications. The 672 m3 (4224 BBLS) of original crude shale oil which
do not appear in the military fuels are accounted for in coke, distillation
gases, and flue gases from combustion.
Using modified refining techniques, based on preprocessing studies
conducted by SOHIO, the Gary Western refinery operated at a rate of
2500 barrels a day to the coke/fractionator in relatively normal fashion,
producing naphtha, liquid gas oil, heavy gas oil, heavy fuel oil, coke and
gas.
It should be noted that this effort demonstrated only the feasibility
of producing fuels from shale oil. Rates were below normal, yields were
low, and the properties of the products were subnormal. However, none of the
problems encountered were entirely unexpected and, generally, appear soluble
with experience and practice.
The products from the Gary refining run were distributed to several
laboratories, agencies and companies for testing.
Wright Paterson AFB (Dayton, Ohio)
Lewis Research Center (Cleveland, Ohio)
Naval Air Propulsion Test Center (Trenton, N.J.)
Mobil Equipment Research & Development Center (Ft. Belvoir, Va.)
Energy Research Laboratory (Bartlesville, Okla.)
t Fuels & Lubricants Laboratory (San Antonio, Texas)
0 Detroit Diesel-Allison/GM (Indianapolis, Ind.)
Naval Ship Engineering Center (Philadelphia, Pa.)
U.S. Coast Guard Station (Portsmouth, Va.)
t Southern California Edison (Los Angeles, Ca.)
Cleveland Cliffs Iron Company (Cleveland, Ohio)
Paraho Test Facility (Anvil Points)
151
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Table 5-2. Summary of "On Site" Upgrading of Shale Oil Planned at Development Sites
en
ro
Project
Colony Development
Operation - Parachute
Creek
Lease Tract C-b
Lease Tract C-a
Lease Tracts U-a/U-b
Union
Occidental
Superior
Steps of Upgrading or Prerefining
Products
Distillation followed by delayed coking of residue
Dearsenatlon of naphtha and gas oil fractions
Catalytic hydrogenatlon of Naphtha and gas oil fractions
Hydrogen production by catalytic reforming of naphtha
followed by steam, reforming shift conversion, C02 removal
t Same as Colony
Distillation, delayed coking
Dearsenatlon
t Catalytic hydrogenatlon
Hydrogen production by gasification
of heavy ends, followed by shift conversion & C02 removal
Catalytic hydrogenatlon of naphtha and crude shale oil.
Hydrogen production by catalytic reforming of retort gases
and naphtha.
Solids/fines removal via filtration & water washing
Catalytic dearsenatlon
Stripping/stabilization
No upgrading Indicated, company claims oil can be trans-
ported directly to refinery
Company Indicates that blending with petroleum crudes will
be attempted
Low Sulfur fuel oil
LPG
Coke
Sulfur
Ammonia
Same as Colony
Plpellneable shale oil
Upgraded shale oil
Coke
Sulfur
Ammonia
Refined shale oil
Sulfur
Ammonia
Sulfur
Ammonia
Coke
Prerefined shale oil
Sulfur
Crude shale oil
t Crude shale oil
Sodium bicarbonate
* Alumina
-------
5.2 WASTE STREAMS & HAZARDS ASSOCIATED WITH REFINING & HANDLING OF SHALE OIL
:ompany shale oil upgrading and refining are
conventional petroleum refining. Some of
CO 1 1 H uia C + AC* /J ^_ _ i *** . _. -. »
these emissions * na Peroeum renng. Some o
-^=w^ 1" ^Pter 3-0)
5.2.1 Waste Streams
fl lOPnli?inf,r«n!X?in1r!t1Jni?f -ha1e o11 uP9rad1"9 a"d refining operations
U» 10,11,12; suggests the following:
Atmospheric emissions from crude shale oil upgrading and
refining are similar in magnitude and composition to those en-
countered with processing of petroleum. However, certain
operations such as hydrogenation and ammonia and sulfur recovery
must be tailored to the properties of shale oil, and pollution
control equipment sized accordingly.
Waste waters from shale oil processing contain organic
and inorganic constituents similar to those found in the
petroleum refining and byproduct coke industry.
Solid wastes from shale oil upgrading and refining operations
include spent catalysts, clay finishing wastes and perhaps
shale oil coke. Such wastes may have somewhat different
compositions and chemical properties than wastes from petroleum
refining.
5.2.2 Carcinogenic Properties of Crude Shale Otis and Refined Products
Crude shale oils, upgraded or refined shale oil products, and certain
waste streams associated with shale oil processing may contain hazardous sub-
stances from which industrial workers and the general population should be
protected. A current concern is the potential human exposure to carcinogens
associated with shale products. Several authors have suggested that shale
derived oils may create more of a cancer hazard than is currently associated
with petroleum oils (21,22,23,24), although the matter is still unresolved.
Epidemlological Studies
Early awareness of the potential carcinogenic!"ty of shale oils occurred
in the British cotton industry (8). A high incidence of scrotal cancer was
attributed to direct worker contact with shale oil lubricants, used on the
spinning machines. However, studies of workers in the Scottish oil shale
industry during the same period did not reveal a particularly high cancer
incidence in that industry. The Scottish experience indicated that only cer-
tain types of processed shale oils possessed carcinogenic properties.
The Estonian oil shale industry is one of the largest and oldest oil
shale industries in the world. For over 20 years the Institute of Experimental
153
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and Clinical Medicine of the Estonian Ministry of Health has conducted
clinical, industrial hygiene and toxicological studies on the workers employed
in this industry (8,9,10). A greater cancer incidence among Estonian shale
workers over that of the general population has not been demonstrated. The
Estonian shale industry attributes this lack of cancer problems to good hy-
giene practices, automation, and isolation of workers from potentially hazard-
ous materials.
The largest current oil shale operation is the Petrobras Complex in
Brazil. Although epidenriological data is limited, no special cancer problems
have been reported for the operation.
