vxEPA
United States
Environmental Protection
Agency
Environmental Monitoring
and Support Laboratory
P.O. Box 15027
Las Vegas NV 89114
EPA-600-7 79-039
January 1979
Research and Development
Compendium Reports
on Oil Shale Technology
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 categories
were established to facilitate further development and application of environmental
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 systems. The goal of the Pro-
gram is to assure the rapid development of domestic energy supplies in an environ-
mentally-compatible manner by providing the necessary environmental data and
control technology. Investigations include analyses 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 environmental issues.
This document is available to the public through the National Technical Information
Service, Springfield, Virginia 22161
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EPA-600/7-79-039
January 1979
COMPENDIUM REPORTS ON
OIL SHALE TECHNOLOGY
Edited by:
G.C. Slawson, Jr.
T.F. Yen
General Electric Company—TEMPO
Center for Advanced Studies
Santa Barbara, California 93102
Project Officer
Leslie G. McMHIion
Monitoring Systems Research and Development Division
Environmental Monitoring and Support Laboratory
Las Vegas, Nevada 89114
ENVIRONMENTAL MONITORING AND SUPPORT LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
LAS VEGAS, NEVADA 89114
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DISCLAIMER
This report has been reviewed by the Environmental Monitoring and Support
Laboratory-Las Vegas, U.S. Environmental Protection Agency, and approved for
publication. Approval does not signify that the contents necessarily reflect
the views and policies of the U.S. Environmental Protection Agency, nor does
mention of trade names or commercial products constitute endorsement or recom-
mendation for use.
11
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FOREWORD
Protection of the environment requires effective regulatory actions
which are based on sound technical and scientific information. This infor-
mation must include the quantitative description and linking of pollutant
sources, transport mechanisms, interactions, and resulting effects on man
and his environment. Because of the complexities involved, assessment of
specific pollutants in the environment requires a total systems approach
which transcends the media of air, water, and land. The Environmental Moni-
toring and Support Laboratory-Las Vegas contributes to the formation and
enhancement of a sound monitoring data base for exposure assessment through
programs designed to:
• develop and optimize systems and strategies for monitoring
pollutants and their impact on the environment, and
• demonstrate new monitoring systems and technologies by
applying them to fulfill special monitoring needs of the
Agency's operating programs.
The study resulting in this report provides technical support to a pro-
gram for the design and implementation of groundwater quality monitoring
programs for Western oil shale operations. This report summarizes available
data on oil shale resource recovery.
This document presents a summary of research and development related to
oil shale operations. Topics considered are: mining, oil shale retorting,
shale oil upgrading, organic and inorganic characteristics of oil shale pro-
ducts, and potential environmental controls (including water availability)
on the oil shale industry. The summaries stress technologies which are pro-
posed for Federal Oil Shale Leases U-a and U-b in eastern Utah. Thus Paraho
and TOSCO retorting processes are considered in some detail. Other oil shale
technologies, such as in situ development, are also discussed but in less
detail.
The research summarized in this report is one component of the technical
basis for developing monitoring programs for oil shale operations. As such,
these technology summaries may be used by industrial developers and their
consultants, as well as the various local, State, and Federal agencies with
responsibilities in environmental planning and monitoring.
iii
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Further information on this study and the subject of monitoring develop-
ment, in general, can be obtained by contacting the Monitoring Systems Design
and Analysis Staff, Environmental Monitoring and Support Laboratory, U.S.
Environmental Protection Agency, Las Vegas, Nevada.
George B. Morgan
Director
Environmental Monitoring and Support Laboratory
Las Vegas
IV
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PREFACE
General Electric-TEMPO, Center for Advanced Studies, is conducting a
5-year program dealing with design and implementation of groundwater quality
monitoring programs for western oil shale development. The type of oil shale
operation being evaluated in this study is that presently proposed for Federal
Prototype Oil Shale Leases U-a and U-b in Eastern Utah. This type of opera-
tion includes room-and-pillar mining, surface retorting utilizing Paraho and
TOSCO II processes, and surface disposal of processed (or spent) oil shale.
This effort is using a stepwise monitoring methodology developed by TEMPO.
This report represents a compilation of information on oil shale technol-
ogy gathered to support the development of the monitoring program. Clearly,
an understanding of the mining and industrial processes associated with oil
shale operations is needed to effectively design environmental monitoring
plans.
The technical information summarized in this document supports a compan-
ion report which describes the initial phase of the monitoring design study.
This initial phase has resulted in the development of a preliminary priority
ranking of potential pollution sources and their associated pollutants. This
priority ranking will be utilized in subsequent phases of the research as the
basis for defining monitoring needs and for ultimately designing the monitor-
ing program.
In the next phases of this research program, a preliminary monitoring
design is to be developed and implemented in the field. Initial field study
results may lead to reevaluation of monitoring priorities. The final product
of the 5-year program will be a planning document that will provide a tech-
nical basis and methodology for the design of groundwater quality monitoring
programs for oil shale industrial developers and the various governmental
agencies concerned with environmental planning and protection.
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ABSTRACT
The development of western oil shale resources has been an evolutionary
process in which production and environmental control technologies have
evolved from current mining and petroleum industry practices. In addition,
new technologies are being developed which are specific to shale oil recovery.
The compendium or summary reports included in this document consider the
various production processes (mining, retorting, and oil upgrading) and key
environmental factors (organic and inorganic characterization, environmental
control, and limitations) related to oil shale development. This state-of-
the-art survey supports a study designing a groundwater quality monitoring
program for oil shale operations such as that proposed for Federal Oil Shale
Lease Tracts U-a and U-b. Hence, the reports emphasize technologies applica-
ble to this development while also providing a general overview of oil shale
technology.
This report was submitted in partial fulfillment of Contract No. 68-03-
2449 by General Electric Company-TEMPO under the sponsorship of the U.S.
Environmental Protection Agency.
VI
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CONTENTS
Section Page
Foreword i i i
Preface v
Abstract vi
Figures ix
Tables xiii
List of Abbreviations xvii
Acknowledgments xx
1 Overview of Oil Shale Development (T.F. Yen) 1
Worldwide Oil Shale Reserves 1
Geological Setting of Uinta Basin 7
Oil Shale , 9
Developing Western Oil Shale Resources 22
References 27
2 Mining Processes (J. Tang and T.F. Yen) 29
Underground Mining 29
Surface Mining 34
In Situ Mining 37
Oil Shale Preparation 41
References 42
3 Kerogen Recovery Processes (C.S. Wen and T.F. Yen) 44
Types of Retorting 44
Paraho Retorting Process 47
Retorting Process-TOSCO II 55
Supporting Processes 58
References 68
4 Hydrogenation (Upgrading) Process (C.S. Wen and T.F. Yen) 71
General Process Description 71
Hydrogenation 73
Supporting Processes 84
References 91
5 Organic Contaminants (J. Kwan and T.F. Yen) 93
Source of Pollutants 93
Health and Environmental Problems 100
Types of Oil Shale and Product Organic Compounds 115
vn
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CONTENTS (continued)
Section Page
Techniques for Pollutant Characterization,
Measurement, and Monitoring 136
References 1:49
6 Inorganic Contaminants (J. Tang and T.F. Yen) 155
Water Pollution 156
Air Pollution 162
Solid Waste 166
Health and Environmental Problems 167
Characterization, Measurement, and Monitoring 172
References 177
7 Environmental Controls in Oil Shale Development 180
(0. Kwan and T.F. Yen)
Introduction 180
Water Availability 180
Water Requirements 182
Water Treatment and Reuse 187
Control Technology and Abatement 195
References 199
Appendix: Metric Conversion Table 201
viii
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FIGURES
Number Page
1-1 Oil shale resources present on tracts that may be developed in
the next decade, present on tracts designated by Federal
Government, removable by present technology, accessible,
and total high-grade resources 3
1-2 Paleogeography in late early to middle Eocene time 8
1-3 Cross section B-B1 of Green River Formation in Piceance Creek
Basin, Colorado 10
1-4 Oil shale lands - Green River Formation 11
1-5 General scheme of oil shale components 14
i
1-6 Schematic section of oil shale 14
1-7 Chemical analysis of a Green River oil shale 15
1-8 Kerogen structure of Green River oil shale 16
1-9 Components and bridges of a Green River oil shale kerogen 17
1-10 Biomarkers in Green River oil shale bitumen 18
1-11 Current oil shale development activity in tristate area 23
2-1 Underground room-and-pillar mining operation 31
2-2 Block-caving mining concept 32
2-3 Sublevel inclined cut-arid-fill stoping mining concept 33
2-4 Typical strip mining operation 35
2-5 Block-and-cut modified strip-mining concept 35
2-6 Open-pit mining operation: (a) isometric and (b) section 36
2-7 Flame front movement in the Occidental modified in situ process 38
2-8 Horizontal in situ oil shale retorting process 39
ix
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Number Page
3-1 Two types of oil shale heating processes 46
3-2 Paraho DH-type retort unit 48
3-3 Semiworks retort for Paraho process 49
3-4 Flow diagram of the Paraho process 51
3-5 Pyrolysis unit, TOSCO II process 57
3-6 Flow diagram for TOSCO II Process 59
3-7 Spent-shale closed disposal system with water spraying on
conveyor 65
3-8 Raw shale feed crushing system 67
4-1 Typical hydrotreater for crude shale oil 74
4-2 Flow diagram for upgrading operation of crude shale oil 76
4-3 Flow diagram of a typical steam-hydrocarbon reforming
hydrogen plant 85
4-4 Flow diagram for amine treating and recovery of shale
oil light ends 87
4-5 Typical ammonia stripper tower 90
5-1 Oil shale fuel production cycle 94
5-2 X-ray diffraction pattern of acid fraction in retord water 95
5-3 Derivation of picryl chloride from TNT 96
5-4 Paraho process - indirect heating mode flow diagram 97
5-5 Disposal of spent shale from a commercial operation 99
5-6 Known nitrogenous carcinogenic compounds 102
5-7 Acute toxicity data of aromatic hydrocarbon to fish 104
5-8 Acute toxicity data of arylamines to fish 105
5-9 Bioaccumulation factor for polycyclic aromatic hydrocarbons
to fish 106
5-10 In situ retort cavity combustion temperatures before steady-
state temperatures are reached 112
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Number Page
5-11 Effect of (a) temperature and (b) heating time on the
proportion of organic carbon in spent shale extractable
with benzene 113
5-12 X-ray diffraction patterns of long-chain paraffins in
petroleum-derived asphaltenes 116
5-13 Nitrogenous organic compounds found in crude shale oil,!
retort water, and spent shale 118
5-14 Mass spectra of succinimide in retort water: (a) electron
impact and (b) chemical ionization 120
5-15 Organic nitrogen compound (maleimides) analysis from
retort water 121
5-16 Total weight of nitrogen and sulfur in Paraho crude shale
oil as a function of the cumulative midvolume distillation
fraction 123
5-17 Analysis of phenols from retort water 125
5-18 Mass spectrum of phenol in retort water 127
5-19 Mass spectra for methyl palmitate in retort water:
(a) electron impact and (b) chemical ionization 128
5-20 Typical gas-liquid chromatogram of oil shale pna fraction 133
5-21 Mass spectrum of biphenyl from retort water 134
5-22 Liquid-liquid extraction scheme 139
5-23 Gel permeation chromatography separation 141
5-24 Chromatographic separation of set 1 extractions shown
in Table 5-15 142
5-25 Chromatographic separation of set 2 extractions shown
in Table 5-15 143
5-26 Sample of retort water (pH 8.8), benzene extracted 144
5-27 Sample of retort water (pH 8.8), ether extracted 145
5-28 Sample of retort water (pH 8.8), choloroform extracted 146
5-29 Sample of retort water (pH 8.8), methylene chloride extracted 147
5-30 HPLC functional group separation spectrum for hydrocarbons,
organic aids, and polar compounds 148
xi
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Number Page
6-1 Deposited metals on cathode from electrolytical treatment of
oil shale retort water and determined by X-ray fluorescence
method 158
6-2 Emissions from oil shale operations 163
7-1 River water utilization for 50,000 bbl/day TOSCO II oil
shale plant 186
7-2 High-pressure liquid chromatrography spectra of highly
polar constituents 191
7-3 Changes in HPLC spectrum over time with biological treatment 194
xn
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TABLES
Number Page
1-1 Global Oil Shale Resources 2
1-2 Estimated of Shale Oil Supply in 1985 4
1-3 Current Oil Shale Development Projects 6
1-4 Composition of Oil Yield of Some Oil Shales 12
1-5 Composition of Bitumens in Green River Oil Shale 1.9
1-6 Carbonate Minerals in Green River Formation 20
1-7 Silicates in the Green River Oil Shale 21
1-8 Classification of Major Oil Shales 22
1-9 Results of Federal Oil Shale Lease Offerings 26
3-1 Material Balance of the Paraho Retorting Process 52
3-2 Composition of Crude Shale Oils, Petroleum Crude, and
Coal Syncrude 53
3-3 Gas Composition of DH and IH Retorts 54
3-4 Composition Analyses of Distillation Fractions from
Paraho Crude Shale Oil 56
3-5 Material Balance of the TOSCO II Process 60
3-6 Elemental Analyses of Raw Shale and Retort Products of
TOSCO II Process 60
3-7 Lighter Component Products from the TOSCO II Semiworks
Plant Process 61
3-8 Chemical Analysis of Spent Shale from TOSCO II Process
and Fischer Assays 62
3-9 Soluble Salts in Spent Shale Leachate of TOSCO II Process 63
xiii
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Number Page
3-10 Composition of Wastewater Used in Spent Shale Moisturizing 64
4-1 Upgrading Alternatives for Crude Shale Oil 72
4-2 Material Balance of Upgrading Process 77
4-3 Inspections of Hydrotreated Products from Paraho Crude
Shale Oil 78
4-4 Overall Yield of Hydrogenation Products from Paraho Crude
Shale Oil 79
4-5 Composition of Catalyst Used for Hydrotreating of Shale Oil 81
4-6 Catalyst Activity Used for Hydrotreating of Shale Oil 82
4-7 Hydrorefining of Crude Shale Oil 82
5-1 Properties of Raw Shale Oil and Petroleum Crudes 101
5-2 Composition of Retort Water from Different Processes 101
5-3 Particles and Organic Air Pollutants from Different
Subprocesses 107
5-4 Air Pollution Emission Inventory Estimated for Oil Shale
Processes 108
5-5 Vapor Losses from Storage Tanks 109
5-6 Processing Facility Solid Wastes for Phase II of Processing
Projected for Federal Tracts U-a and U-b 111
5-7 Human Carcinogens 114
5-8 Nitrogen Compound Distribution in Oil Shale Bitumens 122
5-9 Water-Miscible Polar Constituents from Green River Oil Shale 122
5-10 Phenolic Compounds Determination in Retort Water from
LERC 10-Ton Retort 126
5-11 Volatile Organics in Retort Waters from 150-Ton Retort 129
5-12 Organic Compounds Determined in By-product Waters
from Oil Shale Retorting 131
5-13 Composition of Aromatic Hydrocarbons in TOSCO Shale Oil 132
5-14 Polycondensed Aromatic Hydrocarbons Identified in Benzene
Extracts of Carbonaceous Spent Shale 135
xiv
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Number Page
5-15 COD Distribution Among the Four Fractions 140
6-1 Emission of Air Pollutants from TOSCO II Oil Shale Retorting
and Upgrading 155
6-2 Average Mineral Composition of Green River Oil Shale 156
6-3 Components in Different Oil Shale Process Retort Waters 157
6-4 Water Extracted from Experimental In Situ Retort Test
Area Near Rock Springs 159
6-5 Trace Elements in Water Extracted from Experimantal
In Situ Retort Test Area 160
6-6 Inorganic Components of Recycle-Gas Condensate 161
6-7 Paraho Retorting Gas Properties 164
6-8 Properties of Untreated Retort Gases from Different
Retorting Processes 164
6-9 Maximum Emission Rate in kg/hr, TOSCO Process 165
6-10 Sources of Nature of Atmospheric Emissions from Oil
Shale Extraction and Processing 166
6-11 Constituents of Spent Shale 168
6-12 Leachable Inorganic Ions from Spent Shale of Different
Retorting Processes 168
6-13 Semiquantitative X-ray Emission Analysis of Metals in
Retort Water from Experiments Using a Utah Oil Shale 173
6-14 Toxic Heavy Metals Content in Oil Shale 173
6-15 Heavy Metals Content in Raw Shale and Retorted Shale 174
7-1 Average Water Consumed for Various Rates of Shale Oil
Production 184
7-2 Projected Increase in Water Demand for the Upper Colorado
River Basin by the Year 2000 185
7-3 Mining Operation Water Requirements 185
7-4 Analytical Results from Two Samples of In Situ Retort Water 188
7-5 Total Soluble Materials in Retort Water 189
xv
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Number Page
7-6 Comparison of Different Waste Characteristics 190
7-7 Activated Carbon Adsorption Data 190
7-8 Thermal Stripping Column Results 190
7-9 Summary of Electrolytic Treatment of Retort Water 192
7-10 Results of Aerobic Treatment of Fractionated Retort Water 193
xvi
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LIST OF ABBREVIATIONS
AA atomic absorption spectrophotometry
ACS American Chemical Society
ANFO ammonium nitrate fuel oil
API American Petroleum Institute
ATP adenosine trlphosphate
blox biological oxidation
BOD biochemical oxygen demand
Bu Mines U.S. Bureau of Mines
C-a oil shale lease tract Colorado-a
C-b oil shale lease tract Colorado-b
COD chemical oxygen demand
DDP detailed development plan
DEA diethanolamine
DEI Development Engineering, Inc.
DOE U.S. Department of Energy
EDTA ethylenediaminetetracetic acid
EIS environmental impact statement
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
ERDA U.S. Energy Research and Development Administration
GC gas chromatography
GC/MS gas chromatography and mass spectrometry
GPC gel permeation chromatography
H/C hydrogen carbon ratio
HPLC high pressure liquid chromatography
I.D. inside diameter
LC liquid chromatography
LC5o acute toxicity of exposure resulting in 50 percent
mortality
LC/MS liquid chromatography and mass spectrometry
LD5o median lethal dose
LERC Laramie Energy Research Center
LHD load haul dump
m/e mass per electron
xvi i
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MS
mass spectrometry
NSF National Science Foundation
N.T.U. Nevada-Texas-Utah process
O.D. Outside diameter
PAH polycyclic aromatic hydrocarbons
Paraho-DH paraho direct heating mode
Paraho-IH Paraho indirect heating mode
POM polycondensed organic matter
PSD prevention of significant deterioration
RISE rubble in-situ extraction
SSMS spark source mass spectrometry
SCFSD standard cubic feet stream per day
TC total carbon
TIC total inorganic carbon
TOC total organic carbon
THF tetrahydrofluoride
TLC thin layer chromatography
TNT ti ni trotoluene
TOSCO II The Oil Shale Corporation process
U-a oil shale lease tract Utah-a
U-b oil shale lease tract Utah-b
USDI U.S. Department of Interior
W-a oil shale lease tract Wyoming-a
W-b oil shale lease tract Wyoming-b
Chemicals, Elements, and Other Terms
A
A
Ag
Al
As
Ba
Be
C
Ca
CH*
ci-
CO
C02
COHb
angstrom
adsorbance
silver
aluminum
arsenic
ban* urn
beryl 1i urn
Carbon
calcium
methane
chloride ion
carbon monoxide
carbon dioxide
carboxyhemoglobi n
xvi i i
-------
Cr chromium
CS2 carbon disulfide
Fe i ron
H hydrogen
HC hydrocarbon
HC1 hydrochloric acid
H20 water
HF hydrofluoric acid
HS" sulfide ion
H2S hydrogen disulfide
H2SOi» sulfuric acid
K potassium
X wavelength
Li lithium
m- meta
Mg magnesium
Mn manganese
Mo molybdenum
N nitrogen
n- normal
Ni nickel
NOa nitrogen dioxide
NOX nitrogen oxide
NHs ammonia
NHt ammonium ion
0 oxygen
o- ortho
03 ozone
P phosphorus
p- para
Pb lead
S sulfur
Se selenium
Si silicon
S(M sulfate ion
Ti titanium
U uranium
V vanadi urn
Zn zinc
xix
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ACKNOWLEDGMENTS
Dr. Guenton C. Slawson, Jr., and Dr. Lome G. Everett of General
Electric-TEMPO were responsible for management and guidance of the project
under which this report was prepared. Dr. Teh Fu Yen, Department of Chemi-
cal and Environmental Engineering, University of Southern California, Los
Angeles, and his staff, Dr. C.S. Wen, Mr. James Tang, and Mr. Jonathan Kwan,
were the principal authors of the report. Supporting TEMPO contributors
were:
Dr. Guenton C. Slawson, Jr.