The National Institute of Occupational Safety and Health (NIOSH) is spon-
soring a study of workers involved in the production of shale oil from Colorado
oil shale to investigate possible relationships between exposure to oil shale
and shale products and cancer incidence (29). This study is to follow up on
limited dermatological investigations by U.S. Public Health Service of some
800 shale workers who were employed at Anvil Points in the early 1950s. The
NIOSH study is aimed at determining possible latent effects of occupational
exposure.
Suspected Carcinogens in Shale Products
A variety of known and suspected carcinogens belonging to the POM* class
have been identified in crude shale oil and shale oil products. Some reported
levels of Benzo(a) Pyrene (BaP) in shale derived materials are listed in Table
3-15. Other carcinogenic compounds in the POM class have also been tenta-
tively identified in shale products, including 3-methylcholanthrene and an
isomeric mixture of dimethylbenz(a)-anthracenes (12,24). Generally, ROM's
have high boiling points (about 300°C) and are found in the higher boiling
distillates or residues of shale oils, including shale oil coke and carbon-
aceous residues associated with processed shale (13).
Some of the controversy about the carcinogenicity of shale derived mate-
rials arises from the use of BaP content as an indicator of activity. Levels
of BaP in shale oils are generally in the same range as levels found in similar
boiling range petroleum oils, suggesting that shale oil presents no more of a
hazard than petroleum (11,12,14,15). However, experimental tests with crude
shale oil and various distillate fractions have shown that the carcinogenic
potency by non-human bioassay techniques cannot be attributed to the presence
of benzo(a)pyrene alone (13,16,17,18,19,20,21). Other carcinogenic or co-
carcinogenic compounds may be present. Conversely, high measured levels of
BaP in a material do not necessarily indicate biological availability. TOSCO
II retorted shale for example, has not been shown to be a skin carcinogen in
sensitive mice exposed to it as bedding, while benzene extracts of such shale
are carcinogenic to the skins of mice (12). Other pathological tests on the
internal organs of these mice are still in progress. It should be noted that
BaP has not been demonstrated to be a carcinogen in man (25).
*Polycycltc Organic Matter
154
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Bioassay Tests
A major problem for establishing the degree of cancer hazard for humans
presented by materials such as shale oil is that tests cannot be directly per-
formed on humans. Animal testing results, in addition to being expensive to
obtain, cannot readily be extrapolated to humans. Epidemiological studies are
also expensive, may take years to produce results, and suffer from lack of
control of other factors which may affect cancer incidences. One simple but
promising test for screening potentially carcinogenic substances and materials
is the Ames (or Salmonella Reversion) Test (26). The Ames test is based on
the empirical observation that many mutanogenic substances are also carcino-
gens, and that certain strains of bacteria are good test organisms for indicat-
ing the mutanogenic properties of substances (27). Several federal agencies
and private organizations are currently screening synthetic fuel related mate-
rials for potential carcinogenic properties using the Ames and related tests
(28).
Experiments with test animals (mice and rats) have shown that only cer-
tain fractions of crude and refined shale oils exhibit carcinogenic activity.
High boiling distillation fractions of shale oil have been shown to be carcin-
ogenic to the skins of mice (9,10,20), and the active fractions do not neces-
arily contain large amounts of BaP (21). The Colony Development has contracted
With the Eppley Institute for animal testing of shale derived materials (12).
Based on the results of the Eppley studies, carcinogenic potency indices for
various hydrocarbon material have been determined. Table 5-3 shows a compari-
son of the relative potency of some petroleum and shale derived materials. The
indices suggest that shale derived oils are similar to petroleum oils of com-
parable boiling range or intended use, and that upgraded (hydrotreated) shale
oil is significantly less potent than crude shale oil. It might be commented
that a latency period is required for the development of carcinogens in mice,
and toxic substances other than POM in shale oil can cause death before can-
cers might normally occur (20).
Potentially Carcinogenic Materials in Waste Streams Associated with Shale and
Shale Oil Processing -*
The presence of suspect carcinogens in shale products suggests that waste
streams associated with processing may also contain such substances. Some of
the studies regarding retorted shale have been reviewed in Section 3.3.2. Air
and waterborneemissions and effluents resulting from retorting, upgrading, and
refining operations may also contain such substances (Sections 3.1.1 and 4.2).
Generally, little ts known about the hazards of shale related waste streams,
since retorting and refining operations conducted to date have been limited
in scope and size, and have been aimed primarily at demonstrating technology
rather than determining effluent quantities and properties.
Based on analytical data, animal testing, and epidemiological studies,
some generalizations can be made about the carcinogenic hazard of shale derived
materials:
0 High boiling shale derived oils and carbonaceous residues contain
BaP and other POM.
155
-------
a Levels of BaP in shale derived products are similar to levels
found in analogous petroleum derived oils and residues.
BaP content may not necessarily be a good indicator of carcinogenic
activity in test animals, both because of the possible presence
of other carcinogens and because analytical measurements do not
necessarily indicate bioavailability.
Industrial exposure of humans to certain shale products has been
correlated to cancer incidences, but the correlation is no
stronger than that between exposure to many petroleum and coal
derived substances and cancer.
t Good industrial hygiene practices and isolation of workers from
exposure can dramatically influence occupational cancer incidences.
Bacterial and animal test results regarding the carcinogenicity
of substances or materials cannot directly be related to carcin-
ogenicity in man.
Little is known about actual hazards to workers or the general
population from carcinogens which might be present in the waste
streams of shale and shale oil processing operations.
Table 5-3. Comparable Carcinogenic Potency of Complex Mixtures (12)
Oil Product
Potency Index Based on
Mouse Skin Tests
Industrial Fuel Oil 0.17
Naphthenic Distillate 0.06
Dewaxed Paraffin Distillate 0.06
from Petroleum
Cracked Sidestream 0.26
Coke Oven Coal Tar 0.54
Crude Shale Oil 0.10
Upgraded Shale Oil 0.03
3-methylcholanthrene (reference compound) 1-0
156
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5.3 EMISSIONS FROM THE COMBUSTION OF SHALE OIL PRODUCTS
Emissions from the combustion of fossil fuels may be divided into two
broad categories; those which occur due to the inherent properties and
composition of the fuel, and those which occur as a function of combustion
parameters. Sulfur dioxide belongs in the first category, while carbon
monoxide and hydrocarbons belong to the second category. Particulate
emissions can be placed in both categories; sooty material accompanying
incomplete combustion, and ash derived from inorganic and noncombustible
components of the fuel. Similarly, oxides of nitrogen occur in combustion
gases both from oxidation of fuel nitrogen and from the non-equilibrium
reaction of atmospheric nitrogen and oxygen at combustion temperatures.