Dr. Lome 6. Everett
Supporting consultants for the project were:
Mr. Fred M. Phillips
Dr. Kenneth D. Schmidt
Dr. David K. Todd
Dr. L. Graham Wilson
Additional technical review and input was provided by:
Mr. Lawrence K. Barker, U.S. Geological Survey, Conservation
Division, Area Oil Shale Supervisor's Office, and
Dr. R.E. Poulson, U.S. Department of Energy, Laramie Energy
Technology Center
xx
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SECTION 1
OVERVIEW OF OIL SHALE DEVELOPMENT
WORLDWIDE OIL SHALE RESERVES
The combined total of the world's petroleum crude oil is estimated to be
318 billion cubic meters (m3)(2 trillion bbl) in its ultimate resources
(Norman, 1973). By about A.D. 2000, mankind will have consumed more than one-
half of the recoverable petroleum resources (Hubbert, 1976). Even with en-
hanced oil recovery (EOR) techniques and additional significant discoveries
during the next two decades, the world energy demand will require supplemental
production of considerable quantities of oil from oil shale and tar sands.
Though oil can be produced from coal, the technology to do so is, at this
stage, less mature than that to produce oil from oil shale.
The world total of known oil shale resources is approximately 477 billion
m3 (3 trillion bbl) of oil. U.S. western shales of the Green River Formation
alone exceed 318 billion m3 (2 trillion bbl) of oil in place, as indicated in
Table 1-1 (Donnell, 1977). The thickness of the Green River Formation ranges
from about 3 meters (10 feet) to 610 meters (2,000 feet) with overburden thick-
ness ranging from zero at outcrops to 490 meters (1»600 feet). The most eco-
nomical deposits are at least 9 meters (30 feet) in thickness and yield at
least 95 liters (25 gallons) of oil per 0.91 tonne (1 ton) of oil shale. The
known resources of the high-grade shale are equivalent to 95,500 million m3
(600 billion bbl) of oil (Figure 1-1), out of which at least 13 billion m3 (80
billion bbl) of oil are recoverable by present technology (Yen, 1976a). For
comparison, this amount of oil far exceeds the sum of the resources at Prudhoe
Bay in Alaska and in the Continental Shelf reserves on the U.S. west coast.
Oil shale industries have developed over the past 100 years in France,
Scotland, Sweden, Spain, South Africa, Australia, the Estonia S.S.R., China,
and Brazil (Prien, 1976). Attempts in the United States to develop oil shale
into a mature industry have lasted for more than 50 years (McKee, 1925). In
the early days, there was even a journal devoted to this endeavor. However,
progress has been slow toward realizing a fully matured oil shale industry.
For example, the estimated supply of shale oil for 1985 is only 0.2 to 2.1
Quads (1 Quad = 27.8 million m3 [175 million bbl] of crude, or 1015 Btu), the
lower figure being more realistic. This means that shale oil probably will
account for only about 1 percent of total oil consumption in 1985, as shown in
Table 1-2 (Yen, 1976a). The constraint is imposed by two major factors:
1. The price of petroleum crude oil. In June 1977, the top price of
crude was $13.50 per 0.2 m3 (1 bbl). This price leaves little
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TABLE 1-1. GLOBAL OIL SHALE RESOURCES3
a
From Donnell, 1977.
Country Billions of m (Billions of bbls)
United States
Brazil
U.S.S.R.
Zaire
Canada
Italy (Sicily)
China
Morocco
Sweden
Burma
West Germany
Great Britain
Thailand
318.0
127.3
17.9
16.0
7.0
5.6
4.4
0.6
0.4
0.3
0.3
0.2
0.1
(2,000.2)
( 800.8)
( 112.6)
( 100.6)
( 44.0)
( 35.2)
( 27.9)
( 4.0)
( 2.5)
( 2.0)
( 2.0)
( i.o)
( 0.8)
-------
95(600)
i
21 (130)
13(80)
8.6(54)
1
Figure 1-1. Oil shale resources (in billions of cubic meters
[barrels] of oil) present on tracts that may be
developed in the next decade, present on tracts
designated by Federal Government (USDI, 1973),
removable by present technology, accessible, and
total high-grade resources (from Yen, 1976a).
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TABLE 1-2. ESTIMATES OF SHALE OIL SUPPLY IN 1985*
Supply
Agency
Federal Energy Administration
Project Independence
Ford Foundation
National Petroleum Council
National Petroleum Council
National Academy of Engineering
Joint Committee on Atomic Energy
Institute of Gas Technology
Commerce Technical Advisory
Board
Exxon Energy Outlook
Exxon Energy Outlook
Estimate
dates
11/74
09/74
12/72
08/74
05/74
05/74
12/73
02/75
01/76
02/77
Quads
2.1*
lc
1.5d
0.2
1
0.2
2.1
0.5
0.7e
0.5e
(millions
of m3)
(58.4)
(27.8)
(25.8)
( 5.5)
(27.8)
( 5.5)
(58.4)
(14.0)
(19.5)
(14.0)
(millions
of bbl )
(367.5)
(175 )
(162.5)
( 35 )
(175 )
( 35 )
(367.5)
( 87.5)
(122.5)
( 87.5)
The total energy demand for 1985 is estimated as 108 Quads (Q)(3.1
percent growth) or 125 Q (4.3 percent growth). Total domestic supply
is approximately 94 Q and still requires 14 Q (based on 3.1 percent
growth) from imports. Domestic oil supply is about 25 Q, and syn-
thetic oil supply is estimated as 0.3 Q in 1985.
Based on $11 oil accrued supply.
c Based on technological growth of pre-1974 status.
This value is for Case I; for Cases II a*\d III, 0.80 Q; and for Case IV,
0.20 Q. Case I is the most optimistic supply condition, and Case IV is
the lowest level based on 1970 trends.
e Including synthetic oil from coal.
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margin for extracting oil from shale. Thus the shale oil extraction
industry hinges on the future international and national economic
and political situation.
2. The availability of pollution control science and technology.
Present data on the environmental impact of oil shale extraction,
especially in relation to human health, are insufficient.
Currently, petroleum companies are becoming more optimistic about the
commercial prospects of the 95.4 billion m3 (600 billion bbl) of syncrude
locked in the Green River Formation of the tristate area of Colorado, Utah,
and Wyoming (Chemical Week, 1977). This optimism is based on technological
and economic factors that may give shale oil a good chance to compete with
conventional crude oil.
The speed with which western oil shale resources are developed is related
to a variety of technological, economic, environmental, political, and legal
factors. The following review of the present status of the four Colorado and
Utah leases resulting from the Federal Prototype Oil Shale Leasing Program
provides an overview of near-term plans (Table 1-3).
On August 30, 1977, the Department of Interior approved the revised
Detailed Development Plan (DDP) for Tract C-b in Colorado. This plan calls
for development using a modified in situ process. Ashland Oil and Occidental
Petroleum, partners on Tract C-b, are initiating mine development at this
time. However, several environmental groups (Environmental Defense Fund,
Colorado Open Space Council Mining Workshop, and Friends of the Earth) have
asked the U.S. Department of Interior (USDI) to prepare a supplemental envi-
ronmental impact statement (EIS) on C-b (and C-a). The USDI felt that the
original EIS was sufficient, so the request was denied.
On September 22, 1977, the USDI approved a modified in situ DDP for
Colorado Tract C-a. Development is being pursued by Rio Blanco Oil Shale
Corporation (Standard of Indiana and Gulf Oil Corporation).
The status of the Utah oil shale tracts (U-a and U-b) i$ somewhat more
complex. Certain questions concerning the basic ownership of the tracts have
arisen as a result of several recent legal actions:
• A suit is being pursued by the State of Utah against the U.S.
Department of Interior in which Utah has laid claim to 157,255
acres of land (which includes Tracts U~a and U-b) as lands in
lieu of State lands previously disposed of by the Federal
Government. The U.S. District Court in Salt Lake City has
ruled in favor of the State of Utah. This decision is being
appealed by the Federal Government.
• Peninsula Mining, Inc. has filed for a preferential lease to
the 157,255 acres obtained by the State of Utah as in lieu
of lands in the above described decision.
-------
TABLE 1-3. CURRENT OIL SHALE DEVELOPMENT PROJECTS
Project or location
Sponsor
Technique
Syncrude
capacity
mVday
(bbl/day)
Estimated
cost
($mi 11 ion)
Federal Tract C-b
(Colorado)
Colony Development
(Colorado)
Federal Tract C-a
(Colorado)
Multinn neral
(Colorado)
Sand Wash (Utah)
Parachute Creek
(Colorado)
White River Shale
Project (Utah)
[Federal Tracts
U-a and U-b]
Occidental Petroleum and
Ashland Oil
Atlantic Richfield and
The Oil Shale Corp.
Gulf Oil and Standard
Oil (Indiana)
Superior Oil
The Oil Shale Corp.
Union Oil of California
Sun Oil, Phillips Petro-
leum, and Standard Oil
(Ohio)
Modified in situ retorting 9,063 442
(no surface retorting) (57,000)
Room-and-piliar mining; 7,473 1,132
TOSCO II retorting (heated (47,000)
ceramic spheres)
Modified in situ retorting 239 93a
(with surface retorting) (1,500)
Room-and-piliar mining; 2,115 300
circular-grate retorting; (13,300)
recovery of soda and
alumina
Combination in situ and 11,925 1,000
surface retorting (75,000)
Room-and-piliar mining; 1,240 123
direct heated rock pump (7,800)
retorting
Room-and-piliar mining and 15,900 1,610C
surface retorting (Paraho (100,000)
and TOSCO II)
For 5-year development program with intermittent production in demonstration
units; projected commercial capacity is 12,160 m3/day (76,000 bbl/day).
For the first module of stated capacity.
c For prototype module.
Much smaller demonstration unit would be part of $246-million development
program proposed as joint venture with ERDA.
-------
* Recently (January 1977), a Colorado court ruled that under cer-
tain conditions unpatented oil shale mining claims could be
valid claims. Unpatented claims exist on Tracts U-a and U-b.
As a result of these ownership issues, the White River Shale Project sought
and received (on May 31, 1977) an injunction effectively suspending their lease
agreement until these matters could be clarified. This injunction is being
appealed by the Federal Government at this time.
Other than these activities, the Department of Energy has initiated a
number of cost-sharing contracts with various industries-for example, the
Equity Oil Company project for superheated steam recovery of leached zone oil
shale by in situ method, the Talley-Frac Corporation and Geokinetics tech-
niques for the true in situ recovery (present contract to Talley-Frac Corpora-
tion is for detonation and fracturing only), and the Occidental process of
modified in situ shale recovery methodology. Other than the research and
development effort of the Laramie Energy Research Center, different govern-
ment laboratories such as Lawrence Livermore Laboratory, Sandia Laboratories,
Los Alamos Scientific Laboratory, and Oak Ridge National Laboratory, as well
as a number of universities, contribute greatly toward process modeling,
resource recovery, and environmental aspects of oil shale development. De-
velopment plans by private industrial concerns, such as Colony, Union Oil,
Superior, and TOSCO, are summarized in Table 1-3.
Thus the near-term future of western oil shale development is somewhat
uncertain. However, petroleum specialists in government and industry have
conjectured that by the end of this century, the U.S. economy and resources
can easily develop an oil shale processing industry with an aggregate syn-
crude output of 160,000 m3 to 320,000 m3 (1 million to 2 million bbl) per
day.
GEOLOGICAL SETTING OF UINTA BASIN
Oil shales from the Green River Formation of the Western United States
were formed from the sediments deposited in the two Eocene lakes: Lake Uinta
in Colorado and Utah and Lake Gosiute in Wyoming (Figure 1-2). During their
life span of 6 million years, these lakes were chemically stratified into two
stable zones (Bradley, 1931). The upper layer was relatively fresh and was
able to support life. The lower layer, primarily a solution of sodium carbon-
ates, was a strongly basic and reducing environment. This chemical environ-
ment contributed to the preservation of organic matter, largely from algal
productivity in the upper layer of the lakes.
During much of the Eocene period, Lake Uinta covered a large area from
central and northeastern Utah to northwestern Colorado. Within this large
area, many types of environments existed. Sediments deposited in the western
and southwestern parts of the Uinta Basin in Utah are lithologically and
ecologically different from their strati graphic equivalent to the east in
the Piceance Creek Basin of Colorado. For example:
• The lower part of the Parachute Creek Member of the Green River
Formation (the uppermost member of this formation) in the
-------
36'
SHADED AREAS ARE
HIGH LANDS
106'
Figure 1-2. Paleogeography in late early to middle Eocene
time (from McDonald, 1972).
8
-------
Piceance Creek Basin contains bedded evaporites that are
absent in the Uinta Basin.
• The Garden Gulch Member, which underlies the Parachute Creek
Member, contains rich oil shales in the Piceance Creek
Basin, while they are much thinner and rarer in the Uinta
Basin.
The Uinta and Piceance Basins were allowed to follow differing develop-
mental pathways because of the presence of the Douglas Creek Arch, which
separates the two basins (McDonald, 1972).
The Piceance Creek Basin is economically very important because it con-
tains the richest and thickest oil shale deposits in the world. The Parachute
Creek Member contains most of the oil shale in the Green River Formation.
Much of the oil in the Parachute Creek Member is contained in the Mahogany
Zone (Figure 1-3). The rich brown color of the kerogen in these strata ex-
plains the name. Certain beds in this zone yield as much as 342 liters (90
gallons) of oil per 0.91 tonne (1 ton). The zone varies in thickness from
less than 15 meters (50 feet) to more than 60 meters (200 feet).
The Uinta Basin has undergone less exploration and evaluation than the
Piceance Creek Basin. The most important oil shale deposits are located in
the eastern part of the basin, where they occur in a 122-meter (400-foot)
thick sequence above and below the Mahogany Zone.
Most of the oil shale development in Wyoming occurred in Lake Gosiute.
This lake was separated from Lake Uinta by the east-west-stretching Uinta
Mountains, which contributed sediments to both lakes. The oil shales in
Wyoming are located in two basins, the Washakie and the Green River. Both
areas contain low-grade oil shale, i.e., the quantity is less than 57 liters
(15 gallons) of oil per 0.91 tonne (1 ton). At times, Lake Gosiute was quite
saline, resulting in large amounts of bedded trona or trona mixed with
halite.
In conclusion, the deposits in Uinta Basin are most extensive and have
not yet been fully explored. The Utah shales appear to have less trona-type
materials than those found in Wyoming. The ownership distribution of western
oil shale lands, which will play an important role in their development, is
illustrated in Figure 1-4.
OIL SHALE
A number of diverse fine-grained rocks, termed oil shales, have been
found to contain refractory organic material that can be refined into fuels.
The organic material in these rocks is composed of a bitumen fraction (solu-
ble in common organic solvents) consisting of about 20 percent by weight of
identifiable organics, the remainder being insoluble kerogen. All oil shales
appear to have been deposited in shallow lakes or seas that supported a
dense algal biota. The composition and oil yields of some oil shales are
listed in Table 1-4 (Yen and Chilingarian, 1976).
-------
^iiiiiiiiii! Datum is top p;
^:;;:H;j;i of richest bed;;i
r-*^iin Mahogany j'rl
iilPiiini ledge or zone Iji
':"~: £^-W-:."£
'''*",'••'. *• '.'••"..'••. •.
Green River
Wosotch Formation -"-^^-s^s--;
EXPLANAT 0
ton '« 0.907 tonne
OH shole ond
morlstone
Other rock types
Oil yield in gallons per
fcS^>s- Wosotch Formotion
Saline mmcrols greater
than 10 percent ^^rggr 122 in -"400 _ftIC16_lan = 10 roil
Fiaure 1-3 Cross section B-B' of Green River Formation in Piceance Creek Basin,
' Colorado (U.S. Department of Interior, 1973).
-------
COLORADO
UTAH
WYOMING
TOTAL
Non-federal land
Federal land with unpatented oil shale
placer claims
Federal land with recent unpatented
metalliferous mining claims
Federal land for which existence of possible
encumbrances has not been ascertained
W W W » W 9 • • • *"»~ ••••••]
•v.v.v.'.v.v.v.v.v
^•.»,»,»,».>.»_».».«.».».*,».»,».«i
1000 2000 3000 4000 5000
(404.7) (809.4) (1214.1) (1618.8) (2023.5)
ACRES, thousand
(HECTARES, thousand)
6000 7000 8000 9000
(2428.2) (2832.9) (3237.6) (3642.3)
Figure 1-4. Oil shale lands-Green River Formation (National Petroleum Council, 1972).
-------
TABLE 1-4. COMPOSITION AND OIL YIELD OF SOME OIL SHALES
ro
Organic carbon
Location of sample (percent)
Kiligwa River, Alaska3
Plceance Creek, Colorado8
Elko, Nevadab
Dunnet, Scotland9
lone, California
Sao Paulo, Brazil a
Puertollano, Spain3
Shale City, Oregon3
Cool away Mt., Australia3
Soldiers Summit, Utahb
ErmeTo, South Africa3
New Glasgow, Canada3
53.9
12.4
8.6
12.3
62.9
12.8
26.0
25.8
81.4
13.5
52.2
7.92
Sulfur
(percent)
1.5
0.63
1.1
0.73
2.1
0.84
1.7
2.2
0.49
0.28
0.74
0.70
Nitrogen
(percent)
0.30
0.41
0.48
0.46
0.42
0.41
0.55
0.51
0.83
0.39
0.84
0.54
Ash
(percent)
34.1
65.7
81.6
77.8
23.0
75.0
62.8
48.3
4.4
66.1
33.6
84.0
Oil yield
liters/0.91 tonne
(gal Ion/ ton)
528.2
106.4
31.92
83.6
197.6
68.4
178.6
182.4
760.
64.6
380.
9.4
(139.0)
( 28.0)
( 8.4)
( 22.0)
( 52.0)
( 18.0)
( 47.0)
( 48.0)
(200.0)
( 17.0)
(100.0)
( 2.4)
Data from Robinson, 1976.
}Data from McKee, 1925.
-------
Oil shales interpreted in terms of material science can be classified as
"composites"-tightly bound organics and inorganics as shown in Figure 1-5.
An illustrated hypothetical structure is shown in Figure 1-6. The proportion
of organics in oil shale rarely exceeds 25 percent by weight. The weight
percentage, however, of organics for a typical oil shale yielding 95 liters
(25 gallons) of oil per 0.91 tonne (1 ton) is only about 14 percent (Figure
i-f) •
Kerogen constitutes the bulk of available organic material in oil shale.
Therefore, any liberation of useful hydrocarbons depends on the degree to which
kerogen can be converted to liquid fuel precursors. Green River kerogen con-
sists of polycyclic subunits interconnected by long-chain alkanes and isopren-
oids. This matrix also contains substantial amounts of entrapped uncondensed
alkanes and fatty acids. The extensive cross-linking of these subunits pro-
duces the insolubility characteristic of kerogen (Yen, 1976b). The structure
of kerogen of Green River oil shale has recently been elucidated by Young and
Yen (1977) (Figure 1-8). Individual studies of clusters and bridges are pre-
sented in Figure 1-9 (Yen, 1976c).
The average composition of the bitumen from the Green River oil shale is
summarized in Table 1-5. The major components are n-alkanes, branched and
cyclic alkanes, aromatic oils, resins, and asphaltenes (Robinson, 1976). Bio-
markers such as isoprenoids, stearanes, pentacyclic triterpanes, carotenes,
and porphyrins have been identified (Figure 1-10).
The mineral composition has been recently reviewed and summarized. In
general, there are carbonates, silicates, pyrites, and other sulfides (Shanks
et al., 1976). Some of the minerals are listed in Tables 1-6 and 1-7.
The wide range of properties observed in oil shales from different areas
prohibits development of all but a very generalized concept of their genesis.
Nonetheless, certain factors appear to be necessary for deposition and collec-
tion of the inorganic and organic material that will, after burial, become oil
shale. It is evident that oil shales result from the contemporaneous deposi-
tion of fine-grained mineral debris and organic degradation products derived
from the breakdown of biota. Conditions leading to the collection and concen-
tration of the organic and inorganic components of oil shales must then
include abundant organic productivity, early development of anaerobic condi-
tions, and longevity of the lake systems.
Oil shales probably developed in bodies of water, either marine or fresh,
that were fairly calm, such as isolated marine basins, lakes, or deltaic
swamps. The prevailing climate during deposition was fairly dry, similar to
that considered favorable for coal formation.
Continued sedimentation, perhaps coupled with subsidence, provided over-
burden pressure that effected compaction and diagenesis of organically rich
strata. Chemical activity at low temperature (less than 150°C [300°F])
resulted in loss of volatile fractions, ultimately producing a sedimentary
rock with a high content of refractory organic residues.
13
-------
OIL SHALE
INORGANIC MATRIX
QUARTZ
FELDSPAR
CLAY (ILLITE AND CHLORITE)
CARBONATES (CALCITE AND DOLOMITE)
PYRITE AND OTHER MINERALS
BITUMENS (SOLUBLE IN
KEROGENS (INSOLUBLE IN C$2)
(CONTAINING U,, FE, V., Ni, Mo)
Figure 1-5. General scheme of oil shale components
(adopted from Yen, 1975a).