The properties of crude shale oil have been discussed previously(Sec. 5-1)
The high nitrogen content and, to a lesser extent, the inorganic content of
the refined shale oils are the properties which present the major emissions
potential.
Very little information is available about emissions from the combustion
of crude shale oils. Limtted emissions information has been made available
recently from the testing of refined fuels from the Paraho project. The data
at present indicate that shale derived fuels are not significantly different
from their petroleum derived counterparts in either performance or emissions
characteristics. In the case of the products from the 1975 Paraho refining
run, slightly higher nitrogen and ash contents of certain fractions account
for differences in emissions between shale and petroleum derived fuels (6,7).
About 50% of fuel nitrogen is converted to NOX during combustion. The South-
ern California Edison Company tested Paraho shale oil in July of 1976 at the
Highgrove, California generating station, but emissions data has not been
released.
Particulate polycyclic organic matter may be emitted during the combus-
tion of shale oil and its higher boiling distillate fractions. However, emis-
sions of POM are a function of combustion parameters as well as shale oil com-
position. Further, evidence to date suggests that particulate POM emissions
associated with combustion of refined shale oils are not inherently greater
than those from combustion of similar boiling range petroleum oils.
157
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REFERENCES
1. Hendrickson, T. A., "Oil Shale Processing Methods," Colorado School of
Mines Quarterly. Vol. 69, No. 2, April 1970.
2. McCarthy, H. E., and Cha, C. Y., "Development of the Occidental Modified
In-Situ Oil Shale Process," 68th AIChE Annual Meeting, Los Angeles,
California, November 16-20, 1975.
3. Cameron Engineers, Inc., "Synthetic Fuels Data Handbook. December 1975.
4. Carver, H. E., "Conversion of Oil Shale to Refined Products," Quarterly
of the Colorado School of Mines, Vol. 59, No. 3, July 1964.
5. Bartick, H., et.al., "Final Report on the Production and Refining of Crude
Shale Oil into Military Fuels," Applied Systems Corp., Office of Naval
Research Contract No. N0014-75-C-0055, August 1975.
6. Hosier, S. A., et.al., "Comparative Characteristics of Petroleum and Shale
Oil Base Diesel Fuel Marine. "Monograph on Alternate Fuel Resources. Vol.20.
California Polytechnic State University, San Luis Obispo, California, 1976.
7. Hardin. M. C., "The Combustion of Shale Reserved Marine Diesel Fuel at
Gas Turbine Engine Conditions," ibid (6).
8. Commoner, Barry, "From Percival Pott to Henry Kissinger," Hospital Practice.
Vol. 10. p 138, October 1975.
9. Bogowsky, P. A., and Jons, H. J., "Toxicological & Carcinogenic Studies of
Oil Shale Dust and Shale Oil," Inst. of Exp. & Clin. Med. Tallin. Estonian
USSR. 1974.
10. Vosame, A. J., "Blastomogenicity of Estonian Oil Shale Mazut Soot," Voprosy
gigieny trada i profess, pa to log it v Estonskoi SSR Ed; Valgus. Tallin, 1_,
73, 1966.
11. Atwood, M. T. and Coomes, R. M.,"The Question of Carcinogenicity in Inter-
mediates and Products in Oil Shale Operations," Report for the Colony Devel-
opment Operation. Atlantic Richfield Co.. Operator. Denver, Colorado, May
1974.
12. Coomes, R. M., "Health Effects of Oil Shale Processing," 9th Oil Shale
Symposium, Colorado School of Mines, April 29-30, 1976.
13. Hueper, W. C., "Experimental Studies on Carcinogenesis of Synthetic Liquid
Fuels and Petroleum Substitutes," Arch. Industrial Hygience and Occupational
Medicine, 8, 307, 1953.
14. Coomes, R. M., Presentation at the Colorado State Oil Shale Advisory. Com-
mittee Meeting, Rangely, Colorado, May 1976.
158
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15. Atwood, M. T., Presentation at the Panel Discussion, University of Denver
Symposium on Management of Residuals from Synthetic Fuels Production,
Denver, Colorado, May 1976.
16. Hueper, W. D., Occupational Tumors and Allied Disease, Springfield, 111.,
Charles C. Thomas, pp 147-187, 1952.
17. Henry, S. A., "Occupational Cutaneous Cancer Attributable to Certain
Chemical Industries," Brit. M. Bull. Vol. 4, 389, 1947.
18. Berenbloom, I. and Schoental, R., "Carcinogenic Constituents of Shale Oil,"
Brit. J. Path. 24, 232, 1943.
19. Berenbloom, I. and Schoental, R., "The Difference in Carcinogenicity
Between Shale Oil and Shale," ibid 25, 95, 1944.
20. Hueper, W. C., and Cahnmann, H. J., "Carcinogenic Bioassay of Benzo(a)
Pyrene-free Fractions of American Shale Oils," A.M.A. Arch. Pathol, 65,
608, 1968.
21. Bingham, E., "Carcinogenic Investigations of Oils from Fos*sil Fuels,"
University of Cincinnati Kettering Laboratory, Cincinnati. Ohio, 1975.
22. Sauter, D. Y., "Synthetic Fuels and Cancer," Scientists' Institute for
Public Information, New York, November 1975.
23. Schmidt-Collerus, J.J., "The Disposal and Environmental Effects of Carbon-
aceous Spent Solid Wastes from Commercial Oil Shale Operations," First
Annual Report, NSF GI 34 282X1, Washington, D.C., January 1974.
24. Schmidt-Collerus, J. J., "The Disposal and Environmental Effects of Carbon-
aceous Solid Wastes from Commercial Oil Shale Operations, A Synopsis of
of the Results of the First Year's Research Program," National Science
Foundation, June 1974.
25. Selikoff, I. J., et.al., "Inhalation of Benzo(a) Pyrene and Cancer in
Man,"First Scientific Assembly of the American College of Chest Physicians,
Chicago, Illinois, October 30, 1969.
26 Ames, B. N., "An Improved Bacteria Test System for the Detection and
Classification of Mutagens and Carcinogens," Proceedings of the National
Arch. Sci., Vol. 70, p 782, 1973.
27. Longnecker, D. S., et.al., "Trial of a Bacterial Screening System for the
Rapid Detection of Mutagens and Carcinogens," Cancer Research, Vol. 34,
p 1638, 1974.
28. Energy Research & Development Administration, "Federal Inventory of Energy
Related Biomedical and Environmental Research in FY 1974 and FY 1975,
Vols. Ill and IV, 1975.
29. Cameron Engineers, Inc., Synthetic Fuels Quarterly, June 1976.
159
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6.0 ENVIRONMENTAL MONITORING PROGRAMS AND STUDIES
This chapter is a summary of monitoring projects and studies which have
been or are being conducted in the Piceance and Uinta Basins, and which are
relevant to oil shale development. Two general classes of programs are con-
sidered: (1) private and/or specialized projects and (2) projects connected
with the Federal Prototype Oil Shale Leasing Program. Section 6.1 is a cata-
log and brief description of various activities, most of which have been con-
ducted independently of each other. Section 6.2 is a narrative summary of and
commentary on the monitoring programs of the lease tracts. Section 6.3 pro-
vides some comments about monitoring programs with focus on scope, quality,
and the availability of data and results to interested parties.
6.1 MONITORING AND ENVIRONMENTAL STUDIES BY PRIVATE INDUSTRY, UNIVERSITIES,
AND CERTAIN GOVERNMENT AGENCIES
The major companies with interest in oil shale and several other organi-
zations have been involved in various aspects of baseline environmental moni-
toring. Some of the data and results of the private programs are publically
available and have been published in research papers, conference proceedings,
Environmental Impact Assessments or statements, and other documents. For
example, the Colony Development Operation has conducted and published the
results of numerous monitoring, modeling, and mitigation studies (1,2). Many
additional studies have been discussed and referenced in the preceding chap-
ters of this report.
Other data or findings are not generally available to the public at pre-
sent. However, EIA or EIS reports are expected from Union and Occidental in
the next year or so if the climate for commercial development improves.
Tables 6-1 through 6-4 summarize the projects dealing with meteorology
and air quality, surface and ground water, solid wastes, and revegetation. The
tables are largely self explanatory. Although the attempt was made to cover
all projects which have been conducted or are known to exist at present, no
doubt some activities are not listed. The major information sources for Tables
6-1 to 6-4 are References 3,4,5, and 6.
6.2 ENVIRONMENTAL PROGRAMS OF THE FEDERAL PROTOTYPE OIL SHALE LEASING PROGRAM
After the final EIS prepared by the Department of the Interior was ap-
proved in 1973, six 5,120-acre tracts (two each in Colorado, Utah, and Wyoming)
were offered for lease in 1974. (See Section 2.4) No bids were received for
the Wyoming tracts and, as envisioned in the EIS, the two contiguous Utah
tracts opted to operate jointly so that the three operations at present are
160
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Table 6-1. Summary of Meteorology and Air Quality Monitoring and Studies
Project
Ambient
Quality Monitoring
Meteorological
Data - Ground Level
Inversion &
Diffusion Studies
Health Hazard Studies
& Control Technology
Colony
Development
Operation
Union 011
Company
Occidental
Superior
S02, THC, NOX, Particu-
lates monitored at
Parachute Creek plant
site, other valley &
plateau locations.
Trace elements in
particulate matter also
measured. Started
1970.
Two stations started
1974 - particulates.
One station - SO?, NO*,
CO, THC.
Hi-Volume Particulate
samplers located
at expected max stack
plume concentration
site and at plant site.
Recently added gaseous
pollutant monitors.
Plant site monitoring
of ambient air quality
planned for 1977.
Wind speed, direction,
temp, relative humidity
precipitation at 8
stations in Parachute
Creek Valley &
Plateau. Started 1971.
Wind speed, direction,
temp, relative humidity
at 9 stations, 30' &
200' levels. Precipi-
tation, evaporation at
5 stations. Started
July 1975.
2 met. stations, on &
near plant site -
wind speed, direction
precipitation.
Started 1972.
Wind speed, direction
temperature, humidity
at 4 sites; precipi-
tation at one site.
Balloon & tracer
studies, started in
1972. Diffusion
modeling.
Upper air studies
July, Oct. 1974 &
Jan. April 1975.
t Mine dust studies -
respirable concentra-
tions, size characteris-
tics, TLV estimates.
Dust & diesel emission
control techniques.
Spent shale dust
carcinogenic studies.
Not known
Upper air and invers
studies.
on Particulate sampler at
mine collects samples for
carcinogenic testing.
Upper air studies
planned for 1977.
-------
Table 6-2. Summary of Surface and Ground Water Monitoring Activities
ro
Project
Colorado
State
US Geolo-
gical
Survey
US Weather
Bureau
Federal
Energy Adm.
(Contracted
to Colo. St.
Unlv.butnot
completed)
Stream Flow
Spring flow
being monitored
at 70 locations
1n Plceance
Creek Basin
Streamflow being
monitored at
more than 50
locations on
Colorado River
and major tri-
butaries. All
thru Plceance Ck.
basin, USGS moni-
tors 21 addition-
al stations for
flow with the
support of
Industry.
USGS to monitor
for spring flow
along Parachute
8 Roan Creeks.
Surface Water Quality
Spring water quality
>e1ng analyzed for 70
locations In Plceance
Creek Basin
tater quality and sedl-
nent analyzed for all
stations operated by /
USGS. USGS to
nonltor spring water
juallty along
'arachute and Roan
Creeks .
Ground Water
Pumping Tests
& Water Quality
Groundwater data
collected on 97 wells
by USGS as part of
COSEP study (Includes
data on test lease
tract). USGS has drll
led 22 holes at 11
locations for testing
In 1976 - water occa-
sionally monitored at
domestic wells and
open holes along
stream.