QUART*
ILLITE
"CLAYEY1
CARBONATE
MICA
PORE SPACE
Figure 1-6. Schematic section of oil shale (Yen, 1977),
14
-------
onolcite
quartz
illite.
monlmorillopite
muscovlte
O.86%
NaAISi2O6 H20 4.3%
plagioclase
orfho close
dolomite
1.28%
H
1.42%
SI02 8.6%
12.9%
CoAI2Si208 16.4%
O
22.2%
Co 9.5%
Mg 5.8%
C 5.6%
C
11.1%
CaMg
(co3)2
43.1%
Bitumen
Kerogen
Mineral Matter
86.2%
Organic Matter
13.8%
Oil Shale
Figure 1-7. Chemical analysis of a Green River oil shale
(Yen and Chilingarian, 1976).
15
-------
/vVSA
i i I i I
ENTRAPPED SPECIES
UNBRANCHED ALIPHATIC STRUCTURE
BRANCHED ALIPHATIC STRUCTURE
POLYMETHYLENE BRIDGES
'CYCLIC' SKELETAL CARBON STRUCTURE
(MAINLY SATURATED RINGS)
Figure 1-8. Kerogen structure of Green River oil shale (Young and Yen, 1977).
16
-------
COMPONENTS
BRIDGES
©
©
ISOPRENOIDS
STEROIDS
TERPENOIDS
CAROTENOIDS
D S —S
0 -0-
0
E -C—0—
\
H
DISULFIDE
ETHER
ESTER
ISOPRENOIDS
HETEROCYCLIC
A CH3-CH-(CH2),5-CH-CH2-CH2)7-CH,
ALKADIENE
Figure 1-9. Components and bridges of a Green River oil shale kerogen (Yen, 1976c).
-------
JUAN1
(CONT.FROM ABOVE)
TIME (mm)
Figure 1-10. Biomarkers in Green River oil shale bitumen (Yen, 1973),
18
-------
TABLE 1-5. COMPOSITION OF BITUMENS IN GREEN RIVER OIL SHALE (Yen, 1977)
Classes of components
Percent
by weight
Principal components
N-alkanes
Branched and cycli c
alkanes
Aromatic oil
Resins
Asphaltenes (including
fatty acids)
3.4 - 3.9
23.6 - 30.3
2.7 - 3.3
54.4 - 57.4
9.0 - 12.5
C13-C35 with Ci? and C29 as maxima
Odd-to-even predominance at 3:1 or 4:1
Chain isoprenoids (farnesane, pristane, and phytane)
C27, C28, C2g stearanes
C30 and C31 pentacyclic triterpanes
Ci»o carotanes
Alkyl benzenes
Alkyl tetralins
Mixed aromatic and naphthem'c compounds
M.W. ~625
Indanones
TetraTones, acetylindanes
Hydroxypyrrole, di ketopyrrole
M.W. ~1,320
Porphyri ns
Cio-C3.» fatty acids (n, iso, anti-iso)
C27-C29 sterols
-------
TABLE 1-6. CARBONATE MINERALS IN GREEN RIVER FORMATION
(Shanks et al., 1976)
Name
^^—<•—^*—•—^
Single carbonates
Calcite
Nahcolite
Trona
Magnesite
Wagscheiderite
Thermonatrite
Siderite
Aragoni te
Compound carbonates
Dol omite
Shortite
Barytocalcite
Dawsoni te
Northupite
Pirssonite
Gaylussite
Ankerite
Eitelite
Bradleyite
Formula Abundance
^^•^^^W^W^^^M^A^^W-V^fe^Ml
CaC03 Ubiquitous
NaHC03 Abundant
Na2C03-NaHC03-2H20 Abundant
MgC03 Rare
Na2C03-3NaHC03 Rare
Na2C03-H20 Rare
FeC03 Rare
CaC03 Rare
CaMg(C03)2 Ubiquitous
Na2Ca2(C03)3 Widespread
BaCa(C03)2 Widespread
NaAl(C03)(OH)2 Abundant.
Na2Mg(C03)2-NaCl Abundant
Na2Ca(C03)^-2H20 Abundant
Na2Ca(C03)2-H20 Abundant
(Mg0.8sFe0.i5Ca)(C03)2 Abundant
Na2Mg(C03)2 Rare
MgNa3C03POu Rare
20
-------
TABLE 1-7. SILICATES IN THE GREEN RIVER OIL SHALE (Shanks et al., 1976)
Name
Formula
Abundance
Simple silicates
Quartz
Orthoclase
Plagioclase
Albite
Acmite
2ooli tes
Anal cite
Natrolite
Clays
Montmorillonite
IIlite
Kalite
Stenvenite
Longhlinite
Si02
KAlSi308
NaAlSi308
NaFeSi206
NaAlSi206'H20
Na2Al2Si3Oio-2H20
AU(SM10)2(OHK
H,>Al2Si209
Hi6Na2Mg3Si6021t
Ubiquitous
Widespread
Widespread
Widespread
Rare
Widespread
Rare
Widespread
Locally
abundant
Locally
abundant
Locally
abundant
21
-------
There is almost no dispute that the genesis of kerogen and bitumen is
biological, largely derived from the lipid fraction of algae. Taphonomic and
biostratinomic processes allowed further conversion of the fossilized materi-
al. The geochemical deposits are summarized in Table 1-8.
TABLE 1-8. CLASSIFICATION OF MAJOR OIL SHALES (Yen, 1975b)
Location
Large lake
basins
Type
Green River Formation
** • ^ • ^ i n •
Age
Eocene
Source
Cyanophycea
Shallow seas on
continental
platform and
shelves
Small lakes,
bogs, lagoons,
-associated with
coal-forming
swamps
Congo
Albert Shale,
New Brunswick
Alaskan Tasmanite,
Brooks Range
Phosphoria Formation
Monterey Formation
Irati Shale, Brazil
NSW Torbanite
Fusan, Manchuria
Triassic
Mississippian
Mississippian
Permian
Miocene
Late Permian
Devonian
Tertiary
Unknown-may
be red
algae
Xanthophyceae
Botryocoeaus
DEVELOPING WESTERN OIL SHALE RESOURCES
By 1977, there was still no large-scale commercial production of domes-
tic shale oil. The balance between energy supply and demand controls the
position of oil shale tn the U.S. energy market. The oil embargo in 1973-74
and the subsequent increase in petroleum prices by OPEC intensified the con-
cerns over energy supply and simulated the interest in developing oil shale
as a source of domestic oil supply (Smith and Jensen, 1976).
Federal land ownership is one of the factors that affects oil shale
development. More than 80 percent of the oil shale lands underlain by the
Green River Formation, containing the richest and thickest deposits, are
owned by the Federal Government. In 1973, the Department of Interior's
Prototype Oil Shale Leasing Program was launched. Four tracts of commercial
shale oil production were leased in 1974 by bonus bidding. Of the privately
held land, two-thirds is owned by the five major oil companies (Union,
Exxon, Texaco, Mobil, and Conoco). The locations of oil shale development
activity are indicated in Figure 1-11.
22
-------
GREEN
RIVER
WYO
UTAH
Operating tracts
Tracts not operating
Offered .not teased
LEGEND
Area of oil shale deposits
Areo of nohcolite or trona
deposits
OCCIDENTAL
Area of 95 I./0.907 tonne
(25 gal./ton) or richer
oil shale 3.1m (10 ft.) or
TT
2E 4
6
1 i I ' I ' I
8 IDE 12 14
T ' I ' » « I ' f ' I ' I ' I ' I ' 1 ' » ' I '
16 18 2OE 22 24 26 28 3OE 32 34 36 38 4OE
RANGE
Figure 1-11. Current oil shale development activity in tristate area,
23
-------
The recovery of shale oil from oil shale is based on the principle of
retorting (thermal decomposition) of the kerogen and bitumen within the oil
shale matrix. In general, surface retorting processes can be classified as
external heating or internal heating by:
• Hot gases (BuMines gas combustion DEI kiln, Union Oil,
N.T.U., TOSCO)
• Hot fluids (Cameron-Jones [Petrosix])
• Hot solids (TOSCO II, Lurgi-Ruhrgas).
The most desirable process for retorting oil shale should have as many
of the following characteristics as possible (Carpenter et al., 1977):
• It should be continuous
• It should have a high feed rate per unit cross section area
of retort
• It should have high oil recovery efficiency
• It should require a low capital investment and possess a high
operating time factor (low down-time) with low operating
costs
• It should be thermally self-sufficient-that us, all heat and
energy requirements should be supplied without burning any
of the product oil
• It should be amenable to enlargement into high-tonnage
retorts rather than to a multiplicity of small units
• It should require little or no water because the Green
River oil shale deposits are located in an arid region
• It should be capable of efficiently processing oil shale of
a wide range of particle sizes to minimize crushing and
screening
• It should be mechanically simple and easily operable.
The classification of all in situ (subsurface) processes has been summa-
rized (Yen, 1976a). There are currently two versions of in situ processes;
one is the modified in situ, and the other is the true in situ process. The
modified in situ process is currently being developed by the Occidental
Petroleum Corporation, and it seems promising as a viable additional tech-
nique for oil shale production (see Table 1-3). In general, in situ retort-
ing processes can be classed as follows:
24
-------
• Subsurface chimney
- Hot gases (Atlantic Richfield, McDonnel Douglas,
Continental Oil, Mobil Oil)
- Hot fluids (Shell Oil, Cities Service Oil» Garrett
Corp.)
- Chemical extraction (Shell Oil)
• Natural fractures
- Unmodified (Shell Oil, Marathon Oil, Resources R&D)
- Enlarged by leaching (Shell Oil)
• Physical induction - no subsurface voids (Woods R&D Corp.).
The results of the Federal oil shale lease offerings are summarized in
Table 1-9. The Utah Tracts U-a and U-b are jointly located 1H the eastern
part of the Uinta Basin, close to the White River. Development plans include
conventional room-and-pillar mining and aboveground (ex situ) kerogen extrac-
tion methods.
Among the conventional retorting methods, the Paraho {irtiCess is consider-
ed an improved version of the gas-combustion process. The Paraho gas combus-
tion process was originated by the U.S. Bureau of Nines at Anvil Points,
Colorado, and was improved by a consortium of six petroleum companies (Mobil,
Humble, Pan American, Sinclair, Continental, and Phillips), in 1972, Develop-
ment Engineering, Inc. (DEI) leased the Anvil Points facilities for oil shale
retorting, and in 1973, the Paraho Oil Shale Project of 17 companies was
developed. This retorting process produced 1,590 m3 (10,000 bbl) of shale
oil for the Navy in a 56-day continuous run in 1975 at the operating capacity
of 408 tonnes (450 tons) per day.
Another process is employed by The Oil Shale Corporation (TOSCO). In
1964, TOSCO initiated the Colony Development Operation, which included Sohio,
Cleveland Cliffs, Atlantic Richfield, and TOSCO (later Ashland Oil and Shell
Oil replaced Sohio and Cleveland Cliffs). TOSCO II uses an externally heated
configuration. A semiworks plant of 907 tonnes (1,000 tons) capacity per day
near Grand Valley, Colorado, operated until 1972. Both Paraho and TOSCO II
processes are projected for use on the U-a and U-b leases. The retorting will
mainly use the available Paraho technology (85 percent) supplemented by TOSCO
II (15 percent) for fines.
25
-------
TABLE 1-9. RESULTS OF FEDERAL OIL SHALE LEASE OFFERINGS
no
en
Col orado
C-a
C-b
Utah
U-a
U-b
Wyomi ng
U-a
W-b
^•— • — — ••••••••••••••••••-.i^—i 1 1 •• i
Area
(hectares)
2,060
2,062
2,073
2,073
2,070
2,070
•^^•••*II^M^B*^^H'^«>*M*IV^^^^^mW^HMVl^~*'
Recoverable
(millions of m
200
116
53
43
57
57
resource estimate
3) (millions of bbl)
(1,300)
( 723)
( 331)
( 271)
( 359)
( 359)
VHWMMI-^HWIHI-BVHMVMW-V-M^^
High bonus
bid
($ million)
210
118
76
45
None
None
•••••••VMVVMIHVMhlMIMMV^^
Original lessee
Rio Blanco Oil Shale
Project (Standard
of Indiana, Gulf Oil
Corp. )
Atlantic Richfield,
Ashland Oil, Shell
Oil, The Oil Shale
Corp. (TOSCO)a
Sun Oil Co. and Phillips
Petroleum Co."
Sohiob
-
• i .^— ^— 1 1 M • •• • -
a Present lease partners are Ashland Oil and Occidental.
b White River Shale Project will jointly develop Tracts U-a and U-b.
-------
SECTION 1 REFERENCES
Bradley, W.H., Origin and Microfossils of the Oil Shale of the Green River
Formation of Colorado and Utah, Professional Paper 168, U.S. Geological
Survey, 1931.
Carpenter, H.C., H.B. Jensen, and A.W. Decora, "Potential Shale Oil Production
Processes," Preprint, American Chemical Society, Division of Fuel Chemistry,
Vol 22, No. 3, pp 49-65, 1977.
Chemical Week, pp 17-19, July 13, 1977.
Donnell, J.R., "Benefits and Constraints of Oil Shale and Tar Sand Development
in Arid Areas," Conference on Alternative Strategies for Desert Develop-
ment and Management. Sacramento. California, May 1-June 10. 1977.
Hubbert, M.K., "Survey of World Energy Resources," Energy and the Environment,
Cost-Benefit Analysis (R.A. Karam and K.E. Morgan, eds), Pergamon
Press, pp 3-38, 1976.
McDonald, R.E., "Eocene and Paleocene Rocks of the Southern and Central Basins,"
Geologic Atlas of the Rocky Mountain Region, Rocky Mountain Association of
Geologists, pp 243-260, 1972.
McKee, R.H., Shale Oil. Chemical Catalog Company, 1925.
National Petroleum Council, An Initial Appraisal by the Oil Shale Task Group,
1971-1985, 1972.
Norman, H., "Future Availability of Oil," Conference on World Energy Supplies
Financial Times. BOAC, September 18-20, 1973.
Prien, C.H., "Survey of Oil-Shale Research in the Last Three Decades," Oil
Shale (T.F. Yen and G.V. Chilingarian, eds), Elsevier, pp 235-267, 1976.
Robinson, W.E., Origin and Characteristics of Green River Oil Shale," Oil
Shale (T.F. Yen and G.V. Chilingarian, eds), Elsevier, pp 61-79, 1976,
Shanks, W.C., W. Seyfried, W.C. Meyer, and T.J. O'Neil, "Mineralogy of Oil Shale,"
Oil Shale (T.F. Yen and G.V. Chilingarian, eds), Elsevier, pp 81-102, 1976.
Smith, J.W., and H.B. Jensen, "Oil Shale," Encyclopedia of Energy, McGraw-
Hill, pp 535-541, 1976-
U.S. Department of Interior, Final Environmental Statement for the Prototype
Oil Shale Leasing Program, Vol 1, p 11-116, 1973.
Yen, T.F., Feasibility Studies of Biochemical Production of Oil Shale Kerogen.
a preliminary report for National Science Foundation-RANN, No. GI-35683, 1973.
27
-------
Yen, T.F., "Facts Leading to the Biochemical Methods of Oil Shale Recovery,"
Analytical Chemistry Pertaining to Oil Shale and Shale Oil, (S. Siggia
and P.C. Uden, eds), University of Massachusetts, pp 59-79, 1975a.
Yen, T.F., "Genesis and Degradation of Petroleum Hydrocarbons in Marine Environ-
ments," Marine Chemistry in the Coastal Environment (T.M. Church, ed),
American Chemistry Society, pp 231-266, 1975b.
Yen, T.F., "Oil Shales of United States, A Review," Science and Technology of
Oil Shale (T.F. Yen, ed), Ann Arbor Science Publishers, pp 1-17, 1976a.
Yen, T.F., "Structural Aspects of Organic Components in Oil Shale," Oil Shale,
Elsevier, pp 129-147, 1976b.
Yen, T.F., "Structural Investigations on Green River Oil Shale Kerogen,"
Science and Technology of Oil Shale, Ann Arbor Science Publishers, pp
193-205, 1976c.
Yen, T.F., "Current Status of Microbial Shale Oil Recovery," The Role of Micro-
organisms in the Recovery of Oil, Engineering Foundation, National Science
Foundation, 1977.
Yen, T.F., and G.V. Chilingarian, "Introduction to Oil Shale," Oil Shale.
Developments in Petroleum Sciences, Vol 5, Elsevier, pp 1-11, 1976.
Young, O.K., and T.F. Yen, "The Nature of Straight-Chain Aliphatic Structures
in Green River Kerogen," Geochim. Cosmochim. Acta. Vol 41, No. 10,
pp 1411-1417, 1977.
28
-------
SECTION 2
MINING PROCESSES
The recovery of oil from oil shale resources involves tremendous quanti-
ties of materials that must be mined. A mature oil shale industry of 160,000
m3 (one million bbl) per day would require mining of 1.3 million tonnes (1.4
million tons) of oil shale, and disposal of 1.1 million tonnes (1.2 million
tons) of spent shale per day (Steele, 1976).
Either underground mining or surface mining may be employed for oil shale
recovery. Largely because of the depth of the major oil shale deposits, most
oil shale extraction is expected to be by underground mining. Surface mining
may be applicable to 15 to 20 percent of the shale reserves (Prien, 1974).
The advantage of the usually lower cost of surface mining is offset by the
more efficient applicability of underground processes to the mining of higher
quality oil shale, commonly located at depths of over 200 meters (over 600
feet).
In situ development is an alternative to conventional resource recovery
procedures, but it is still somewhat in an experimental stage of development.
These three major mining processes (underground, surface, and in situ) are
discussed in the following subsections.
UNDERGROUND MINING
The actual experience in mining oil shale has involved underground mining
techniques. Underground mining results in less surface disturbance than sur-
face mining and is desirable and practical for mining deep oil shale deposits.
Cameron Engineers, Inc. studied the technical and economic feasibility of
mining the deep, thick oil shale deposits of Colorado Piceance Creek Basin
(Hoskins et al., 1976). Four mining systems were evaluated and selected as
the most promising for further underground mining considerations. These four
mining methods are:
• Room-and-pillar mining
• Sublevel stoping with spent shale backfill
• Sublevel stoping with full subsidence
• Block caving using load haul dump (LHD).
29
-------
The general features of these mining approaches are presented in the
following paragraphs.
Room-and-Pillar Method
Room-and-pillar mining is the most suitable method for mining deep (460
meter [1,500 feet] or less), thick (9 to 27 meters [30 to 90 feetj), high-
grade (125 liters per tonne [30 gallons per ton]) oil shale deposits.
Major advances in underground mining of oil shale by using this method
have been achieved by the Bureau of Mines in its oil shale program (East and
Gardner, 1964). Commercial scale room-and-pillar mining of oil shale was dem-
onstrated by the Bureau of Mines at Anvil Points, Colorado, during 1944 to
1956. The Bureau of Mines research program for room-and-pillar mining en-
dorsed changes to rotary drilling in the mine headings and benches. Their
investigations have also looked into the use of modern haulage and loading
equipment and other operational improvements based on advances in quarry and
open-pit mine engineering. Mine safety procedures have also been studied as
part of the Bureau of Mine studies. This technique has been improved through
subsequent work by the Union Oil Company at Parachute Creek (1956 to 1958),
the Colorado School of Mines Research Foundation (1964 to 1967), and the
Colony Development Operation at Grand Valley, Colorado (U.S. ERDA, 1976b)
(1965 to present). Room-and-pillar mining is proposed for Oil Shale Tracts
U-a and U-b by the White River Shale Project (White River Shale Project,
1976). Mining techniques for modified in situ development (studied by Occi-
dental Petroleum at Logan Wash, Colorado) and room-and-pillar mining are the
only mining systems that have been tested on the oil shales of the Green
River Formation.
The first step in the development of a room-and-pillar operation is to
excavate the entrance through which mining equipment will be transported. The
contour and shape of adits are dictated by the topographic nature of the parti-
cular oil shale deposits. Once the adits have been established, mine develop-
ment proceeds by drilling horizontal holes along the sides of the room to be
excavated. An ammonium nitrate-fuel oil (ANFO) mixture is the explosive com-
monly used. The shale rubble is loaded on ore trucks with front end loaders for
conveyance outsiide the mine. Backhoe or other digging equipment is used to
scrape away the remaining shale. After all the shale is removed from the room,
roof bolts are installed to strengthen the mine roof. Pillars of shale rock
left in the mining zone support the roof against failure while mining continues
from room to room (Figure 2-1). According to the experiences of the Bureau of
Mines and other prototypes, optimum room-and-pillar sizes at Anvil Points,
Colorado were both 18x18 meters (60x60 feet) (Schramm, 1970). This results in a
resource extraction level of 75 percent with 25 percent remaining in the support-
ing pillars. The pillar size used for a particular situation, however, is
dependent upon the depth at which material is being mined. For Oil Shale Tracts
U-a and U-b, rooms and crosscuts are planned to be 18.3 meters (60 feet) wide.
Entries with a width of 15.2 meters (50 feet) to 16.8 meters (55 feet) are
planned. The pillar widths within the panels will be 18.3 meters (60 feet) to
24.4 meters (80 feet). Entry pillars will be 18.3 meters (60 feet) wide and
their height will be determined by panel access requirements and the statutory
maximum distance between crosscuts.
30
-------
scaling ^ roof bolting
Figure 2-1. Underground room-and-pillar mining operation (modified from U.S. ERDA, 1976a).
-------
Usually, a thick oil shale deposit (18 to 24 meters [60 to 80 feet]) is
mined in two steps. The upper bench with a 9- to 12-meter (30- to 40-foot)
height is mined first. Then the lower bench is developed in a similar proce-
dure, except that the blast holes are drilled vertically instead of horizon-
tally (Figure 2-1).
Several alternatives exist for the resource contained in the pillars after
completion of a room and pillar operation. These include:
• Leave the pillars in place
• Pull the pillars and recover for surface retorting
• Rubble the pillars and recover by in situ processing.
Economics and subsidence after mine collapse will dictate the viability
of these alternatives.
Other Underground Mining Methods
Block-Caving Method—
The block-caving method is employed for recovery of much thicker and
larger bodies of resource than those for which room and pillar methods are ap-
plicable. Generally, a large block of ore is first partly severed by driving
a series of horizontal passages, known as slusher drifts, through it or by a
series of finger raises (Figure 2-2). A finger raise is a vertical or in-
clined passage connecting two or more working levels. Pillars are left to
support the mine roof. The block is then undercut by removing a horizontal
slice at the bottom. The unsupported column of ore breaks and caves under its
own weight, and the broken ore is drawn off gradually from below. The develop-
ment work is conducted on three levels: the level at which the ore is under-
cut, the "grizzly" level at which the ore is drawn, and the haulage level at
which the ore is transported to the shaft.
LEVEL 2 FINGER
LEVEL 3
HAULAGE
ENTRY
Figure 2-2. Block-caving mining concept (Hoskins et al., 1976),
32
-------
Cut-and-Fill Stoping Method—
Mining operations proceed upward through the resource body in this method.
After a slice of ore is cut off, the broken material is removed and the stope
is filled with overburden accumulated from previous cuts until the floor of
the chamber is within 1 meter of the roof. The miners stand on the waste ma-
terial to make the next cut. The operation is thus conducted in cycles, con-
sisting of breaking off material, removing the broken ore, and filling the
empty space with waste. The filling is carried out mainly to support the walls
of the stope.
Cut-and-fill stoping may utilize two variations: the horizontal and the
inclined. In the horizontal cut-and-fill method, the back and filling are
maintained practically horizontal. In the inclined method the back and filling
are kept parallel to each other and the stope faces are inclined at about the
angle of repose of the waste material; this permits the use of gravity to re-
move the ore and to fill the excavated workings with waste material.
A sublevel inclined cut-and-fill method involves a block of ore first
subdivided into three horizontal sections by driving drifts throughout the
length of the block (Figure 2-3). Mining operations begin in the upper sec-
tion and retreat in a horizontal direction toward the shaft. The excavation
in the upper section is kept ahead of that in the lowest section. After the
ore is broken off and removed, each excavated section is filled up to the roof
with waste material brought from above by gravity.
&&vaa%3Egg»WK«gKS
Figure 2-3 Sublevel inclined cut-and-fill stoping mining concept
(modified from U.S. ERDA, 1976a).
33
-------
SURFACE MINING
Surface mining is an economical method for recovering shale deposits that
lie close to the ground surface. The economic use of surface mining is a func-
tion of the stripping ratio, i.e., the ratio of the amount of overburden materi-
al that must be removed to that of the resource recovered. The other important
factor is, of course, the grade of the oil shale recovered. An oil shale depos-
it can be economically surface-mined when the stripping ratio is in the range
of 0.5 to 2.5 (Prien, 1974, 1976; Steele, 1976). There are two basic types of
surface mining: stripping and open pit.
It has been estimated that overburden will have to be disposed of away
from the mine site during the first 10 years of operation. After that period,
mined-out pit areas will be available for the disposal of overburden while
allowing mining to proceed. Factors that affect this time frame are the
stripping ratio, production rate, thickness and grade of shale, etc. (Prien,
1976).
Stripping Method
This is a common surface-mining process for extraction of coal in the
Western United States. This mining approach is suitable only for oil shale
deposits that are within 300 meters (1,000 feet) of the surface with very low
stripping ratio (less than 0.5).
Explosives are used to loosen the overburden, and large draglines are
commonly used to remove it. Power shovels are employed to excavate the ex-
posed ore seam and load the shale onto trucks. The overburden is stored at a
nearby site until the mined area is large enough to allow backfilling opera-
tions without interfering with mining advance. A typical strip mining opera-
tion is shown in Figure 2-4. The block-and-cut modified strip mining method
(Figure 2-5) can provide high-quality land reclamation after the resource is
removed. The overburden from the first mining area is removed, and then the
resource is cut away. Mining proceeds in the neighboring zone, with the
overburden being deposited and contoured in the first mined area. Mining
progresses laterally through additional cuts, with the overburden in each area
moved to backfill the preceding cuts on a continuous basis. Finally, the
spoil from the initial mining zone is used to backfill the last mined areas.
1 ?
Open-Pit Method
Open-pit mining is a highly developed process that is widely used in
mining other ores and may be practical for oil shale in some areas. For
western oil shale deposits, surface mining will be primarily of the open-pit
type. It is suitable for deeper deposits than is strip mining and can be used
where the stripping ratio is between 0.5 and 2.5 (National Petroleum Council,
1972). The preliminary development plans for Oil Shale Tract C-a included the
primary mining approach (Rio Blanco Oil Shale Project, 1976).
34
-------
PREVIOUS
SPOIL PILES
Figure 2-4. 'Typical strip mining operation (modified from U.S. ERDA, 1976a),
Figure 2-5. Block-and-cut modified strip mining concept.
35
-------
In open-pit mining, the overburden is loosened using explosives implanted
in drill holes. The ore is removed by power shovels and trucks. As the pit
is deepend, a series of benches is produced, which provide stability for the
sides of the pit (Figure 2-6). When the desired shale deposit is reached, it
is then loosened by blasting, loaded into trucks, and conveyed to crushers and
other process areas.
surface
bench height
•:... rood
rood •.•.»;.••. • :•:: :v.v.v.v.v.A/:: :.'.•:
••'•••'••'*• f tom ••"•••«.
(b)
Figure 2-6. Open-pit mining operation: (a) isometric [modified from Steele,
1976] and (b) section [modified from U.S. ERDA, 1976a3.
36
-------
In open-pit mining, as in strip mining, large amounts of overburden are
generated. A suitable site for storage must be located. About 80 percent of
all mined oil shale material is discarded as shale residue. The overburden
and residue must be stored away from the mine site initially until pit dis-
posal is feasible.
Theoretically, open-pit mining can optimally recover 85 percent or more
of the available resource. However, because of the area required for disposal
(including in-pit disposal of overburden and spent shale), this figure may not
be achievable in practice (White River Shale Project, 1976).
One important concept of open-pit mining is that the waste or capping
directly over the ore not only must be removed but removed beyond the limits
of the ore body at the edge of the pit. The purpose is to permit the mining
of boundary ore and prevent the sides from sliding into the pit. Thus, as
the depth increases, the pit must also be widened. If the stripping ratio
becomes too high (about 2.5) and haulage distance increases too much as the
pit is expanded, open-pit recovery will become uneconomical. Any remaining
ore would then be recovered using alternative recovery techniques, such as
underground mining.
A recent study by the Department of Interior (Prien, 1976) envisages a
very large unitized open-pit operation in the Piceance Creek Basin, with a pit
as deep as 610 meters (2,000 feet). Under this condition, both lower grade
oil shales and associated saline materials may be recovered economically. This
operation could eventually be a combination of open-pit mining and underground
mining. The pit would subsequently be filled and revegetated, and the entire
disturbed area restored (Prien, 1976). To date, however, open-pit mining of
oil shale deposits has not been undertaken in the United States.
IN SITU MINING
In the in situ operation, both mining and retorting of oil shale are pro-
cessed underground. There are two techniques, namely, "modified" and "true"
in situ processes.
Modified In Situ Method
In this method, mining of sufficient shale deposits (approximately 15 to
20 percent) takes place at the upper and/or lower layer of the shale. This pro-
vides the desired porosity when the shale is fractured by explosives and col-
lapsed into a room and is done by drilling vertical longholes from the mine-
out room into the shale layer. An explosive agent is implanted in the holes
for blasting. Blasting on vertical free faces can also be included in the
retort development process. Finally, retorting is operated in a vertical gas
combustion mode. This process is shown in Figure 2-7..
Occidental Research and Development is currently developing a commercial -
size modified in situ process in Colorado. The first commercial-size retort
(Retort No. 4) with a 36.6- x 36.6-meter (120- x 120-foot) cross section and
76-meter (250-foot) height, containing rubblized shale, was ignited in December
1975 (TRW and Denver Research Institute, 1976). A total of 4,300 m (27,000
37
-------
AIR AND RECYCLE GAS
GAS
- HFTf»PTIMR AND VAPORIZATION ZONE ~- —
PILLAR
7
PILLAR
Figure 2-7. Flame-front movement in the Occidental modified in situ process
(McCarthy and Cha, 1975).
38
-------
bbl)of oil has been recovered and production rates of 80 m3 (500 bbl) per day
have been realized. Production from a similar sized retort (Retort No. 5)
has also been completed by Occidental.
True In Situ Methods
The usual approach to this method is to drill a pattern of wells into
the shale deposit, consisting of a central injection well surrounded by a
series of production wells. The shale between the wells may be fractured by
using hydraulic pressure, chemical explosives, or steam. Use of nuclear
explosives has also been discussed, but has been dismissed as not being a
realistic alternative. The fractured oil shale is then ignited by injecting
heated compressed air or hot natural gas into the injection well. Product
recovery from the underground combustion and pyrolysis is through the sur-
rounding production wells (Figure 2-8).
Compressed air
injection well
Oil ond 0,0$ i
producing nil -i
3'° ft* ?£^o *' '0 fl'KSli o'j£'. -* • * W&'Atf&i
!QttfW%tto'WA$sffi, ' ,< &&&$£$,
1 t^y. g oVs a • «jq&g P ^tfe v>gfir. ' » ' ^c^^Oo^^aJL
H*-
•Burned shole-
mfissMss®
TTX
Combustion
jcne
_i Retorltd! Re.or.m, I RflB shfl|e I
I shole I /one j |
Figure 2-8. Horizontal in situ oil shale retorting process
(Duvall and Jensen, 1975).
39
-------
A critical point for this process is that the fracturing techniques must
produce sufficient heat-transfer surfaces for successful operation. A research
project is in progress, sponsored by the U.S. Department of Energy, to test this
method near Rock Springs, Wyoming. In field experiments, several methods of
fracturing, including hydraulic pressure, chemical explosives, and electricity,
have been used for tests on an oil shale bed of 6- to 12-meter (20- to 40-foot)
thickness, with 15 to 122 meters (50 to 400 feet) of overburden. Horizontal
fractures were produced by using hydraulic pressure over a 10.7-meter (35-foot)
vertical interval at a depth of 122 meters (400 feet). Fractures extending at
least 61 meters (200 feet) from the injection well were reported. Chemical ex-
plosives and the combination of hydraulic pressure with liquid chemical explo-
sives have also been used. Explosives in liquid form may be introduced into
natural or artificial fractures while those in solid form are put in well
bores. Tests were able to produce small quantities of oil. Larger underground
recovery tests are planned (U.S. ERDA, 1976).
The U.S. Energy Research and Development Administration (ERDA) has also
undertaken extensive experimentation involving laboratory studies, pilot
scale simulations of underground operations and field experiments. Eight ex-
periments utilizing various fracturing and recovery methods were conducted at
a depth of 25 meters (82 feet). Additionally, two fracturing experiments were
performed at a depth of 120 meters (394 feet) (Dinneen, 1976). Experiments
with such fracturing techniques as electricity, chemical explosives and hydrau-
lics have been conducted (Burwell et al., 1970; Campbell et al., 1970; Carpen-
ter et al., 1972; Melton and Cross, 1967; Miller and Howell, 1967; Wise et al.,
1976). These trials have demonstrated that underground combustion can be ini-
tiated after site preparation, and oil can be produced from in situ processing
(Carpenter et al., 1977).
Fracturing Methods Using Chemical Explosives-
Chemicals, such as ANFO and nitroglycerine, have been used as fracturing
agents. Explosive fracturing following hydraulic fracturing improves perme-
ability while also creating additional fractures. Fracturing shale by chemi-
cal explosives has been limited to depths of 10 to 100 meters (about 30 to 300
feet). However, for a vertical, downward-moving combustion zone processing,
the rubblized zone must be overlain by a relatively unbroken, impermeable zone
in order to control the gas flow. Chemical explosives may not be suitable for
this kind of breakage because of damage to overburden integrity and subsequent
difficulty of controlling the burn.
Hydraulic and Steam Fracturing-
Hydraulic injection can be utilized to leach out the soluble minerals from
oil shale formations. Hot water (66° to 149°C [150° to 300°F]) produces a
higher leaching rate than cold water. As leaching progresses, the oil shale
formation becomes more permeable and may also begin to rubble. Steam at 329°C
(625°F) and 102 atm (1,500 psi) or hot gases may be injected for pyrolysis and
shale oil recovery. At a temperature of about 315°C (600°F), the organic
material in oil shale, kerogen, is converted to oil (U.S. House of Representa-
tives Hearings, 1974). Equity Oil Company began an in situ program near Rio
Blanco, Colorado, in 1965. Hot methane gas was injected into a naturally
40
-------
fractured oil shale zone, and a low pour point oil was produced. Modifications
of the procedures have since been made to utilize steam as the heat carrier in
place of methane (Hendrickson, 1975).
Nuclear Explosive Fracturing-
Detonation of nuclear explosives has been proposed for oil shale recovery.
A cavity that is approximately spherical would be formed underground by the
explosion. Roof collapse would lead to formation of a vertical rubble pile or
chimney. The chimney would be surrounded by relatively unbroken rocks of low
permeability. Hot gas would then be injected into the rubble zone for combus-
tion and retorting processes (Lewis, 1974).
Although the use of nuclear devices has been proposed for numerous peace-
ful and constructive programs, at least two major obstacles will prevent their
use for some time. The method has not undergone field demonstration which would
entail exhaustive studies on its feasibility and environmental impacts. Also,
the public sector still largely opposes the introduction of nuclear detonations
into public and private enterprises. These problems suggest that nuclear
detonations will not be used in mining operations for many years.
OIL SHALE PREPARATION
Oil shale consists of solid organic materials intimately associated with
large amounts of solid minerals. The size requirement of the crushed shale
depends on the retorting process adopted. Since more retorting processes
require shale rock to be from 5.1 centimeters (2 inches) or 7.6 centimeters
(3 inches) to no smaller than 0.32 centimeters (0.125 inches), mined shale
needs to be crushed and sized before retorting. Mined shales from trucks or
conveyors are introduced into a feed surge control hopper. The ore is then
conveyed to "grizzlies" above the primary crushers. Grizzlies are designed to
screen out ore that will clog the entry to the primary crusher. The primary
crusher reduces the ore to a size that will fit the entry to the secondary
crusher. The primary crushed output is screened, and the oversize portion is
returned to the primary crusher feed. The primary crusher product is trans-
ported to a raw shale stockpile. Materials from this stockpile are then
transported to the secondary crusher feed bins. Grizzlies are not required on
the secondary crushers, since the materials are already sized to fit. After
crushing and screening, the secondary crusher output is ready as retort feed.
The surface storage capacity required for reliable feed for retorting is con-
sidered to be a minimum of a 30-day supply.
Alternative crushing systems that may be employed include jaw crushers,
gyratory crushers, roller crushers, and impact mills. However, it has not yet
been determined which units are most efficient.
Transfer of the shales between different parts of the mining area can be
achieved by a number of methods. The most efficient means appears to be truck
or belt haulage from the mine, with subsequent transfer by continuously moving
belts.
41
-------
SECTION 2 REFERENCES
Burwell, E.L., I.E. Sterner, and H.C. Carpenter, "Shale Oil Recovery by In
Situ Retorting-A Pilot Study." Petroleum Technology, Vol 22, pp 1520-
1524, 1970.
Campbell, G.6., W.6. Scott, and J.S. Miller, Evaluation of Oil Shale Fractur-
ing Tests near Rock Springs. Wyoming, Bureau of Mines RI 7397, p 21, 1970.
Carpenter, H.C., E.L. Burwell, and H.W. Sohns, "Engineering Aspects of Process-
ing Oil Shale by In Situ Retorting," presented at 71st National Meeting
of American Institute of Chemical Engineers. Dallas, Texas, February 1972.
Carpenter, H.C., H.B. Jensen, and A.W. Decora, "Potential Shale Oil Production
Processes," presented at Symposium on Oil Sand and Oil Shale, American
Chemical Society, Division of Fuel Chemistry, Vol 22, No. 3, Montreal,
Canada, pp 48-65, 1977.
Dinneen, G.U., "Retorting Technology of Oil Shale," Oil Shale (T.F. Yen and
G.V. Chilingarian, eds), pp 181-197, 1976.
Duvall, J.J., and H.B. Jensen, "Simulated In-Situ Retorting of Oil Shale in a
Controlled-State Retort," Proceedings of the 8th Oil Shale Symposium,
Quarterly of the Colorado School of Mines, Vol 70, No. 4, p 187, 1975.
East, J.H., Jr., and E.D. Gardner, Oil Shale Mining, Rifle. Colorado, 1944-56,
U.S. Bureau of iines Bulletin 611, 163 pp, 1964.
Hendrickson, T.A. (ed), Synthetic Fuels Data Handbook, Cameron Engineers, Inc.,
1975.
Hoskins, W.N., F.D. Wright, R.L. Tobie, J.B. Bills, R.P. Upadhyay, and C.B.
Sandberg, "A Technical and Economic Study of Candidate Underground
Mining Systems for Deep, Thick Oil Shale Deposits," Proceedings of the
9th Oil Shale Symposium, Quarterly of the Colorado School of Mines, Vol
71, No. 4, p 199, 1976.
Lewis, A.E., "Nuclear In-Situ Recovery of Oil from Shale," Oil Shale Tech-
nology, U.S.' House of Representatives 93d Congress, Hearings Before the
Subcommittee on Energy of the Committee on Science and Astronautics,
Second Session on H.R. 9693, No. 48, 1974.
McCarthy, H.E., and C.Y. Cha, "Development of the Modified In-Situ Oil Shale
Process," presented at 68th American Institute of Chemical Engineers
Meetings, Los Angeles, California, 1975.
Melton, N.M., and T.S. Cross, "Fracturing Oil Shale with Electricity,"
Colorado School of Mines Quarterly. Vol 62, pp 63-74, 1967.
Miller, J.S., and W.D. Howell, "Explosive Fracturing Tested in Oil Shale,"
Colorado School of Mines Quarterly. Vol 62, pp 63-74, 1967.
42
-------
National Petroleum Council, U.S. Energy Outlook-An Interim Report. 1972.
Prien, C.H., Current Oil Shale Technology. Denver Research Institute, Univer-
sity of Denver, 1974.
Prien, C.H., "Survey of Oil-Shale Research in the Last Three Decades," Oil
Shale (T.F. Yen and 6.V. Chilingarian, eds), Elsevier, p 235, 1976.
Rio Blanco Oil Shale Project, Gulf Oil Corporation and Standard Oil Company,
Detailed Development Plan. Federal Lease Tract C-a. Vol 2, Section 4.3,
1976.
Shrarnn, L.W., Oil Shale, U.S. Bureau of Mines Bulletin 650, p 183, 1970.
Steele, R.V., "Oil Shale Mining and Spent Shale Disposal," Synthetic Liquid
Fuels Development: Assessment of Critical Factors, U.S. Energy Research
and Development Administration, ERDA 76-129/2, Vol II, p 455, 1976.
TRW Environmental Engineering Division and Denver Research Institute, A Pre-
liminary Assessment of Environmental Impacts from Oil Shale Development.
Section 2.3, 1976.
U.S. Energy Research and Development Administration, Synthetic Liquid Fuels
Development; Assessment of Critical Factors. ERDA 76-129/2, Vol II,
1976a.
U.S. Energy Research and Development Administration, BalancedProgram PIan:
Analysis for Biomedical and Environment Research, Vol 5, pi, 1976b.
U.S. House of Representatives 93d Congress, Oil Shale Technology, Hearings
Before the Subcommittee on Energy of the Committee on Science and
Astronautics, Second Session on H.R. 9693, No. 48, p 404, 1974.