VedpUatlon/
tunoff Studies
Maintain weather
stations at towns
1n the area -
plus Little Hills
station 1n the
Plceance Cr. Basi
& Other Studies
USGS modeling studies
reported 1n Prof.
paper 908 and various
open file reports.
Describe simulated
effects of develop-
ment on hydrology of
Plceance Creek basin.
i
All electronic com-
puter simulation
model to determine water
availability In the White
River Basin.
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Table 6-2. Summary of Surface and Ground Water Monftorfng Activities (Contd)
Project
Colony
Union
Occidental
Superior
Cor s 1m II
Studies
(comprised
17 Organi-
zations;
others may
join at
$80,0007
participant
Stream Flow
3 gauging sta-
tions on Para-
chute Creek
6 gauging sta-
tions on Para-
chute Creek
Interml ttent
drainages at
rock dumping
site monitoring.
started 1975.
USGS gauging
station on
Plceance Creek,
on Superior
property.
Surface Water Quality
15 stations In Para-
chute Creek Basin.
Periodic sampling
since 1958. 6 weekly
stations started 1n
1974.
Water quality samples
for springs & Inter-
mittent flows of
streams .
Sediment @ one site,
Plceance Creek.
4 chemical quality
stations on Parachute
Creek.
2 chemical quality
stations on the
White River.
Chemical quality on
Alkali Springs
Ground Water
Pumping Tests
& Water Quality
Not known
Pumping and water
quality testing at
5 wells .started
Jan. 1975.
Mine water quality
samples taken.
Fluid level record-
Ing on 7 coreholes,
Pump testing of 2
coreholes 1n leach
zone by USGS, plus
transmlsslvlty.
Precipitation/
Runoff Studies
Runoff & salt load
study for upper
Parachute Creek.
Precipitation at 5
stations in
Parachute Creek
Not known
Water quality 1n two
abandoned cable tool
wel 1 s .
Model 1 ng
& Other Studies
An electronic com-
>uter simulation
model of the White
i Colorado River
Basins to simulate
operating conditions
and Input parameters
:o be determined by
the user.
CT>
GO
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Table 6-3. Summary of Spent Shale/Solid Waste Disposal Projects
Project
Physical Stabilization/
Properties of Spent Shale
Leaching Studies
Colony
o*
Union
Paraho, Anvil Points
Has conducted or supported several
studies:
Moisture requirements, handling,
compacting spent TOSCO II shale.
Nine backfilling
Uquifactlon studies of disposal
piles
Slope stability studies.
Physical properties and compaction
studies in connection with revege-
tatlon research both at Parachute
Creek and at Brea, Calif.
Joint Paraho/USBM/EPA project for
defining retorted shale handling
and disposal systems. Specifi-
cally aimed at Paraho spent shale
rather than TOSCO type spent shale.
Major emphasis on water requirements,
compaction, permeability and
concentration.
Water balance 1n Davis Gulch disposal area -
Irrigation & leaching requirements.
Leaching studies 1n connection with revege-
tatlon work.
Colony 1s supporting stability & leaching
of spent shale containing representative
quantities of other wastes (coke, catalysts,
etc.)
Leaching studies are part of revegetation
research at Anvil Points by Colorado State
University, and the Paraho/USBM program for
processed shale management.
-------
Table 6-4. Summary of Revegetatlon Projects
Project
Nature of Re vegetation Work
en
Colony
Union
Paraho
(Anvil Points)
TOSCO/Forest Service/
EPA Project
R1o Blanco "Shot"
Test Plots.
Soil Conservation
Service Plant
Materials Center.
1966-1974: Greenhouse, valley, and plateau tests with TOSCO II spent shale. Studies on
plant assimilation of trace metals and organlcs from spent shale at Rocky Flats Research
Center. Colony sponsored several CSU studies of plant growth 1n TOSCO II spent shale.
Revegetation of Union A spent shale at Parachute Creek site, 1965-1967. Greenhouse
revegetation and leaching studies 1967-1974, at Brea, Calif. Valley and plateau plots
established 1n 1974 In Parachute Creek area. Recent work has emphasized Union B spent
shale, since that 1s what will be produced during commercial production.
Revegetatlon test plots on processed Paraho shale were established 1n 1975 at Anvil
Points. The revegetatlon was highly successful due mainly to the large amounts of water
applied. Under contract to EPA, Colorado State University has undertaken at Anvil Points
1n 1976, a new, more ambitious program to compare revegetatlon of processed Paraho shale
covered with various depths of topsoll.
The Department of Agriculture established a Surface Environment and Mining (SEAM) program
some years ago for joint funding by government/industry of rehabilitation projects on
disturbed lands. TOSCO has entered Into such an agreement with the Forest Service for a
project Involving upper and lower plots in the Parachute Creek/Roan Cliffs area to experi-
ment on revegetatlon of processed TOSCO II shale in realistic situations. TOSCO further
intends to perform ecosystem studies in conjunction with these plots.
In 1974, at the site of the Rio Blanco nuclear stimulation test, plots were laid out on
processed shale. Irrigation was done at irregular intervals and the plots failed. They
were reconstructed 1n 1975.
The SCS, with support from the Fish & Wildlife Service, EPA, and several other sources, has
established a plant materials center in Meeker, Colo, for the Western Oil Shale Region.
Such a center will help develop & multiply plant materials for various purposes including
processed shale revegetatlon. Due to the salutory climate and resultant ecosystems in the
Meeker area, this center will be of limited use for revegetation in the Piceance & Uinta
basins.
-------
Table 6-4. Summary of Revegetatlon Projects (Contd)
Project
Nature of Revegetatlon Work
Wolf Ridge Plots.
84 Mesa Test Plots
Colorado State
University/Colo.
Dept. of Natural
Resources/U.S. EPA
Colorado State University has proposed a long range revegetatlon program to ERDA (not yet
funded) for work on Wolf Ridge, a few miles east of Tract C-a. This proposal 1s unique
in that it would be a long range ecosystem study rather than a narrow revegetatlon project.