Wise, R.L., B.C. Sudduth, J.M. Winter, L.P. Jackson, and A. Long, "Preliminary
Evaluation of Rock Springs Site 9 In Situ Oil Shale Retorting Experiment,"
presented at 51st Annual Fall Meeting, SPE-AIME, New Orleans, Louisiana,
October 1976.
White River Shale Project, White River Shale Project Detailed Development
Plan, Federal Lease Tracts U-a and U-b, Vol 2, Section 7.5, 1976.
43
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SECTION 3
KEROGEN RECOVERY PROCESSES
TYPES OF RETORTING
Commercial recovery of oil from oil shale is based on thermal decomposi-
tion of its solid organic materials. The major portion of the organic
material in oil shale is the insoluble kerogen. The term retorting, as
applied to oil shale, signifies the process of adding heat to decompose the
shale into kerogen products and by-products. The two basic categories of oil
shale retorting are in situ and aboveground processes.
In the in situ process, thermal decomposition takes place underground.
Extensive experimental work on this type of recovery process has been conducted
by the Laramie Energy Research Center (LERC) (Burwell et al., 1969 and 1970;
Carpenter et al., 1972) and by the Occidental Petroleum Corporation (Garrett,
1972; McCarthy and Cha, 1976). The LERC in situ program addresses recovery
from fractured oil shale retorted between injection and recovery wells. This
combustion-type, true in situ retort is of the forward burning type where gas
plus oil move in the same direction. The Occidental modified in situ retorting
involves underground mining of a portion of the oil shale deposit and explo-
sively fracturing shale into this cavity to create a rubblized chimney of oil
shale for retorting. Lawrence Livermore Laboratory is also working on a modi-
fied in situ process (Braun and Rothman, 1975; Industrial Research, 1975). This
concept, Rubble In Situ Extraction (RISE) has not been field tested.
In the abovegrcund retorting processes, retorting is performed in large
vessels (retorts) in which the heat is applied to crushed oil shale. Retort-
ing processes may be categorized according to the mode of heating: directly
heated or indirectly heated.
Until recent years, virtually all efforts to develop oil shale technology
were directed toward aboveground retorting. Hundreds of U.S. patents have been
issued concerning the retorting of shale (Klosky, 1959; Hendrickson, 1975;
Perrini, 1975). Some of the most developed retorting processes are:
0 Directly Heated Retort
Paraho DH Process (Bartick et al., 1975; White
River Shale Project, 1976)
Union Oil Type "A" Process (Berg, 1951; Irish
and Deer!ing, 1964)
44
-------
N.T.U. Sas Combustion Process (Harak et al.,
1971; Ruark et al., 1956)
Jndirectly Heated Retort
TOSCO II Process (Whltcombe and Vawter, 1976;
Hall and Yardumian, 1968)
Paraho IH Process (Bartick et al., 1975; White
River Shale Project, 1976)
Union Oil Type "B" Process (Berg, 1951; Irish
and Deer!ing, 1964)
Lurgi Process (Rammier, 1968; Dinneen, 1976)
Petrosix Process (Bruni, 1968; Chemical Engi-
neering, 1974)
The major retorting processes considered in this section are Paraho and
TOSCO II.
Directly Heated Retort
A directly heated (DH) retort is one in which the heat of retorting is
supplied by the burning of carbonaceous-processed shale residue and a portion
of the retorted gas and oil. The combustion heats the shale, causing oil and
gas to be released and the products to flow out of the retort (Figure 3-la).
Because combustion air is admitted into the retorting vessel, the product gases
are diluted with nitrogen and, therefore, have relatively low heating values on
the order of 3x1O6 to 3.7xl06 joules per standard m3 (800 to 100 Btu per
standard ft3).
Indirectly Heated Retort
An indirectly heated (IH) retort is one in which the heat of retorting is
supplied by an externally heated carrier (Figure 3-lb). A heat carrier (either
a gas or a solid) circulates continuously through the retort to heat the shale,
the heat being supplied to the carrier by the burning of fuel in an external
heater. As the shale is heated, oil and product gas are released and are
recovered from the retort. The product gases from an indirectly heated retort,
such as the TOSCO type, are composed of undiluted components produced during
oil shale pyrolisis and, therefore, have a higher heating value (on the order
of SOxlO6 joules per standard m3 [800 Btu per standard ft3]) than product
gases from directly heated retorts. In addition, the oil product from an IH
retort tends to have a slightly higher API gravity and a lower pour point than
shale oil from a DH process.
45
-------
W)DIRECTLY HEATED (DH) RETORT
RAW SHALE FEEDSTOCK
RETORT
1
->GAS PRODUCT
•CRUDE SHALE OIL
AIR OR OXYGEN
STEAM
GAS
PROCESSED
SPENT SHALE
(B) INDIRECTLY HEATED (IH) RETORT
TO UPGRADING
RAW SHALE FEEDSTOCK
RETORT
I
PROCESSED
SPENT SHALE
-»GAS PRODUCT
TO UPGRADING
-> CRUDE SHALE OIL
TO ATMOSPHERE
t
HEATER
RECYCLED
HEAT
CARRIER
T t
FUEL AIR
Figure 3-1. Two types of oil shale heating processes (modified from
White River Shale Project, 1976).
46
-------
PARAHO RETORTING PROCESS
Mechanical Description
A general layout of the Paraho DH-type retort located at Anvil Points,
Colorado, is shown In Figure 3-2. The size of this semiworks retort unit is
3.2 meters (10.5 feet) O.D., 2.6 meters (8.5 feet) I.D., and 23 meters (75
feet) high. The term "semiworks" refers to a facility that is larger than a
pilot plant but still smaller than commercial scale. The Paraho IH retort is
essentially the same except for the addition of an external heater for recycle
gas. Besides the retort unit., process equipment includes raw shale crushers,
condensers for oil vapor and product gas, a precipitator, and blowers for air,
recycle gas, and product gas (Figure 3-3).
The air-gas distributors near the middle of the retort consist of two
pipes with small orifices of various sizes for the distribution of air and
recycle gas. Oxygen in the air reacts with residual carbon to produce hot
gases. This gas rises through the retorting zone where the raw shale is heat-
ed in excess of 900°F (482°C), causing thermal decomposition of the kerogen
in the shale. Feedstock is distributed at the top of the retort by a revolv-
ing distributor with four legs that maintain an even feed rate over the
whole cross section. The process gases are collected by two inverted U-shaped
pipes near the top of the retort.
The linear grate mechanism at the bottom of the retort provides for con-
trolled, uniform, and continuous rate of solids descent. Recycle-^gas distri-
bution channels are incorporated into these grates, allowing contact between
gas and solids in the cooling zone of the retort.
Process Description
In the Paraho process, the retorting of crude shale oil from the oil shale
is accomplished in vertical, refractory-lined vessels equipped with shale and
gas distribution systems. Raw shale from the feed bin in a size range of
approximately 1.3 to 7.6 centimeters (0.5 inch to 3 inches) moves downward
through a combined mist formation and cooling zone where the oil shale parti-
cles are preheated to about 70°C (160°F) by gas and oil mist ascending from
the retorting zone. The shale proceeds downward into the retorting zone and
contacts the recycle gas that has been heated by the burning of residual carbon
in the processed shale (DH mode), or heated to about 593°C (1,100°F) in an
external heater (IH mode). In this zone, the raw shale reaches temperatures
high enough to pyrolyze the kerogen into oil vapor and gas.
A carbon residue from the pyrolysis reaction remains in the retorted spent
shale. The retorting temperatures also cause decomposition of mineral carbon-
ates, principally calcite and dolomite. The spent shale moves downward from
the hot zone to the cooling zone where the heat of the retorted shale is trans-
ferred to the rising stream of recycle gas. The cooled shale is then dis-
charged from the retort through a grate mechanism at the bottom of the retort.
The recycle gas is injected at the bottom of the retort and rises through
the retorting shale in the cooling zone in the DH retort. This zone acts as a
47
-------
feed shale
feed hopper
rotating spreader
bottom
distribution
retorted shale
off-gas collectors
distributors
hydrauKcafy operated gate
Figure 3-2. Paraho DH-type retort unit (Jones, 1976).
48
-------
raw shale feedstock
VD
retorted shale
approx.
135 «C
(275-F)
air blower
Figure 3-3. Semiworks retort for Paraho process (modified from Bartick et al., 1975).
-------
simple countercurrent solid-to-gas heat exchanger. Air, diluted with retort
recycle gas, is injected through air-gas distributors located at two levels
near the center of the retort unit. The hot gas ascends through the raw shale
in the retorting zone where the solid oil shale is heated to over 482°C
(900°F) to cause thermal decomposition of the kerogen in the shale. In an IH
retort, the heated gases are injected into the retorting zone.
The retort product gas and the oil mist are passed through an electro-
static precipitator where the shale oil is recovered (Figure 3-3). Recovered
product oil flows to an oil tank, from which it is pumped either directly to
downstream processing or to storage. The product gas, after leaving the
electrostatic precipitator, enters a blower where it is pressurized and is
then diverted to either the recycle gas system or to the net product gas
system.
The spent shale discharged from the retort is conveyed to rotary mois-
turizing drum coolers that cool the spent shale and suppress dust. After
cooling and dust suppression, the spent shale, with a moisture content of 5
to 10 percent by weight, passes on conveyors to the disposal area.
Flow Diagram
Figure 3-4 is a flow diagram of the Paraho process. The water require-
ments shown are based on the full commercial operation scale planned by White
River Shale Project (1976). This diagram includes secondary crushing, spent
shale disposal, and air processing. Approximate overall quantities of raw
materials and products are indicated.
Material Balance
Assuming an average oil shale grade of 125 liters per tonne (30 gallons
per ton) and a recovery efficiency of 85 percent (Fischer assay), the manu-
facture of 13,600 m3 (85,000 bbl) per day of crude shale oil would require a
feed rate of 122,400 tonnes (135,605 tons) per day of oil shale and 79.9
million standard m3 (2,797 million standard ft3) per day of combined air and
recycle gas. The raw water requirement for this operation would be 9.78
million liters (2,570,400 gallons) per day. At this production rate, 96.9
million kilograms (107,355 tons) per dav of spent shale and 31.79 million
standard m3 (1,122 million standard ft3) per day of product gas would be gen-
erated (Table 3-1).
Products/Effluents Characterization
The composition of the crude shale oil produced from the 2.59-meter
(8.5-foot) Paraho DH retort is presented in Table 3-2. The product gas compo-
sition is estimated for the vertical-type DH and IH retorts in Table 3-3.
The comparison of hydrogen-to-carbon ratios among petroleum crude (H/C =
2.4), oil shale syncrudes (H/C = 2.0), and coal syncrudes (H/C = 1.4) is
encouraging. The similarity in hydrogen content of oil shale syncrudes and
petroleum crude indicates that needed refining processes may be closely
related to current petroleum refining technology. Consequently, the fuels
50
-------
61.2 MSCM/D
(2,151 MSCF/D)
18.7 MSCM/D
(646 MSCF/D)
AIR
144,152 TmPD
(158,856 TPD)
MINED RAW
SHALE
SECONDARY
CRUSHING
21,649 TmPD
, (25,868 TPD)
FINE SHALE
RECYCLE GAS
GAS
TREATING
122,502 TmPD
(135,605 TPD)
CRUSHED RAW
SHALE
31.5 MSCM/D
(1,122 MSCF/D)
PRODUCT GAS
GAS
PARAHO
RETORTING
UNIT
87,368 TmPD
(107,355 TPD)
PROCESSED
SHALE
6,758 LPM
f 1.785 GPM1
RAW WATER
PROCESSED
SHALE
DISPOSAL
13,600 M3/D
(85,000 BPD)
CRUDE SHALE OIL
1,264,639 LPD
(554,118 GPP)
RETORT WATER
107,109 TmPD
(118,091 TPD)
SPENT SHALE
TO UPGRADING
TO WASTE WATER
TREATING PLANT
TO DISPOSAL
Figure 3-4. Flow diagram of the Paraho process.
-------
TABLE 3-1. MATERIAL BALANCE OF THE PARAHO RETORTING PROCESS
(BASED ON 13,600 m3 [85,000 bbl) CRUDE SHALE OIL
PER DAY)
Std m3 Std ft3
(mil- (mil-
Material Tonnes Tons m3 bbl lions) lions)
Amount In:
Crushed raw shale feed3 122,502
Recycle gas
Process air
Total In:
64,371
22,381
209,254
135,065
70,967
24,676
230,708
-
61.2 2,161
18.7 646
-
Amount out:
Off-gasb 97,946 107,993
Crude shale o11c 12,674 13,974 13,600 85,000 92.7 3,273
Retort waterd 1,267 1,394
Processed shale6 97,368 107,355
Total out: 209,255 230,716 - -
a Starting from 144,194 tonnes (158,976 tons) of mined oil shale,
15 percent consisting of fine crude shale (size 0.5 In.).
Recycle plus product gas.
c °API 19.3.
Retort water assumed here to be about 10 percent of crude shale oil.
e Process water needed for wetting spent shale is about 9.733 million
liters (2.570 million gallons) per day.
52
-------
TABLE 3-2. COMPOSITION OF CRUDE SHALE OILS (FROM PARAHO AND TOSCO II
PROCESSES), PETROLEUM CRUDE, AND COAL SYNCRUDE
Parameter
Physical Properties
Gravity (°API)
Spec. Gravity ( 60/60° F)
Pour Point (°F)
19
0
85
Paraho
retort0
.3
.938
TOSCO II Petroleum
retort6 crude^
21.2 15-44
0.927
80 0
Coal
syhcrude"
95
Viscosity (Centistokes) 20.15 at 140°F 22
Viscosity (SUS) 47.1 at 210°F 106 at 100°F 31-1025 at 100°F
Total Acid No. (mg KOH/gm)
Oil Properties
Oil (wt%)
Resin (&%)
Asphaltene (wU)
Carbene and Carboid (wt%)
Ultimate Analysis
Carbon (wt%)
Hydrogen (wU)
Oxygen (wt%)
Nitrogen (wt«)
Sulfur (wt£)
Selected Metal
Concentration
Arsenic (ppm)a
Nickel (ppm)6
Iron (ppm)b
Vanadium (ppm)b
96. Od
2.8d
l.Od
0.2d
84.90
11.50
1.40
2.19
0.61
19.6
2.5
71.2
0.37
.
_ ^
_ • _
-
85.1 86.4%
11.6 11.79
0.8 0.169
1.9 1.149
0.9 0.19
0-0.03
0.03-45
0.002-348
261
48i
15i
Hi
82.5
9.3
7.2
0.8
0.3
\
—
aDetermined by atomic absorption.
bDetermined by y-ray fluorescence.
C0ata modified from Bartick et al. (1975); data are for directly heated
Paraho retort.
dData from Wen and Yen (unpublished data).
eData modified from Hall and Yardumian (1968).
fData modified from Dunstan et al. (1938).
9Data from Nelson (1958).
hData from Jones (1966).
1Data from Yen and Schwager (1976).
53
-------
TABLE 3-3. GAS COMPOSITION OF DH AND IH RETORTS
Gas
composition
N2a
Q2b
H2c
CO
C02d
H2S
Ci
C2'S
C3'S
CVS
C5+
H20d
Total :
Vertical type
DHe Vol%
61.0
0.1
4.9
2.9
22.8
0.1
2.1
1.1
0.6
0.3
-
4.1
100.0
Vertical type
IHe Vol%
1.8
-
36.6
7.3
21.2
2.0
20.5
6.5
1.2
0.6
-
2.3
100.0
TOSCO II IHf
Vol%
-
-
22.4
3.6
21.4
4.3
15.2
15.7
7.7
4.3
5.4
-
100.0
aDeterminations made by Dohrmann method. For samples with end points
of 343°C (649°F), nitrogen is determined by the Kjeldahl method.
Determined by pyrolyzing the sample in He and C02 determined by
thermal conductivity.
Determined by oxidizing the sample in an oxygen stream.
Determined by thermal conductivity.
eData from Bartick et al. (1975).
fData from Hall and Yardumian (1968).
54
-------
produced are likely to be much like those in use today, minimizing impacts on
combustion system design.
The results of the true boiling point data for various distillation frac-
tions are presented in Table 3-4. Levels of the various heterocyclic atoms
(nitrogen, sulfur, and oxygen) in various distillation fractions are also pro-
vided, along with analyses of the organic properties and levels of selected
metals.
RETORTING PROCESS-TOSCO II
The Oil Shale Corporation (TOSCO) developed this IH retorting process in
1957, building a 22 tonne (24 ton) per day pilot plant in Denver. In 1964,
the "Oil Shale Venture" was formed by TOSCO, SOHIO, and Cleveland Cliffs Iron
Company for the purpose of demonstrating the process on a semiworks scale.
Field operations reached a capacity of 910 tonnes (1,000 tons) per day using
a 17-story semiworks plant built at Parachute Creek, Colorado. The semiworks
plant was shut down in 1972.
Mechanical Description
The TOSCO II retorting process (Whitcombe and Vawter, 1976; Hall and
Yardumian, 1968) features the use of heated ceramic balls as a heat-
transferring medium. The retorting vessel is arrotating drum in which raw
oil shale is heated by contact with the heated ceramic balls (Figure 3-5).
Process Description
In the TOSCO II process, crushed oil shale is heated to approximately
482°C (900°F) by direct contact with heated ceramic balls (Rammier, 1968).
Raw oil shale is crushed to a size of 1.27 centimeter (cm) (0.5 inch) or
smaller and is first preheated by ball-heater flue gas before it is deliverd
into the pyrolysis drum. The 1.27-cm (0.5-inch) diameter ceramic balls are
heated to about 593°C (1,100°F) and then fed to the rotating retort drum
where the thermal decomposition reaction takes place (Figure 3-5). The rota-
tion of the pyrolysis drum mixes the crushed shale and ceramic balls, pro-
viding a high rate of heat transfer and pyrolysis.
The pyrolysis,drum discharges directly into the accumulator where retort-
ed shale and balls are separated on a cylindrical trommel screen. Spent shale
passes through the screen openings and into a surge hopper. The ceramic balls
pass from the accumulator to a ball elevator for transfer to the ball heater
where they are reheated by direct contact with flue gas. The ceramic balls
are then recycled through the retort. •
The processed (spent) shale discharged from the pyrolysis drum at 482°C
(900°F) is cooled by being the heat source for a rotating high-pressure steam
generator. It then is discharged to another rotating vessel in which it is
further cooled by direct quenching with water. The water flow is controlled
to obtain about 12 percent (by weight) moisture in the spent shale discharged
from the vessel (Whitcombe and Vawter, 1976). The moisture is added to con-
trol dust emission and to make the spent shale suitable for compacting in the
disposal area.
55
-------
TABLE 3-4. COMPOSITION ANALYSES OF DISTILLATION FRACTIONS FROM PARAHO CRUDE SHALE OIL*
en
en
Characteristic
Physical properties
Gravity ("API)
Specific gravity
Pour point (°F)
Smoke point (°F)
wt'' of cut on
crude shale oil
Ultimate analysis
Sulfur (wt».)
Nitrogen (wt")
Oxygen (wU)
Carbon (wt )
Hydrogen (wt )
C/H
Oil properties'*
Paraffins
Olefins
Naphthenes
Aroma tics
Selected metal concentrations
Nickel (ppm)
Vanadium (ppm)
Iron (ppm)
Arsenic (ppm)
Gas IBP- 165
— 85.0
— 0.65
— —
— —
0.13 0.32
— 0.93
— 0.138
— 3.19
— 84.36
— 13.42
— 6.29
— —
— —
— —
— —
— —
— _
— —
— 0.0
165-380
39.5
0.8275
—
—
0.70
1.15
1.33
0.52
83.84 -
12.63
6.64
—
—
—
—
1.86
0.01
7.0
0.0
380-480
34.2
0.8540
-35
11.5
4.95
0.75
1.34
0.66
84.16
12.54
6.71
36.7
3.1
33.3
26.9
0.51
0.02
10.7
0.0
480-520
30.3
0.8745
-10
—
3.10
0.84
1.47
0.72
83.29
12.31
6.77
32.1
4.6
28.6
34.7
0.49
0.02
32.2
0.0
520-600
28.6
0.8838
+15
—
9.47
0.67
1.76
0.98
83.98
12.26
6.85
30.6
—
18.9
50.5
0.19
0.02
4.68
0.0
600-650
23.7
0.9117
+45
—
6.46
0.69
1.74
0.48
84.05
11.39
7.05
34.3
—
9.3
56.4
0.17
0.02
3.8
Q.O
650-700
22.0
0.9218
+60
—
6.08
0.68
1.82
0.77
84.92
11.78
7.21
19.8
2.0
15.7
64.5
0.23
0.02
5.9
0.0
700-750
20.2
0.9328
-+80
—
6.13
0.63
2.33
0.32
84.39
11.44
7.38
28.9
2.0
8.2
62.9
0.27
0.02
8.8
0.0
750-800
19.7
0.9358
+100
—
7.55
. 0.55
2.07
0.67
85.05
11.34
7.50
11.3
2.0
21.9
66.8
0.38
0.02
6.3
0.0
800-843
17.7
0.9484
+100
—
15.57
0.53
1.99
1.96
85.72
11.65
7.36
—
—
—
—
0.71
0.02
10.8
0.0
843
12.0
0.9861
—
—
39.54
0.52
2.60
0.82
—
—
—
—
—
—
~**_
1.57
0.11
36.2
17.2
aOata modified from Bartick et al. (1975).
b01efin content determined by fluorescence indicator absorbence (FIA); paraffin, naphthene, and aromatics determined by mass spectrometry.