One obvious difficulty 1s the limited supply of either TOSCO II or Paraho processed shale
for use.
Test plots were laid out on a flat area a few miles northeast of Tract C-a 1n 1973 and
again in 1974 to test the revegetatlon potential of numerous native & exotic grasses,
forbs, and shrubs. No Irrigation was used. Some species show promise.
Test plots at two elevations (5700 ft and 7300 ft) using TOSCO II and USBM retorted shales.
Several soil thickness layers have been Investigated. Salinity measurements taken in piles,
leachate, and runoff. The published results in 1974 indicated that resalinization follow-
ing leaching of shale can limit the success of vegetative establishment, although some cover
has been partially established at both sites. Plots are being monitored to determine longer
term success.
-------
C-a (Rio Blanco Oil Shale Project), C-b (Roxana Oil Shale Project), and U-a/U-b
(White River Shale Oil Project).
The lease documents (7,8,9) .contain extensive environmental stipulations
The baseline survey, as defined by the lease stipulations, is a two year study
(one year must be completed before submission of the Detailed Development Plan)
which must be completed before commercial operations may begin. The baseline
is to define the environment as it exists now; however, lack of a philosophical
foundation for the baseline science has necessitated pragmatic decisions by
federal/state agencies and industries. This has led to differing expectations
about what the baseline survey will and will not accomplish. The baseline
survey, as it is now being conducted, is the product of specific lease stipu-
lations plus many months of joint negotiations between all interested parties
(federal/state/industry). In the process, the Area Oil Shale Supervisor has
defined and/or added to the stipulations.
Because of the lessees' concerns of anti-trust action if baseline studies
were performed jointly, and because of varying ecological conditions on the
tract, the three lessees have mounted distinctly different and separate envi-
ronmental monitoring efforts. For a first-effort baseline program, multiple
approaches have the advantage of investigating methods for future operations.
But the disadvantage is the potential difficulty of directly comparing certain
results between the tracts. At this stage of environmental baseline science,
the advantages probably outweigh the disadvantages. It would be useful to per-
form a critical review at the completion of the ongoing environmental programs,
to determine'the most appropriate baseline survey data and methods, and to
standardize the rationale for future efforts.
6.2.1 Geotechnical Data Gathering
This part of the baseline survey is not of major environmental interest,
but some parts of this effort have important relationships to the environ-
mental survey.
Geology: Each lessee has conducted the classical core-hole drilling and
logging program to define reserves on the tract. Fischer assays for shale
richness, sodium and aluminum analyses for recoverable Nahcolite and Dawson-
ite, and analyses for seven trace elements (As, B, Cd, F, Hg, Sb, Se) have
been made on core samples to investigate resource and environmental potentials.
Interpretation of some of these data has been inconclusive to date. For ex-
ample, there is general lack of knowledge of the mobility, bioavail ability,
and hazards associated with trace elements.
Hvdrology: The presence and location of aquifers has been determined by
all the lessees- Because mine dewatering is necessary for both underground
and open-pit mining, the lessees have modeled subsurface aquifers for
eventual dewatering operations. Baseline water quality has been extensively
measured (both ordinary chemical parameters as well as trace elements) even
though the lessees propose a "no discharge" practice for effluent waters from
commercial operations.
167
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6.2.2 Environmental Baseline Programs (6JO.11,12)
This program can be divided into two sections: those projects that are
continuous over a two-year interval and those that essentially are "one-shot"
programs that may or may not need to be completed within the two-year time
frame.
Air Quality and Meteorology (AQ & MET): Each tract, by lease stipulation,
is to have four AQ-MET stations on or about its property (eight for the joint
U-a/C-b). Both C-a and C-b have two stations fully instrumented for AQ para-
meters (S02, H2S, NO, NOX, 03, Cfy, CO, nonmethane hydrocarbons, particulates)
and two partially instrumented. U-a/U-b has three stations fully instrumented.
The initial requirement, now changed, was 90% recovery of AQ data. It should
be noted that approximately 5-9% of total time is needed for calibration
and zeroing of certain instruments. Difficulties are encountered in operating
such remote stations, and the 90% recovery requirement may be hard to meet.
MET stations are coincidental with AQ stations. The "main" station has
either a 30 to 60 meter tower taking data at three levels. Wind speed and
direction, temperature, humidity, rainfall, and solar isolation, delta T and
wind sigma are obtained for use in modeling. The ancillary stations have 10
meter towers measuring the normal MET parameters (eg, wind speed and direc-
tion). The lease requirement for 95% data recovery has not been too difficult
to meet to date. Isolated cases have occurred, such as a solar insolation
meter being "knocked out" by lightning flashes.
Upper Air Studies and Diffusion Modeling: Although not a part of the
original lease stipulations, lessees have been required to perform four quar-
ters of upper air studies, 15 actual days each quarter. (Tracts C-a and C-b
have conducted a fifth quarterly study.) These studies are necessary for dif-
fusion modeling and demonstration of compliance with federal/state air quality
standards.
Tract C-a had planned tracer studies to validate the diffusion model, but
these plans were initially aborted due to dust problems. However, RBOSP has
recently completed field work in connection with tracer studies. These studies
will be essential to ultimate plant design and should have been made part of
the lease stipulations.
Tracts C-b and U-a/U-b have acoustical sounders to measure inversion
layers. The upper air studies have also provided inversion data albeit on a
less continuous basis.
Terrestrial Biology: The greatest variations and difficulties in the
baseline programs are to be found in the biological studies. Despite the con-
certed efforts of the International Biological Programs, no standard method of
evaluating biological ecosystems is entirely agreed upon. Both techniques of
measurement and methods of modeling ecological interrelationships remain an
enigma. All three tracts are performing more or less complete analyses of the
flora and the small mammal fauna. These components essentially determine the
local ecosystem dynamics. But the "politics" of big game animals and birds
have influenced the focus and efforts of the programs. Further, considerable
168
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effort is being placed on investigations of amphibians and reptiles, while
far less is being placed on the invertebrate populations, especially on the
effects of grazing pressure in these ecosystems.