-------
RAW SHALE
en
SURGE HOPPER f
W
GAS TO ATMOSPHERE
RAM SHALE
FEEDER
PYROLYSIS Y SPENT
ACCUMULATOR |l SHALE
SHALE
PREHEAT
SYSTEM
HOT FLUE GAS
SPENT SHALE
COOLER 6 STEAM
GENERATOR DRUM I
ELUTRIATOR
SCRUBBER
GAS TO ATMOSPHERE
MOISTURIZER
SCRUBBER
TO SPENT SHALE
DISPOSAL
SPENT SHALE.
MOISTURIZER DRUM
SPENT SHALE DISPOSAL CONVEYORS
Figure 3-5. Pyrolysis unit, TOSCO II process (modified from Whitcombe and Vawter, 1976),
-------
Vaporized product shale oil and gas at the top of the pyrolysis accumula-
tor flow through a cyclonic separator to remove entrained solids and into a
fractionation system. In the fractionator, the oil vapor is cooled to produce
heavy oil, distillate oils, naphtha* and light gases. Hot vapors are further
cooled to recover additional oil before the gas is compressed and conveyed to
downstream hydrogen sulfide treatment.
Flow Diagram
Figure 3-6 is a general flow diagram showing the TOSCO II process. The
water requirements presented are based on calculations for the White River
Shale Project. In'this diagram, the fuel requirement of the plant is, supplied
by combustion of gas formed in the retorting process after scrubbing the gas
to remove hydrogen sulfide. Sulfur is recovered as the by-product of this
process. Other by-products include ammonia and petroleum gas.
Material Balance
A representative balance for the TOSCO II process for the production of
2,400 m3 (15,000 bbl) per day of crude shale oil is shown in Table 3-5. After
mining and crushing, the shale is fed to the retorting unit, which consists of
two 8,182 tonne (9,000 ton) TOSCO II retorting trains operating parallel to
each other. Sulfur is recovered at a 30-tonne (33-ton) per day rate as the
by-product. |
Products/Effluents Characterization
Composition data on a typical TOSCO II oil is presented in Table 3-2.
Elemental analyses of the feedstock and products are given in Table 3-6. Note
that the primary product, shale oil, contains about 0.83 percent sulfur and
1.82 percent nitrogen (Table 3-2). The high content of nitrogen and sulfur in
crude shale oil necessitates special HDNS (Hydrogen Denitrogenation, Desul-
furization) processing. Table 3-7 shows a typical analysis of C8 and lighter
components produced in the TOSCO II retort. Because air is excluded from the
TOSCO II retort, the gas is substantially free of nitrogen and contains the
amount of carbon Oxides produced by pyrolysis as well as hydrogen sulfide and
other sulfur compounds.
A chemical analysis of spent shale from the TOSCO II retorting process in
Colorado is listed in Table 3-8. The dissolved salts reported in the leachate
from spent shale are listed in Table 3-9.
SUPPORTING PROCESSES
Processed Shale Cooling
The processed shale from retorting represents 80 to 90 percent of the raw
material fed to the retorts. The treated retort water used to moisten the spent
shale contains inorganic and organic compounds that could be the products of
oil shale retorting or residues in the spent shale. The approximate concentra-
tions of contaminants expected in the water are reported in Table 3-10. There
are three basic approaches for cooling processed shale from the high temperatures
58
-------
01
V
— /
WARM BALL
16,326 TmPD
(18.000 TPDl
BALL
HOT
BALL
>
..s
3RUSHED FINE SHALE
929 LPM
(246 GPM)
HEATER
f
TOSCO II
RETORTING
UNIT
PROCESSED
SHALE
V
RAW WATER
. \
\
,
^
PLANT FUEL
GAS TREATING
0.4 MSCM/D t
(14 MSCF/D") 1
1GAS
2,400 M3/D
(15,000 BPDJ
CRUDE SHALE OIL
220,
(58,
944 LPD
374 GPD)
nT»Tv\«n* MA Tien
WARM
BALL
r
TO BALL HEATER
r
PROCESSED
SHALE
DISPOSAL
14,726 TmPD
(16,236 TPD) w _
^ *«
SPENT SHALE
TO UPGRADING
TO WASTE WATER TREATING
TO DISPOSAL
Figure 3-6. Flow diagram for the TOSCO II process.
-------
TABLE 3-5. MATERIAL BALANCE OF THE TOSCO II PROCESS (BASED ON
2,400 m3 [15,000 bbl) CRUDE SHALE OIL PER DAY)
Std m3 Std ft3
(mil- (mil-
Material Tonnes Tons m3 bbl lions) lions)
Amount in:
Crushed raw shale feed 16,326 18,000 -
Total in: 16,326 18,000 ....
Amount out:
Off-gasa 440 485 - - 0.4 14
. Crude shale oilb 2,210 2,437 2,400 15,000
Retort water0 221 244 -
Processed shaled 13,387 14,760 -
Total out: 16,258 17,926 - ...
aBased on retort gas production of 923 std ft3 per barrel of oil
(Hendrickson, 1975).
b°API 212.
Retort water assumed here to be about 10 percent of crude shale oil.
Spent shale approximately 80 percent of raw shale feed.
TABLE 3-6. ELEMENTAL ANALYSES OF RAW SHALE AND
RETORT PRODUCTS OF TOSCO II PROCESS3
Raw shale feedstock*5
Retort product
Spent shale
Crude shale oil
Gas
Water
Organic
carbon (wt%)
16.53
4.94
84.68
48.87
nil
Sulfur
(wtX)
0.75
0.62
0.83
4.37
0.43
Nitrogen
(wt%)
0.46
0.28
1.82
nil
1.30
Hydrogen
(wt%)
2.15
0.27
11.27
9.86
11.30
aData from Atwood (1973).
33 gallons per ton of raw shale.
60
-------
TABLE 3-7. LIGHTER COMPONENT PRODUCTS FROM THE TOSCO II
SEMIWORKS PLANT PROCESS
Component product
H2
CO
Ci
C2
C2-
C3
C3-
Sub total
Id,
nCi»
c*-
C5~
C6
C7
C8
Fischer assay oil
Subtotal
Total
C02
H2S
Grand total
Yield per 100 pounds
Fischer assay oil (pounds)
0.41
0.91
2.22
2.84
1.37
1.62
1.41
10.78
0.13
0.68
1.38
1.67
1.17
0.76
0.36
99.59
105.74
116.52
8.58
1.34
126.44
aData modified from Hall and Yardumian (1968).
61
-------
TABLE 3-8. CHEMICAL ANALYSIS OF SPENT SHALE FROM TOSCO II
PROCESS AND FISCHER ASSAYS
Constituent
Total carbon
SO 3
S102
A1203
Fe?03
CaO
MgO
Na20
KzO
Others
Total
TOSCO IIa
wt (%)
9.82C
2.63
33.07
9.14
3.24
17.56
7.74
0.77
1.39
14.64
100.00
Fischer assays"
wt («)
8.16d
2.02
40.22
11.20
4.24
20.31
8.54
3.11
2.20
^
100.00
aData modified from Nevens et al. (1961).
Average values from oil shale grade 17.8 gallons/ton to
51.8 gallons/ton.
clnorganic carbon 4.41 percent; organic carbon 5.41 percent.
Inorganic carbon 5.43 percent; organic carbon 2.73 percent.
62
-------
TABLE 3-9. SOLUBLE SALTS IN SPENT SHALE LEACHATE OF TOSCO II PROCESS3
CO
Incremental
volume of
leachate sample
(ml)
254
340
316
150
260
125
155
250
650
650
650
760
Cumulative
total volume
leachate
(ml)
254
594
910
1,060
1 ,320
1,445
1,600
1,850
2,500
3,150
3,800
4,560
Conductance
(mmhos/cm
at 25°C)
78,100
61 ,600
43,800
25,100
13,550
9,200
7,350
6,825
5,700
4,800
4,250
3,850
Concentration (mg/1)
Na+ Ca++ Mg"*"+
35,200
26,700
14,900
6,900
2,530
1,210
735
502
-
-
-
—
3,150
2,145
1,560
900
560
569
585
609
—
-
-
—
4,720
3,725
2,650
1,450
500
579
468
536
—
-
-
—
of sample
SO, *
90,000
70,000
42,500
21,500
8,200
5,900
4,520
4,450
-
-
-
—
cr
3,080
1,900
913
370
250
138
138
80
—
—
—
—
aData from Hendrickson (1975).
-------
TABLE 3-10. COMPOSITION OF WASTEWATER USED IN SPENT
SHALE MOISTURIZING9»b
^•^•••^^^^••^^•^..^^^••••^••"'•^'••"•••^••^••••••••••••••••^^^^^•^•^^•WBIVV^^^
Constituent
Amines
Organic acids
Carbonates
Sul fates
Chlorides
Chroma tes
Thiosul fates
Phenol
Cyani des
Ammonia
Hydroxides
Phosphates
Chela tes
Arsenic
Concentration
(ppm)
1900
1000
520
510
330
130
60
60
50
30
30
15
3
0.03
aData from Colony Development Operation (1974).
Processed water after ammonia stripping and
other pretreatment or primary treatment.
64
-------
at the retort outlet sufficiently to allow safe and reliable transport and
disposal. These are discussed below.
Spraying with Water on Conveyors-
In this system, cooling water is sprayed on the spent shale as it travels
on a conveyor belt leading from the retort unit (Figure 3-7). The entire
system is enclosed and the dust-laden steam is collected and treated using a
wet scrubber system with heat rejection to the atmosphere. Belt-conveyor
slopes are limited to a maximum slope of about 30 degrees, and a more pre-
ferred slope is generally in the 18-to-20-degree range. The belt-conveyor
system requires less equipment than some other types of processed shale cool-
ing systems and subsequently has a lower cost and greater reliability.
However, the system is enclosed and transmits dust-laden steam, which could
make it difficult to cool and wet the processed shale adequately and also to
suppress dust efficiently.
Retort Unit
Spent
Shale
Equipment
Wet Scrubber
Water
Belt Conveyor
Recovery
Pump
Water Recovery
Spent Shale Slurry
to Disposal
Figure 3-7. Spent-shale closed disposal system with water spraying
on conveyor (modified from Hendrickson, 1975).
Air Cooling on Moving Grates-
The moving-grate mechanism at the bottom of the Paraho retort spreads
processed shales from the retorting zone which are cooled by air blown upward
on them. The dust-laden cooling air is contained in a totally enclosed sys-
tem and moved to scrubber equipment. After cooling, the processed shale is
moisturized to suppress dust and passed on conveyors to the disposal area.
65
-------
This system uses mainly air, thus minimizing the water requirement.
However, equipment needs are greater and, consequently, the system costs more
and is less reliable.
Rotary-Drum Cooler-
Rotary-drum coolers have been successfully applied to a wide range of
chemical industries. In this system, processed shale, after leaving the
retorting unit, is conveyed to rotary moisturizing drum coolers where its
temperature is reduced by tumbling and water sprays. The intimate mixing of
water and processed shale could be guaranteed in this system. Dust-laden
steam and moist air produced are passed to scrubbers that condense steam and
remove dust. The advantages of this system are that it ensures that a
reasonable temperature can be achieved for the disposal of processed shale.
In addition, shorter distances are required to ensure cooling of processed
shale in comparison with other cooling systems. Its disadvantages are the
higher cost of equipment, maintenance, and operating expenses.
Raw Shale Feeding and Crushing
Raw shale for retorting processes must be crushed. The size of the
crushed raw shale that can be processed varies from one type of retort to
another. The Paraho process requires shale particles between 1.3 centimeters
(0.5 inch) and 7.6 centimeters (3 inches) in size, while the TOSCO II process
handles crushed shale smaller than approximately 1.3 centimeters (0.5 inch).
Various retorting processes have different needs depending on how the shale
is heated and how it is transported, among other factors.
Among the reasons for limiting the maximum particle size are time require-
ments for particle heating and kerogen diffusion. In retorting, heat must be
conducted to the center of the particle in order to attain maximum efficiency of
conversion from solid organic matter to oil vapor, gas, and residue. Then, the
oil vapor and gas must be diffused from the particles to the surrounding gas
space. Heating and diffusion time increase with particle size.
Figure 3-8 shows a raw shale feed crushing system of the Paraho retorting
process. Raw shale from the mine is charged to the primary crusher feed hopper
and passed through a jaw crusher where oversize pieces are either broken down
to allow passage or discarded. After the first stage of reduction by the jaw
crusher, the shale is carried by a belt conveyor from the primary crusher to
the primary screen. The oversize shale goes to the secondary crusher, and
the undersize shale is conveyed to the fine shale storage pile or discarded.
The particles retained on the (lower) screen are of the desired product size
for the Paraho retort system and are conveyed by the product conveyor to
storage bins. Before retorting, the crushed shales of desired size are passed
down a polishing screen to remove dust and then conveyed to the retort unit.
Raw shales in a size range of approximately 1.3 to 7.6 centimeters (0.5 to 3
inches) are fed to the retort.
66
-------
MINE
ROCK
I SECONDARY
I CRUSHER
PRIMARY
SCREEN
BUCKET
ELEVATOR
LOWER SCREEN
CRUSHED RAW SHALE
/STORAGE
/ BIN
STORAGE
POLISHING
SCREEN
RETORT UNIT
Figure 3-8. Raw shale feed crushing system (modified from
Bartick et al., 1975).
67
-------
SECTION 3 REFERENCES
Atwood, M.T,, "The Production of Shale Oil," Chemtech. p 617, October 1973.
Bartick, H., K. Kunchal, D. Switzer, R. Bowen, and R. Edwards, Final Report-
The Production and Refining of Crude Shale Oil Into Military Fuels,
Office of Naval Research Contract N00014-75-C-0055, Applied Systems Co.,
August 1975.
Berg, C., "Retorting of Oil Shale," Oil Shale and Cannel Coal, Institute of
Petroleum, London, England, Vol 2, p 419, 1951.
Braun, R.L., and A.J. Rothman, "Research and Development on Rubble In Situ
Extraction of Oil Shale (RISE) at Lawrence Livermore Laboratory,"
Colorado School of Mines Quarterly. No. 70, p 159, 1975.
Bruni, C.E., "Demonstration Plant for Retorting Iraqi Oil Shale," presented
at U.N. Oil Shale Symposium, Tallinn, U.S.S.R., 1968.
Burwell, E.L., H.C. Carpenter, and H.W. Sohns, Experimental In Situ Retort-
ing of Oil Shale at Rock Springs, Wyoming, Bureau of Mines TPR 16, 1969.
Burwell, E.L., T.E. Sterner, and H.C. Carpenter, "Shale Oil Recovery by In
Situ Retorting, A Pilot Study," Journal of Petroleum Technology, Vol 22,
p 1520, 1970.
Carpenter, H.C., E.L. Burwell, and H.W. Sohns, "Engineering Aspects of Process-
ing Oil Shale by In Situ Retorting," presented at 71st National Meeting
of American Institute of Chemical Engineers, Dallas, Texas, February 20-
23, 1972.
Chemical Engineering, "Process Technology-Shale Oil—Process Choices,"
May 13, 1974.
Colony Development Operation, An Environmental Analysis for a Shale Oil
Complex at Parachute Creek, Colorado, Part I, 1974.
Dinneen, 6.U., "Retorting Technology of Oil Shale," Oil Shale (T.F. Yen and
6.V. Chilingarian, eds), Elsevier, 1976.
Dunstan, A.E., A.W. Nash, B.T. Brooks, and H. Tizard, The Science of
Petroleum, Oxford University Press, New York, Vol II, Sec 18, p 839,
1938.
Garrett, D.E., In Situ Process for Recovery of Carbonaceous Materials from
Subterranean Deposits. U.S. Patent No. 3.661.423. Mav 9. 1972.
Hall, R.N., and L.H. Yardumian, "The Economics of Commercial Shale Oil
Production by the TOSCO-II Process," presented at 61st Annual Meeting
of American Institute of Chemical Engineers. Los Angeles, California,
1968.
68
-------
Harak, A.E., L. Dockter, and H.C. Carpenter, Some Results from the Operation
of a 150-Ton Oil Shale Retort, U.S. Bureau of Mines TPR 30, 1971.
HendHckson, T.A. (ed), Synthetic Fuels Data Handbook, Cameron Engineers, Inc.,
Denver, Colorado, 1975.
Industrial Research, "In-place Shale Process-More Oil, Less Digging," No. 14,
June 1975.
Irish, G.E., and R.F. Deer!ing, Feed Segregation and Shale Oil Recycle, U.S.
Patent 3,133,010, May 12, 1964.
Jones, J.B., "The Paraho Oil Shale Retort," presented at 81st National Meeting
of American Institute of Chemical Engineers, Kansas City, Missouri,
April 11-14, 1976.
Jones, J.F., Coal Oil Energy Development. Office of Coal Research, Contract
No. 14-9-601-235, Washington, D.C., 1966.
Klosky, S., Index of Oil Shale and Shale Oil Patents: Vol 1946-1956, A Supple-
ment to~Bu"netin 468; Vol. I - U.S. Patents, 1958. 134 PP; Vol II -
United Kingdom Patents, 1958, 75 pp; Vol III - European Patents, 1959, 45
pp, U.S. Bureau of Mines Bulletin 574.
McCarthy, H.E., and C.Y. Cha, "Oxy Modified In Situ Process Development and
Update," Colorado School of Mines Quarterly. Vol 71, p 85, 1976.
Nelson, W.L., Petroleum Refinery Engineering, McGraw-Hill, New York, 1958.
f*f:
Nevens, T.D., W.I. Cubblrtson, Jr., and R.D. Hollingshead, Disposal and Uses
of Oil Shale Ash, Interim Report No. 1, USBM Project No. SWD-8, Univer-
sity of Denver, Denver Research Institute, 1961.
Perrini, E.M., Oil from Shale and Tar Sands, Noyes Data Company, Park Ridge,
New Jersey, 1975.
Rammier, R., "Distillation of Fine Grained Oil Shale by the Lurgi-Ruhrgas
Process," presented at U.N. Oil Shale Symposium, Tallinn, U.S.S.R., 1968.
Ruark, J.R., K.L. Berry, and B. Guthrie, Description of Operation of the
N.T.U. Retort on Colorado Oil Shale, U.S. Bureau of Mines RI 5279, 1956.
Wen, C.S., and T.F. Yen, unpublished data.
Whitcombe, J.A., and R.G. Vawter, "The TOSCO-II Oil Shale Process," Science
and Technology of Oil Shale (T.F. Yen, ed), Ann Arbor Science Publish-
ers, Michigan, 1976.
White River Shale Project, White River Shale Project-Detailed Development
Plan-Federal Lease Tracts Ua and Ub, Vols 1-2, Part 1-7, 1976.
69
-------
Yen, T.F., and I. Schwager, Chemistry and Structure of Coal-Derived Asphaltenes,
U.S. Energy Research and Development Administration, Contract No.
E(49-18)-2031, Washington, D.C., 1976.
70
-------
SECTION 4
HYDROGENATION (UPGRADING) PROCESS
GENERAL PROCESS DESCRIPTION
• » Oil shale retorting yields a viscous, waxy, high-nitrogen, and moderate
level-sulfur liquid product that is undesirable for transportation or storage.
For this reason, development plans usually include an upgrading or hydrotreat-
ing process to treat shale oils before they are shipped to petroleum refiner-
ies. The upgrading involves heating, hydrogenation, and possibly some
cracking of the crude shale oil. The upgrading alternatives can be categor-
ized according to the desired final product (Table 4-1).
Visbreaking, categorized as a mild thermal cracking process, lowers the
molecular weights of the shale oil hydrocarbons only slightly. If the vis-
breaking is accomplished in the presence of hydrogen, the hydrogen helps to
stabilize the reduced pour point of crude shale oil products obtained by com-
bining visbroken and hydrogenated oils. The resulting combination of crude
shale oils is a product with a reduced pour point which is suitable for stor-
age and transportation without becoming too viscous to be handled.
Delayed coking is a semicontinuous thermal cracking process. It pro-
duces a lower molecular weight distillate and a solid residue (coke). The
distillate is a cracked shale oil with lowered pour point and viscosity.
In the heavy-oil cracking process, both lower molecular weight distillate
and a coke residue are produced. The properties of cracked shale oil are
similar to those of the shale oil produced by the delayed coking process
described above.
During hydrotreating, the crude shale oil is treated with hydrogen in
the presence of a catalyst to remove the components of sulfur, nitrogen, and
oxygen from the crude oil. The product resulting from the hydrotreating pro-
cess has a low viscosity and a low pour point, and the concentrations of
sulfur, nitrogen, and oxygen in the bulk of crude shale oil are reduced
greatly. The upgraded shale oil produced from a severe upgrading process,
as shown in Table 4-1. is suitable for pipeline transport and further process-
ing in petroleum refineries.
71
-------
TABLE 4-1. UPGRADING ALTERNATIVES FOR CRUDE SHALE 01Is
Upgradi ng
alternatives
Processing choices
Product quality
PO
I. None
II. Mild
III. Moderate
IV. Severe
'Visbreaking
•*• Delayed coking
•Heavy-oil cracking —*-Hydrostabilization
->• Moderate hydrogenation
Crude shale oil not readily
transported by pipeline
A cracked shale oil more suit-
able for transport by pipeline
Suitable as boiler fuel or
refinery feedstock
Delayed coking
•Hydrogenation
->• Severe hydrogenation
->• Heavy-oil cracking —
•Hydrogenation
-*• High-quality refinery feedstock
similar to sweet crude oil
a From White River Shale Project (1976).
-------
HYDROGENATION
Mechanical Description
Shale oil hydrogenation includes hydrotreating the crude shale oil to
reduce levels of sulfur and nitrogen, and hydrocracking of the naphtha to
reduce product viscosity for piping purposes.
The crude Paraho processed shale oil has been refined by using the Gary
Western facility at Fruita, Colorado (Bartick et al., 1975). The hydrotreat-
ing unit consists of a denitrogenation/desulfurization reactor, a fraction-
ating tower, and a naphtha hydrotreater with separators. Under contract to
the U.S. Navy, the Gary Western facilities have been used to convert Paraho
crude shale oil into military fuels including NATO gasoline, JP-4, JP-5/Jet A,
DFM/DF-2, and heavy fuel oil. The components of a typical hydrogenation
scheme are illustrated in Figure 4-1. Because of reactor size limitations,
multiple reactors might be required.
Two types of hydrotreating units have been proposed for TOSCO II crude
shale oil refining (Whitcombe and Vawter, 1975). One is a distillate hydro-
treater for processing the 400° to 950°F oil component from retorting plus
similar boiling-point range components formed in the coker. The other type
processes C5 to 400°F naphtha formed in the retort, coker, and distillate
hydrotreater. The process is designed by Atlantic Richfield Company, which
conducted pilot plant studies using TOSCO II crude oil.
Process Description
The hydrogenation process (Figure 4-1) includes a crude shale oil hydro-
treater and a naphtha hydrotreater. The crude shale oil hydrotreater unit
consists of a multistage hydrogen denitrogenation, desulfurization reactor
(HDNS) with a separator, a gas stripper, a fractionating tower, and a sta-
bilizer. The naphtha hydrotreater consists of a heater, a denitrogenation
reactor, a separator, and a gas stripper.
In the crude shale oil hydrotreating process, the oil and hydrogen are
premixed and heated. This mixture then enters the HDNS reactor, which contains
catalysts with high selectivity for hydrogenation of nitrogen and sulfur com-
pounds. The output stream from this reactor is mixed with water and enters a
separator. The excess hydrogen is removed and recycled back to the HDNS
reactor. Water, ammonia, and hydrogen sulfide are removed from the separator.
The desired denitrification and desulfurization of the C* and light material
are accomplished in the HDNS unit. The "heavy" hydrocarbon (C5 and up) frac-
tions are then distilled in a fractionating column to yield the desired dis-
tillation fractions. The naphtha fraction produced is stabilized and
separated and then further treated by the naphtha hydrotreater unit for
additional denitrification.
Ammonia and hydrogen sulfide are removed from the crude shale oil hydro-
treating unit by water-washing the recycle gas in the separator. Sour wash
water is sent to the wastewater treating plant. The stripped water, after
the removal of hydrogen sulfide and ammonia, can be recycled to the hydro-
treating units.
73
-------
MAKEUP Ho
RECYCLE Hg
MAKEUP
RECYCLE Hg
C4-TO GAS
RECOVERY FACILITIES
->x >
CA-LT ENDS
^ v
IBP (initial boiling point)
20S°C(400
N >t
STRIPFEf
1,
HgO
ftff->
AITROGENIATION
CTOR
STRIPPER
PRODUCT
NAPHTHA,
204»-3I6*C (400*-600*F)'|k
DIESEL
RECOVERY
COLUMN
WASH
WATER
Figure 4-1. Typical hydrotreater for crude shale oil (modified from White River Shale Project, 1976).
-------
The slip-stream fraction (bottom material of 205°C [400°F] and up which
is separated from the fractionator) is fed to a recovery column to recover
the diesel fuel (204° to 316°C [400° to 600°F] fraction and the resulting
bottom fraction (316°C [600°F] and up). The bottom fraction of 316°C
(600°F) and up is used as fuel oil for process heaters and the utility plant.
The naphtha fraction recovered from each crude shale oil hydrotreating
unit and C5 to 205°C (400°F) fraction recovered from the light ends (gases)
compression facilities are processed in a conventional naphtha hydrotreating
unit (see Figure 4-1) to reduce the nitrogen content from 3,000 ppm to about
1 ppm. The d, and light ends separated from the stripper in the naphtha
hydrotreater unit are combined with the light fraction from the HDNS reactor
and sent to the amine absorber treating unit to remove acid gases (hydrogen
sulfide and carbon dioxide) and some trace heavier material. After amine
treating, the Ci» and light ends fraction can be used for hydrogen plant feed.
Flow Diagram
A flow diagram for a generalized full-scale shale oil upgrading plant
is shown in Figure 4-2. The diagram presents all the supporting processes
including amine treating, hydrogen plant, low-Btu gas treating, sulfur recovery
and tail gas treating, wastewater treating, and sour water stripper. These
supporting processes are discussed in a later subsection. Additional details
on hydrogenation, denitrogenation, and desulfurization may be found in Thomas
(1970), Schuit and Gates (1973), Cottingham and Nickerson (1975), Satterfield
et al. (1975), Silver et al. (1976), and Frost et al. (1976).
Material Balance
An overall material balance for crude shale oil upgrading and product re-
covery is shown in Table 4-2. Each processing component of hydrotreating
inputs and outputs is listed.
Product Characterization
Table 4-3 gives the properties of the output from the crude shale oil
hydrogenation and naphtha hydrotreater. A comparison,between crude shale oil
and upgraded product shows a great decrease in pour point from 30° to 10°C
(85° to 50°F) and a decrease of viscosity from 20 centistokes at 60°C (140°F)
to 4 centistokes at 38°C (100°F). The sulfur content of 0.61 weight percent
in crude shale oil is reduced to 0.025 weight percent after upgrading. Simi-
larly, after denitrogenation, nitrogen content is decreased from an original
2.19 weight percent to 0.034 weight percent.
Table 4-4 presents the overall yields from crude shale oil after complet-
ing the hydrogenation of crude shale oil. The combined yield of products
from hydrogenation is about 76.8 percent by weight of the crude shale oil.
75
-------
HIGH
BTUGAS.
C4-GAS
G^-GAS
CQg
AMINE
64 TO LIGHT
ENDS
en
CRUDE
SHALE OILJ
REGENERATOR
I I PVM AMtff I
RICH AMINE
SULFUR RECOVERY(->TAIL GAS
TAIL GAS
TREATING
HgS
->TO SOUR WATER STRIPPER
HYOROTREATER
204*C
(400*FI
NAPHTHA
HYOROTREAT-
SOUR WATER
DCSEL
RECOVERY.
COLUMN
HYDROGEN
PLANT
H,
HjS/NHg/COg
SULFUR
Hg
WASTE WATER
TREATMENT
SOUR WATER
FROM RETORT
SOUR WAI
FROM GAS
LIQUID AMMONIA
NAPHTHA
SOUR WATER
STRIPPER
SHUPPED WATER
204*-3I«*C (
3I6»C(600'F)
400«-
-ING
-> STRIPPED WATER
STRIPPED WATER.
600*Ft
Z04*C t400*F>
Figure 4-2. Flow diagram for upgrading operation of crude shale oil
(modified from White River Shale Project, 1976).
-------
TABLE 4-2. MATERIAL BALANCE OF UPGRADING PROCESS (BASED ON 1,600 m3
[10,000 bbl] CRUDE SHALE OIL CAPACITY PER DAY)9
Material
Amount in:
Crude shale oil
Gas-to-amine
treating plant
Water-to-hydrogen
plant
Air- to-sulfur plant
Total in:
Amount out:
Off-gas
CO* from hydrogen
plant
Naphtha
Gas oil
Sul fur
Ammonia
Water produced
Sulfur plant tail
gas
Total out:
aData modified from White
bAPI 19.3.
Tonnes
1,491
116
209
33
1,849
16
257
268
1,153
15
37
25
78
1,849
River
Std m3 Std ft3
Tons m3 bbl nons) lions)
1,644 1,600 10,000
128 - - 0.1 3.5
230 - ...
36 - 0.03 0.9
2,038
17 - - 0.01 0.4
283 -
295 364 2,270
1,271 1,367 8,549
17 - ...
41 - ...
28 -
86 - -
2,038 - -
Shale Project (1976).
.
77
-------
TABLE 4-3. INSPECTIONS OF HYDROTREATED PRODUCTS FROM PARAHO CRUDE SHALE OIL*
00
Characteristic/
constituent
Gravity (°API)
Specific Gravity
(16°/16°C; 60°/60°F)
Pour Point
Viscosity (cSt)
Flash Point
Freeze Point
Molecular weight
Nitrogen (wt%)
Sulfur (wt%)
Oxygen (wt%)
Carbon (wt%)
Hydrogen (wt%)
C/H
Olefins (vol%)
Crude oil
19.3
0.938
30°C (85°F)
20 (60°C; 140°F)
—
—
—
2.19
0.61
1.40
84.90
11.50
0.62
—
- - n •• • - •
IBP-204°C
(IBP-400°F)
61.1
0.735
—
—
—
—
—
24 ppm
30 ppm
0.29
85.51
47.70
0.49
0.8
i —ii. .in., 1, ,
Products
204°-316°C
(400°-600°F)
40.8
0.821
—
—
21°C (75°F)
-18°C(1°F)
208
0.288
0.006
0.23
86.40
13.69
0.53
1.0
• !• • ». •. _^ __ _ ,, _ ____ __ _ m ^^ ,„,„. .--|| —
3160-371°C Upgraded
(600°-700°F) shale oil
31.6 40
0.868
10°C (50°F)
4 (38°C; 100°F)
— —
— —
— —
0.63 0.034
0.01 0.025
0.18
86.19
12.54
0.57
— —
a Data modified from White River Shale Project (1976) and Bartick et al. (1975),
-------
TABLE 4-4. OVERALL YIELD OF HYDROGENATION PRODUCTS
FROM PARAHO CRUDE SHALE OIL*
Outputs wt%
Gas10.1
IBP-204°C (IBP-400°F) Product 10.4
204°-316°C (400°-600°F) Product 24.3
316°-371°C (600°-700°F) Product 23.6
371°-454°C (700°-850°F) Untreated 18.5
Coke 12.0
NH3 0.9
H2S 0.4
H20 0.9
TOTAL 101.1
aData modified from Bartick et al. (1975).
Coke yield is approximately 12 percent by weight.of crude shale oil, and
total gas generated is about 10.1 percent by weight. Total net hydrogen input
utilized amounts to 1.3 weight percent of the crude shale oil. This is equi-
valent to approximately 790 standard ft3 of hydrogen used per barrel of shale
oil; since 100 percent efficiency cannot be attained, gross process input of
hydrogen is on the order of 2,000 standard ft3 per barrel of oil.
Catalysts and Additives
Hydrogenation catalysts may be classified as follows:
• Free metals (e.g., platinum, palladium, and nickel) or supported
metals (e.g., cobalt-molybdenum on aluminum oxide [Nalcoma 471].
nickel-tungsten on aluminum oxide [Harshal Ni-430]), which are
useful for low temperature operation with clean, nonpoison-
containing feedstocks. The principal application is for olefin
and aromatic saturation. Since these compounds do not contain
nitrogen, oxygen, or sulfur additions, they do not poison the
catalyst.
• Metal oxides and sulfides or a combination of the two, supported
on nonacidic materials such as alumina, magnesia, or kieselguhr.
These types of catalysts are used largely for saturative hydro-
genations in the presence of potential poisons.
• Metal oxides and sulfides, or combinations of the two, supported
on acidic materials such as silica-alumina, silica-magnesia,
79
-------
activated clay, or acidified alumina. This class is used
largely in hydrocracking.
A series of catalysts has been studied for single-stage hydrorefining of
the coke distillate from a shale oil (Benson and Berg, 1966). Twelve different
catalysts were investigated as potential denitrogenation catalysts (Table 4-5).
At pressures up to 70 atmospheres, a hydrofluoric acid-treated cobalt oxide-
molybdenum oxide-alumina was found as best in the 12 studies. The tabulation
of the efficiency values is given in Table 4-6. Nitrogen conversion with the
HF-activated cobalt molybdate catalyst was 89.5 percent of total denitrogena-
tion, whereas for the best catalyst, the Peter Spence cobalt molybdate cata-
lyst, the conversion was 71.1 percent.
One other study has favored hydrorefining the shale oil-coke distillate
in a two-stage treatment (Montgomery, 1968). In the first stage, conditions
were mild in order to saturate the olefins, give a reduction in oxygen com-
pounds, and allow removal of some sulfur. Conditions in the first stage were
245°C (473°F), 35 atmospheres, space velocity of 0.89 volume of oil per
volume of catalyst per hour, with hydrogen circulation of about 2.3 moles per
mole of distillate. The catalyst was presulfided (reacted with hydrogen
sulfide prior to use) commercial cobalt oxide-molybdenum oxide-alumina, and
hydrogen consumption was 0.8 moles per mole of feed. Conditions in the second
stage were 435°C (815°F), 100 atmospheres, space velocity of one volume of oil
per volume of catalyst per hour, with hydrogen circulation of about 11 moles
per mole of feed. The catalyst was presulfided commercial nickel tungsten
alumina, and hydrogen consumption was about 3.3 moles per mole of feed. Table
4-7 summarizes the results of this hydrogenation procedure. With a total
hydrogen consumption of 4.1 moles per mole of coke distillate, some aromatic
rings, as well as the olefins, were saturated.
Recently, in situ crude shale oil, produced by the underground combustion
retorting method, has been hydrocracked over a nickel-molybdena catalyst at
427°C (800°F) and 103 atmospheres (Cottingham and Nickerson, 1975). The yield
of diesel fuels was 51.6 percent (by volume) of the in situ crude shale oil,
and the yield of No. 4 fuel oil was 21.5 percent (by volume). In conclusion,
a total of 73.1 percent (by volume) of the in situ crude shale oil could be
hydrocracked into low-sulfur, high-cetane-index diesel fuels or No. 1 through
No. 4 burner fuels.
The denitrification of shale oil gas has also been studied in the compari-
son of cobalt-molybdenum and nickel-tungsten catalysts (Silver et al., 1976;
Frost et al., 1976). The metallic components of the catalysts did show differ-
ences in effecting the denitrification reaction. Cobalt-molybdenum had the
greatest effect, presulfided nickel-tungsten the next, and nonpresulfided
nickel-tungsten the smallest. This demonstrates that presulfiding did increase
the activity of the nickel-tungsten metallic components.
The spent catalysts contain metal oxides or sulfides, as well as the
carbonaceous deposits. In all the cracking catalyst regenerations, the cata-
lyst is first purged with steam or inert gas. Regeneration is carried out in
air diluted with steam or inert gas, so the oxygen content is 0.5 to 1 per-
cent and preferably at 2 to 10 atmospheres pressure. Burning begins at
80
-------
TABLE 4-5. COMPOSITION OF CATALYST USED FOR HYDROTREATIN6 OF SHALE OIL3
Catalyst
Composition
Identification code
Catalyst source
Cobalt molybdate I
Cobalt molybdate II
Cobalt molybdate III
Cobalt molybdate IV
00 Cobalt molybdate V
Molybdenum oxide I
Molybdenum oxide II
Ororrite hydroforming catalyst
HF-activated cobalt molybdate
Platinum (type 1000)
Mn03 deposited on DA-T
cracking catalyst
Molybdenum sulfide
9.5% Mo03, 3.0% CoO Co-Mo-0201-T-l/16 in.
5.0% Si02, 2.0% graphite
80.5% A1203
Same as above Co-Mo-0201-T-l/8 in.
CoMoO.»-Al203
Large pore
2.5% CoO
14.0% Mo03
Graphite base
16% Mo03
79% A1203
5% Si03
Same as above
86% DA-1
13.5% Mn03
#2127-2
Graphite-type pellets,
5/32 in. diameter
3/16 in. diameter
pellets
Mo-0203-T-l/S in.
MO-0203-T-1/8 in.
promoted with indium
#9816
Harshaw Chemical
Company
Harshaw Chemical
Company
Humble Oil and
Refining Company
Peter Spence and
Sons, Ltd.
Union Oil Company
Harshaw Chemical
Company
Harshaw Chemical
Company
Esso Research
Esso Research
Esso Research
Esso Research
Esso Research
aFrom Benson and Berg, 1966.
-------
TABLE 4-6. CATALYST ACTIVITY USED FOR HYDROTREATIN6 OF SHALE OIL0
'Activity atT
operating condition
Catalyst0
HF-activated cobalt molybdate
Cobalt molybdate IV
Cobalt molybdate I
Cobalt molybdate III
Molybdenum oxide I
Cobalt molybdate IV
Oronite hydroforming catalyst
Molybdenum sulfide
Platinum (type 100)
MnOj deposited on DA-1
cracking catalyst
Union Oil cobalt molybdate
3/16-in. pellets
Molybdenum oxide II
Operating variable
Catalyst bed temperature (°C)
Reactor pressure (psig)
Space velocity (g/g-hr)
Gas rate (std ft3/bbl)
Gas composition, % H«
No. 1
1.30
1.00
0.78
0.71
0.70
0.70
0.66
0.59
0.59
0.50
0.43
0.36
No. 1
440
1,000
1.0
2,500
100
No. 2
2.70
1.00
-
0.82
1.00
0.59
0.75
-
0.51
0.37
0.33
0.49
Condition
No. 2
510
1,000
1.0
4,000
100
From Benson and Berg (1966).
b A-^-.ff... _ wt% nitrogen of cobalt molybdate IV
HLiiviuy - wt% n1trogen of Cata1yst
Catalyst composition corresponding to Table 4-5.
TABLE 4-7. HYDROREFINING OF CRUDE SHALE OILC
Original coke
distillate (wt%)
Sulfur
Nitrogen
Oxygen
0.54
2.0
1.2
After first
stage (wtS)
0.49
2.0
0.83
After second
stage (ppm)
60
917
-
From Montgomery (1968).
82
-------
30° to 350°C (86° to 662°F), and the characteristic "hot spot," or burning,
zone passes through the entire catalyst bed in the direction of flow. When
the burning zone has passed through the entire catalyst bed, the oxygen con-
centration can be increased, keeping the above restriction at the maximum
temperature until air itself is being used. Then it is cooled to the operat-
ing temperature, or presulfiding temperature, and purged with inert gas or
steam. Frequently, idle time on a commercial unit is so costly that the
deactivated catalyst can be replaced by fresh catalysts much faster, and thus
more cheaply, than they can be regenerated. The spent catalyst is removed
and regenerated ex situ, or custom regenerated. The regenerated catalyst is
then ready for the next replacement.
Certain deficiencies of crude oil can be corrected by supplying certain
chemical additive agents. The kind of additive agent to be used depends on
the desired quality to be imparted or accentuated in the oil. Some of the
agents may be beneficial under one set of conditions and harmful under another.
The additive agents consist of oxidation inhibitors, oiliness carriers, vis-
cosity index improvers, fluorescence improvers, and pour point depressants.
Agents for improving the viscosity index usually consist of high molecular
weight polymers of unsaturated hydrocarbons. The lack of fluidity in crude
shale oil at moderately low temperatures (high pour point) is explained by
the presence of bituminous materials, including resin, asphaltene, carbene,
carboid, and/or wax, which congeal when the shale oil is cooled. The fluidity
of oil containing bituminous substances depends not only on the quantity but
also on the type of crystals dispersed in the crude shale oil. Certain
chemicals can modify the structure of the crystals and alter the fluidity of
the oil. Such pour-point depressants may be present in the oil itself or may
be added to it.
Several synthetic compounds have been found which, when added in small
proportions to an oil, reduce the pour point (Kalichevsky and Stagner, 1942;
Wunderlich and Frankovich, 1970). These compounds are high molecular weight
condensation products. One type of pour-point reducing agent is made by con-
densing phenol and chlorinated wax by means of aluminum chloride, and further
condensing this reaction product with phthalyl chloride. Another type is a
synthetic hydrocarbon used for reducing the pour point by condensing a high
boiling monochloroparaffin with naphthalene by means of anhydrous aluminum
chloride.