The leases stipulate bimonthly sampling periods. Sampling periods pat-
terned after animal activity patterns instead of arbitrary calendar periods,
could perhaps be more useful.
Game Management Plan: The lease stipulations requires lessees to formu-
late game management plans on and about the tracts. Since game management is
a responsibility of federal/state agencies, it is not certain how such plans
can interrelate with government programs without usurping their powers and
authority. To date, the game management plans consist mostly of species lists
and a cooperative attitude between industry/government.
Aquatic Biology: The aquatic biological component of the baseline survey
is actually geared to more humid regions. Major streams and rivers are well
monitored with slightly less emphasis on seeps, springs, and intermittent
creeks. Phytoplankton, zooplankton, periphyton, benthos, macrophytes, and
fish are being measured. If these data can be related to terrestrial eco-
systems, they will be of compelling interest.
Water quality (W.Q.) data is being intensively collected at each aquatic
biology station. These data are of the utmost importance and will be abso-
lutely necessary for future comparisons after commercialization. All normal
parameters plus trace elements are being measured. Other W.Q. data is being
collected in cooperation with the U.S.G.S. programs (Table 6-2).
Soil Mapping and Analysis: Adequate soils maps and knowledge of the
interrelationships of soil and flora are essential not only to an understand-
ing of local ecosystem dynamics but also to proper long-term revegetation
planning. All three lessees have completed soils data gathering projects.
Revegetation: Lease stipulations require an acceptable and demonstrated
plan in the Detailed Development Plan or firm plans to obtain such acceptable
revegetation before commercialization. Each of the lessees because of dif-
fering mining procedures and local ecosystems, has proposed different revege-
tation plans and has undertaken its own unique testing program to prove the
benefits of these plans. C-a lessees,proposing open-pit mining, plan to cover
processed shale with overburden sized to prevent upward capillary movement of
salts. C-b proposes to revegetate on about six inches of topsoil placed
directly over processed shale. U-a/U-b plans to terrace processed shale, coat
the surface with a temporary impermeable plastic, form trenches of soil in
the low spots, and use these as water catchment systems. Water is not nearly
IIgre^t aP pro'blem in Colorado's Piceance Creek Basin as n Utah's Uinta Basin.
All lessees are undertaking trials of these systems with U-a/U-b performing the
most extensive work.
Toxicology: Processed shale contains small amounts of potentially haz-
ardous o>ginic compounds. The potential carcinogenicity problem is only part
of thl S2J5ll toxicology problem associated with any new material and process.
The lessees of Tract C-b, through their connection with the Colony Development
169
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operation, have contracted for extensive carcinogenic animal testing programs,
from which results are now beginning to appear. The lessees of tract C-a have
openly spoken of plans to perform an extensive overall toxicology program not
only on spent shale but on shale oil and its products, but the program has not
begun to date.
Trace Element Analyses in the Ecosystem: One of the unresolved questions
in revegetation plans is whether processed shale piles will introduce danger-
ous levels of trace elements into the environment either through erosion or
through uptake into plants. A baseline is needed for levels of these elements
in the local ecosystems (see Section 6.2.1). All three lessees are conducting
somewhat different programs to measure present levels in soils, flora, and
fauna.
Archaeology, Paleontology, and Historical Values: Federal laws require
archaeological, paleontological,and historical clearance of areas before dis-
turbance. All lessees have mounted and finished extensive, professional clear-
ance projects on and about the leases.
Visibility and Scenic Studies: Lessees have undertaken visibility studies
by photographic techniques, which should be most useful as a check on air
quality degradation from future pollution. However, other scenic* values are
rather subjective, and descriptive techniques are the only available measuring
technique.
Ecological Interrelationships: The leases stipulate that ecological
interrelationships be addressed, which is a requirement of the National Envi-
ronmental Policy Act (NEPA). However, in the strictly scientific sense, it
is not yet known how to adequately treat this requirement. It has been ad-
dressed in many ways in the Detailed Development Plans (eg, by descriptive
words and by charts), but adequate models have not been developed.
6.2.3 Continuous Monitoring Programs
After the baseline studies are completed and when conmercialization
begins, a continuous monitoring program is to be undertaken to compare the
ecosystems "before and after" and to serve as a warning system for possible
degradation of the environment. As stated in the Detailed Development Plans,
the lessees plan to continue the baseline studies at a less intensive but
sufficient level to measure changes that may occur. There is little need for
a separate and distinct transition period unless a long delay ensues between
the end of the two-year baseline study and the beginning of commercial opera-
tions. In such an event, the lease stipulates that monitoring begin six
months before commercialization. Monitoring will continue for the life of
the project and for that amount of time afterward necessary to ensure compli-
ance with lease stipulations. Source monitoring will also be necessary once
construction and commercial operations begin on the tracts.
6.3 COMMENTS ON MONITORING PROGRAMS
The projects listed and summarized in this chapter differ dramatically
in scope, purpose, and approach since the goals of individual sponsors vary.
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For most of the potential environmental impacts associated with oil shale
development, a corresponding project or series of projects aimed at baseline
or impact monitoring, or at mitigation, exists. The use of data and project
results to assess environmental impacts on both a site-specific and regional
basis is difficult for three primary reasons. First, information is fragmented
and in many cases, not publically available. Secondly, the types of data
gathered have been dramatically different for different projects. Thirdly,
the reporting and formating of data and information has not been uniform. A
few comments regarding the adequacy of data and programs dealing with air,
water, solid wastes, and revegetation are presented below.
6.3.1 Air Quality and Meteorological Monitoring
Adequate baseline air quality and surface meteorological data have been
or are being collected at most development sites. As development proceeds,
source monitoring should be initiated. Upper air studies have been conducted
at most sites, and the results are sufficient to indicate maximum impact sites
for placing ambient source monitors. Additional upper air studies may be
needed for model input purposes (to define local inversion, turbulance, etc.).
6.3.2 Surface and Ground Water Monitoring
If present surface water gaging stations are maintained, it appears that
adequate background data will be available for determining the effects of
direct discharges of most oil shale development activities on surface water.
A possible exception is Occidental; adequate information is not available
for appraising their baseline monitoring program at present.
Considerable subsurface hydrologic testing has been conducted in the
Piceance Creek and Uinta basins. In the southernPiceance Creek and eastern
Uinta basin, the hydrology is reasonably well known, and adequate monitoring
programs have been or can be developed for determining the effects of oil
shale activities on subsurface waters. However, in the northern part of the
Piceance Creek basin interpretations differ substantially as to the effects
that oil shale development may have on the hydrologic regime. The crux of the
problem is the extent to which rich oil shale units within each of the two
major aquifers impede vertical flow. Until sufficient data are available to
define vertical flows, adequate prediction of the effects of activities such
as mine dewatering on the surface water flows and quality cannot be made.
None of the current water monitoring programs are designed to obtain the in-
formation required for better characterization of the aquifer systems One
approach might be to establish a program of pump Jesting of individual wells
at distinct depth intervals, and monitoring water levels in two or more nearby
wel1s.
6.3.3 Solid Wastes
Several projects have addressed retorted shale handling and disposal.
Activities supported by Colony and Union in particular, have contributed greatly
to design and operational planning for retorted shale disposal. A recent
Colony project, for example, is aimed at determining physical properties and
leaching potential of processed shale containing representative amounts of
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other solid wastes (spent catalyst, coke, lime sludges, etc.).
All research and monitoring programs to date have dealt with relatively
small quantities of retorted shale. Potential problems such as mass stabili-
zation of shale piles, or the maintainence of an impervious layer below plant
root zones, can likely be defined and solutions found only by creation of a
large pile. Commercial scale oil shale processing will be necessary in order
to allow the necessary experiments to be performed.
6.3.4 Revegetation
Numerous experiments and studies have been directed toward demonstrating
vegetative stabilization of the surface of retorted shale piles. The appli-
cability of the findings of such studies to large scale revegetation of re-
torted shale may not be straightforward. Plot experiments have been conducted
mainly at valley sites in Piceance Basin, and the results may have no rele-
vance to plateau sites in Uinta basin. Irrigation, mulch, and fertilizer
applications found to be successful in experimental plots may not be practical
for large plots. Plant succession and the establishment of deep rooted shrubs
and trees have not been (and perhaps may not easily be) adequately researched.
One inherent problem for more extensive revegetation research and monitoring
is the current shortage of retorted shale.
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REFERENCES
1. Colony Development Operation, "An Environmental Impact Analysis for a
Shale Complex at Parachute Creek, Colorado, Part 1," 1974.
2. Colony Development Operation, "Draft Environmental Impact Statement/Pro-
posed Development of Oil Shale resources in Colorado," U.S. Department of
the Interior, Bureau of Land Management, December 1975.
3. Spence, H. M., et.al., "Summary of Industry Oil Shale Environmental Studies
and Selected Bibliography of Oil Shale Environmental References," Oil
Shale Committee of the Rocky Mountain Oil and Gas Association, March 1975.
4. Cameron Engineers, Inc., "Synthetic Fuels Quarterly, Vols. 12 and 13,
January 1975 through June, 1976.
5. Shale Country. Mountain Empire Publishing, Inc., Vols. 1 and 2, January
1975 to June 1976.
6. Information provided by Thomas A. Beard and Richard B. Schwendinger,
independent consultants.
7. U.S. Bureau of Land Management, "Tract C-a Oil Shale Lease," U.S. Depart-
ment of the Interior, Denver, Colorado, 1974.
8. U.S. Bureau of Land Management, "Tract C-b Oil Shale Lease," U.S. Depart-
ment of the Interior, Denver, Colorado, 1974.
9. U.S. Bureau of Land Management, "Tract U-a Oil Shale Lease" and "Tract
U-b Oil Shale Lease," U.S. Department of the Interior, Denver, Colorado,
1974.
10. Detailed Development Plan, Vols. I and II, Federal Oil Shale Lease Tract
C-b, submitted to Area Oil Shale Supervisor, February 1976.
11. Detailed Development Plan, Vols. I-V, Federal Oil Shale Lease Tract C-a
(Rio Blanco Oil Shale Project), submitted to Area Oil Shale Supervisor,
March 1976.
12 Detailed Development Plan, Vols. I and II, Federal Oil Shale Lease Tracts
U-a and U-b, submitted to Area Oil Shale Supervisor, June 1976.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-069
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
A PRELIMINARY ASSESSMENT OF THE ENVIRONMENTAL IMPACTS
FROM OIL SHALE DEVELOPMENTS
5. REPORT DATE
July 1977 issuing date
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
K. W. Crawford, C. H. Prien, L. B. Baboolal,
C. C. Shih and A. A. Lee
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc. Denver Research Institute
One Space Park P. 0. Box 10127
Redondo Beach, Denver, Colorado 80210
California 90278
10. PROGRAM ELEMENT NO.
EHE 623
11. CONTRACT/GRANT NO.
68-02-1881
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Laboratory-Cin., OH
Office of Research and Development
U. S. Environmental Protection Agency
Cincinnati, Ohio 45268
13. TYPE OF REPORT AND PERIOD COVERED
Preliminary 7/75 - 7/76
14. SPONSORING AGENCY CODE
EPA/600/12
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report is a summary of major oil shale extraction and retorting develop-
ment activities. The potential impacts on the physical environment which could
result from commercial oil shale development are discussed relative to sources,
properties, and quantities of wastes. The report describes existing air, water,
and land resources in northwestern Colorado and northeastern Utah. The identi-
fication of potential impacts of oil shale development on these resources, pollu-
tion control technologies and management plans are reviewed. Potential hazards
associated with refining and end use of shale oil products are evaluated. The
major environmental monitoring and impact studies are identified, and the scope
of oil shale development projects is assessed by this document.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Oil Shale
Mining
Retorts
Refining
Waste Disposal
Air Pollution
Waste water
Colorado
Utah
Solid Waste
Land Disposal
13B
18. DISTRIBUTION STATEMENT
RELEASE TO THE PUBLIC
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
186
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
174
. U S. GOVEMHENT HINTING OFFICE: <977-757-056/6li87 Region No. 5-11
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