An oil can be exposed to oxidation through exposure to the air. When a
shale oil breaks down in service as a result of oxidation, it may form more
heavy end products (resin, asphaltene, carbene, and carboid) or corrosive or
noncorrosive acids, or it may increase in viscosity. Oxidation, once started,
can proceed as a chain reaction that may take place in storage tanks, refinery
lines, and the fuel injection systems of engines. Oxidation in shale oil can
be delayed or prevented by the addition of small amounts of inhibitors. These
usually consist of hydroxy compounds, such as phenolic derivatives and naph-
thols; nitrogen compounds, such as naphthylamines, aniline, and its deriva-
tives; and sulfur compounds, represented by elemental sulfur, disulfides, etc.
83
-------
Diliness is the ability of the oil to form a hydrodynamic film between
two relatively moving surfaces and to support the load between them. Oiliness
agents are polar compounds. Shale oil refining processes may reduce the
oiliness property through the removal of naturally occurring polar-film-
forming 'compounds. Addition agents for improving oiliness usually include
fatty oils, such as sperm oil, lard oil and tallow; fatty acids, such as
oleic acid; and synthetic esters of fatty acids.
Usually, the addition of fluorescent agents in oils has no relation to
their performance in engines. However, the refiner is sometimes obliged to
refine the oils to meet the demand of the usually light-colored oils. In ser-
vice, oils tend to develop black carbonaceous material, which remains at least
partially suspended in them. If the oil is fluorescent and is examined in
reflected light, these black particles are concealed, and the oil appears
relatively unchanged. Several dyes have been developed for imparting the
desired fluorescence to oils. However, the addition of fluorescent agents may
not be necessary, since the production of shale oil with oil shale clay miner-
als at elevated temperatures during retorting might create the fluorescent
property inherently.
SUPPORTING PROCESSES
Hydrogen Manufacturing Plant
The shale oil produced by Paraho or TOSCO II retorting is generally too
high in its pour point, too viscous to be piped, and too high in nitrogen and
sulfur to be used as normal refinery feedstock. As a result, a refinery
upgrading process is necessary for crude shale oil, normally hydrogenation.
Generally, an auxiliary hydrogen plant is needed and constructed onsite.
Gases produced by the retort and the hydrotreating unit of crude shale
oil are first treated to remove sulfur compounds and saturate the olefins
before the gases and light ends are used in hydrogen plant feed. Activated
carbon, or CoMo—ZnO, beds are usually used to catalyze the removal of trace
quantities of sulfur compounds. Typically, a conventional steam-hydrocarbon
reforming hydrogen plant is used to provide hydrogen for the hydrotreating
units (Figure 4-3). Natural gas, propane, butane, and/or naphtha are used as
general feed gases. In catalytic steam-hydrocarbon reforming, volatile hydro-
carbons are reacted with steam over a nickel catalyst at 700° to 1,000°C
(1,292° to 1,832°F) to produce carbon oxides and hydrogen. The carbon monox-
ide formed, as indicated in the following equation, uses propane as a typical
hydrocarbon:
C3H8 + 3H20 >- SCO + 7 H2
It is converted to carbon dioxide according to the water-gas shift reaction
shown in the following equation:
CO + H20 >• C02 + H2
84
-------
oo
en
HIGH LOW
DESULFURIZATION TEMPERATURE TEMPERATURE
•FORMER SHIFT SHIFT
FEED
AT URAL GAS
PROPANE
BUTANE
NAPHTHA
^
F
>
,.
J
^1)11
< 1
,8 TEAM
] J
S s
AIR™
CO ^
— ,^
\^ i
ATALYST >
N TUBESl
"^
1
rS
i
,
' rS
_J
^STRIPPER J^ <
-------
The latter conversion takes place at 250°C (482°F) over an iron oxjde
catalyst. The gas leaving the reformer contains carbon monoxide and hydrogen.
The carbon monoxide is shifted to carbon dioxide, which can be readily adsorbed
and stripped from the system.
The total amount of hydrogen required for the hydrotreating unit is about
5.5 million standard m3 (200 million standard ft3) per day (White River Shale
Project, 1976) based on a production rate of 16,000 m3 (100,000 barrels) per
day of crude shale oil. A portion of the hydrogen (about 10 percent) can be
recovered from the hydrotreating unit and produced in the retorting plant
(available in the high-Btu gas). The hydrogen plant must be started a few days
before oil shale retorting to insure maximum hydrogen production.
Amine Treating
The purpose of amine (or acid gas) treatment is to separate sulfur com-
pounds for processing in a sulfur recovery plant and to separate a clean C02
stream that can be rejected to the atmosphere. In the case of hot carbonate
scrubbing, a relatively concentrated H2S stream can be separated for process-
ing in a Claus plant for sulfur recovery.
Gases and light ends produced by retorting and by hydrotreating crude
shale oil contain acid gases (hydrogen sulfide and carbon dioxide) as impurities,
A recirculating stream of diethanolamine (DEA) is used to remove these im-
purities by the following reactions:
RNH2 + H2S ^ RNH3HS (1)
RNH2 + C02 + H20 ^ RNH3HC03 (2)
Adsorption of hydrogen sulfide occurs at 38°C (100°F) or lower temperature
in the adsorber and rejection of hydrogen sulfide from the decomposition of
amine salts in the stripper is active at 116°C (240°F). Higher temperatures
are required for carbon dioxide both for adsorption (at 49°C [120°FJ) and
rejection (149°C [300°F]). A solution strength of 20 to 30 percent DEA is
used. Monoethanolamine, triethanolamine, and methyldiethanolamine have all
been used to adsorb hydrogen sulfide in amine treating.
A simplified schematic diagram of the equipment for recovery and amine
treating of the light ends is shown in Figure 4-4. The gas phase enters an
adsorber where it contacts the amine solution to form salts that then, pass
to the stripper as rich amine. In the stripper, heat is applied to decompose
the salts and regenerate the lean amine, which is returned to the adsorber.
The major portion of the treated gas leaving the adsorber is combined with
the hydrotreating unit light ends and compressed to hydrogen plant feed pres-
sure. The gas then passes to the hydrogen plant where it undergoes further
treatment for hydrogen sulfide removal and final desulfurization.
Low-Btu Gas Treating
Low-Btu gas is generated by the Paraho direct heating process. Usually
it contains small quantities of hydrogen sulfide and ammonia and thus requires
86
-------
HIGH BTU GAS
co
RETORT
GAS
PHASE
SEPARATOR
AMINE STEAM
HYDROCARBON PHASE
SOUR WATER
LIGHT ENDS FROM NAPHTHA HYDROTREATER
TO SULFUR RECOVERY
HIGH BTU GAS
TO H2 PLANT
LEAN OIL
^i i PHASE
SEPARATOR
->RICH OIL
-^SOUR WATER
TO STRIPPER
Figure 4-4. Flow diagram for amlne treating and recovery of shale oil light ends.
-------
treatment before It can be used for fuel gas. Amine treating is not efficient
for removing ammonia. The gas can be water-washed to remove ammonia prior to
sulfur removal. The high content of ammonia and carbon dioxide in the wash-
ing tower bottom material is treated in the sour water stripper.
Hydrogen sulfide in the washed low-Btu gas may be removed by any of a
number of wet or dry processes, such as absorption in liquid scrubbing systems
or on dry solids (dolomite or iron oxide). The use of hot carbonate scrubbing
requires that the gases be cooled to 120°C (250°F), while hot ferric oxide,
for example, can be used on a solid absorbent if the gases are cooled to
below 537°C (1000°F). The purified low-Btu gas can be fed as the fuel gas for
the retorting unit.
Tail Gas Treating arid Sulfur Recovery
The purpose of tail gas treating is to separate sulfur compounds for pro-
cessing in a sulfur recovery plant and to separate a clean C02 stream that
can be eliminated in the atmosphere. The tail gas treating unit handles the
waste flue gas from the sulfur recovery plant, the amine absorber treating
unit, the wastewater treating plant, and the sour water stripper unit. The
exhaust gases of these treating units contain high levels of hydrogen sulfide,
ammonia, and carbon dioxide.
The following two consecutive reactions show the Claus process (Seglin,
1976) for sulfur recovery:
H2S + 3/2 02 > H20 + S02 (3)
2H2S + S02 catalyst * 2H2° + 3S (4)
•
Carbonyl sulfide (COS) undergoes reactions similar to these to form sulfur
plus carbon dioxide. In the Claus operation, one-third of the recovered
sulfur is burned in a waste heat boiler to form the necessary S02 for reac-
tion 4. This process reduces the hydrogen sulfide emission in the tail gas
to a very low level.
The hydrogen sulfide produced in the tail gas can also be recovered as
elemental sulfur using the Stretford process in which the gas is washed with
an aqueous alkaline solution containing sodium carbonate, sodium vanadate,
and anthraquinone disulfonic acid. The hydrogen sulfide dissolves in the
alkaline solution, reacts with the 5-valent state vanadium, and is. oxidized
to elemental sulfur. The liquor is regenerated by air-blowing. The hydro-
gen sulfide can be removed to any desired level via this process.
Wastewater Treatment
Processed water from the hydrotreating units is transferred in the waste-
water treating plant to recover hydrogen sulfide (sulfur recovery plant feed),
anhydrous liquid ammonia as a net product, and stripped water (which is,re-
cycled to the hydrotreating processes).
-------
Various methods are available for cleaning the hydrotreating wastewater
for reuse. The Claus process can be used to remove H2S, then a sour water
stripper can be used for ammonia removal. Other cleanup steps may also be
needed-for example, filtration to remove suspended solids and lime to remove
inorganic ions (e.g., ammonium, carbonates). In order to further reduce the
level of soluble organics, biological oxidation (biox) may be provided. Biox
can be effective on organics, nitrogen, phosphorus, and sulfur/compounds,
though additional nutrients may have to be added to provide the proper bal-
ance. Biox does not, however, satisfactorily clean up refractory compounds
such as alkylated benzene and naphthalene that may be present. Final treat-
ment with an electrolytic process (Wen and Yen, 1977) or activated carbon may
be needed.
Sour Water Stripper
The condensate formed by cooling the hydrotreating unit contains water
from unreacted steam, together with oil, coke, and contaminants from crude
shale oil decomposition. The types of compounds present in this condensate,
or sour water, include sulfur compounds (such as hydrogen sulfide, thiophene,
carbonyl sulfide, etc.), oxygen compounds (such as phenols, fatty acids,
etc.), nitrogen compounds (such as ammonia, amines, etc.), carbon dioxide,
chlorides, and other contaminants. There are also complexes resulting from
the interaction of these compounds, e.g., thiocyanates, ammonium polysulfides,
etc.
The major constituent of the sour water is ammonia. The system for re-
moving ammonia from sour water is an ammonia stripping process (Gulp and Gulp,
1971; Snow and Wnek, 1968), In sour water, either ammonium ions, NHt, or dis-
solved ammonia gas, NH3, or both, may be present. At pH 7 only ammonium ions
in solution are present. At pH 12 only dissolved ammonia gas is present, and
this gas can be liberated from wastewater under proper conditions. The
equilibrium is represented by the equation: NHj ^ *• NH3 + H+. As the pH
is increased above 7, the reaction proceeds to the right. Two major factors
affect the rate of transfer of ammonia gas from water to the atmosphere:
(1) surface tension at the air-water interface; and (2) difference in con-
centration of ammonia in the water and the air. Surface tension decreases
to the minimum in water droplets when the surface film is formed,/and ammonia
release is greatest at this point. Little additional gas transfer takes place
once a water droplet is completely formed. Therefore, repeated droplet forma-
tion of the water assists ammonia stripping. To minimize ammonia concentration
in the ambient air, rapid circulation of air is beneficial. Air agitation
of the droplets may also speed up ammonia release. The ammonia;"stripping
process, then, consists of: (1) adjusting the pH of the water to values in
the range of 10.8 to 11.5; (2) formation and reformation of water droplets
in a stripping tower; and (3) providing air-water contact and droplet agita-
tion by circulation of large quantities of air through the tower (Figure 4-5).
89
-------
(£>
O
SOUR
WATER
INLET
AIR INLET
FAN
AIR OUTLET
!
T
:j—ir
if ^p*
DRIFT
ELIMINATORS
.DISTRIBUTION
SYSTEM
AIR INLET
WATER-COLLECTING
BASIN
COUNTERCURRENT TOWER
Figure 4-5. Typical ammonia stripper tower.
-------
SECTION 4 REFERENCES
Bartick, H., K. Kunchal, D. Switzer, R. Bowen, and R. Edwards, Final Report-
The Production and Refining of Crude Shale Oil into Military Fuel,
Applied Systems Co., Office of Naval Research Contract NOOOT4-75-C-0055,
August 1975.
Benson, D.B., and L. Berg, "Catalystic Hydrotreating of Shale Oil," Chemical
Engineering Progress. Vol 62, No. 8, p 61 , 1966.
Cottingham, P.L., and L.6. Nickerson, "Diesel and Burner Fuels from Hydro-
cracking In Situ Shale Oil," Hydrocracki ng and Hydrotreati ng (J.W. Ward,
ed), American Chemical Society Symposium, Series 20, 1975.
Culp, R.L., and G.L. Gulp, Advanced Waste Water Treatment. Van Nostrand
Reinhold Co., New York, 1971.
Frost, C.M., R.E. Poulson, and H.B. Jensen, "Production of Synthetic Crude
Shale Oil Produced by In Situ Combustion Retorting," Shale Oil, Tar
Sands and Related Fuel Sources (T.F. Yen, ed), Advances in Chemistry
Series, No. 151, pp 77-91, 1976.
Kalichevsky, V.A. , and B.A. Stagner, Chemical Refining of Petroleum, American
Chemical Society Series, Reinhold Publishing Co., 1942.
Montgomery, D.P., "Refining of Pyrolytic Shale Oil," Industrial Engineering
Chemical Products Research and Development, No. 7, p 274, 1968.
Satterfield, C.N., M. Model!, and J.F. Mayer, "Interactions between Catalytic
Hydrodesulfurization of Thiophene and Hydrodenitrogenation of Pyridine,"
American Institute of Chemical Engineers Journal, Vol 21 , p 1100, 1975,
Schuit, 6.C.A., and 6.C. Gates, "Chemistry and Engineering of Catalytic Hydro-
desulfurization," American Institute of Chemical Engineers Journal . Vol
19, p 417, 1973.
Seglin, L., Preliminary Evaluation of the S03-Coal Gasification Process,
U.S. Energy Research and Development Administration, report from
Econergy Association, New York, 1976.
Silver, H.F., N.H. Wang, H.B. Jensen, and R.E. Poulson, "Comparison of Co-Mo
and Ni-W Catalysts in the Denitrification of Shale Gas Oil." American
Institute of Chemical Engineers Symposium Series, Vol 156, No. 72, p 346,
-
Snow, R.H., and W.J. Wnek, Ammonia Stripping Mathematical Model for Wastewater
Treatment. I IT Research Institute, final report IITRI-C6152-6 to Federal
Water Pollution Control Administration, December 1968.
Thomas, C.L., "Hydrorefining of Shale Oil," Catalytic Process and Proven
Catalysts. Chapter 16-IX, Academic Press, New York, 1970.
91
-------
Wen, C.S., and T.F. Yen, "Purification and Recovery of Economic Material from
Oil Shale Retort Water by an Electrolytic Treatment Process," Proceedings
of Second Pacific Chemical Engineering Congress. Vol 1, 1977.
Whitcombe, J.A., and R. Glenn Vawter, "The TOSCO II Oil Shale Process,"
presented at the 79th American Institute of Chemical Engineers Meeting,
March 16-20, 1975.
White River Shale Project, Detailed Development Plan, Federal Lease Tracts
Ua and Ub, Part 1-7,
Wunderlich, O.K., and J.F. Frankovich, "Pour Point Depressant," U.S. Patent
3,532,618, October 6, 1970.
92
-------
SECTION 5
ORGANIC CONTAMINANTS
Because of the known and unknown consequences of oil shale exploitation,
actions seeking to stimulate its commercialization must be balanced by concerns
for environmental, social, and economic impacts that might be caused by oil
shale development. Perhaps the major environmental health problem associated
with oil shale technology is the potential release of carcinogenic organic com-
pounds, such as the polynuclear aromatic hydrocarbons, and their nitrogenous
derivatives. In this section, potential pollutants are first categorized by
the origins of their production. These potential pollutants are then discuss-
ed in relation to possible health and environmental problems. In the charac-
terization and measurement of organics, there are two extremes: one can view
organics as a lumped constituent and determine total organic carbon (TOC) or
similar measurements, or one can address specific compounds. The level of
organic compound identification for this discussion is somewhere in between,
restricted largely by the incomplete state of knowledge concerning organics in
_oil shale processing. An attempt will be made to identify the classes of
organic compounds that may be present in oil shale.
SOURCE OF POLLUTANTS
Many of the pollution effects associated with oil shale are similar to
those of other mining or refining operations. However, shale retorting results
in the production of unique gaseous and liquid effluents, plus solid residues,
which contain potentially hazardous organic and inorganic pollutants. Pollu-
tants may differ in type and quantity, depending on the type of recovery,
retorting, upgrading, and disposal methods used. A generalized oil shale
fuel production cycle is shown in Figure 5-1.
\
Mining Processes
Oil shale extraction and handling result in generation of particulates,
noise, runoff, and many pollutants similar to those encountered in other mining
operations. Many of the pollutants from mining and crushing are inorganic;
these are discussed in Section 6. The major sources of organic pollutants from
mining are the mining and crushing machinery that contribute to air pollution.
In both the conventional and the in situ processes, chemical explosives
are used in the fracturing step and might prove to be a significant source of
organic pollutants (Miller and Johnsen, 1976). For example, picry! chloride
has been tentatively identified from the X-ray diffraction pattern (Figure 5-2)
of the acid fraction in retort water (Kwan and Yen, unpublished data).
93
-------
Mining
I
Crushing
I
Retorting
Spent
Shale
Disposal
Oil Shale
Deposits
Crude
Shale Oil
1
Upgrading
i
Refining
i
Fuel and
By-Products
Fracturing
I
Retorting
i
Product
Recovery
Figure 5-1. Oil shale fuel production cycle.
94
-------
S-SULFUR
PC-PICRYL CHLORIDE
26 22 18
DEGREE 29
10
Figure 5-2. X-ray diffraction pattern of acid fraction in retort
water (Kwan and Yen, unpublished data).
95
-------
Picryl chloride (2-, 4-, 6-trinitrochlorobenzene) could be derived from TNT
(2-, 4-, 6-trinitrotoluene) during the retorting process (Figure 5-3).
TNT Picryl Chloride
Figure 5-3. Derivation of picry! chloride from TNT.
Retorting Processes
Retorting of oil shale results in the production of unique gaseous and
liquid effluents containing potentially hazardous inorganic and organic pollu-
tants. In the Paraho and the TOSCO II retorting processes, the oil vapors are
collected and condensed into liquid shale oil. The uncondensable fraction of
oil vapor is a low-Btu gas that is used as internal fuel, as shown in Figure
5-4. The heating value of these gases is about 83 Btu/standard ft3 for the
Paraho DH process, 100 Btu/standard ft3 for the Paraho IH process, and 923
Btu/standard ft3 for the TOSCO process. Water is also produced during the
pyrolysis of the-oil shale, and this water may be treated for use and/or used
for moisturizing the spent shale prior to disposal. These gaseous and liquid
waste streams are discussed in more detail subsequently.
In the in situ process after shale has been retorted from a portion of a
wet shale formation, the residue and surrounding strata are cooled by conduc-
tion and seepage of water into the region. Migration of groundwater through
the burned-out region as the result of hydraulic gradients may cause leaching
of chemicals from the residue. An in situ rubblized zone may include areas
with only spent shale and areas with partially burned shales in varying
states. There may be regions that contain condensed tars because of incom-
plete pyrolysis. Thus, the water migrating through a burned-out zone may
come into contact with anything from spent shale to unaffected shale. There-
fore, a wide variety of both organic and inorganic compounds may be extracted
by these processes.
Upgrading Processes
Upgrading of crude shale oil results in pollutants common to petroleum
refinery operations. The sources of wastes originating from refinery opera-
tions can be divided into five categories (Rice et a!., 1969; McPhee and
Smith, 1961).
96
-------
VO
Raw
Shale
Mist Formation
and Preheating
Retorting Zone
Heating
Residue Cooling
and Gas Pre-
heating
I
Spent
Shale
Gas
Stack
i
*£
Heater
Recycle
Gas Blower
Electrostatic
Precipitation
Cooler
Oil
Product
Gas
Figure 5-4. Paraho process-indirect heating mode flow diagram.
-------
1. Wastes containing a principal raw material, or product,
resulting from the stripping of the product from solution
2. By-products produced during reactions
3. Vessel cleanouts, slab washdown, spills, sample point
overflows, etc.
4. Cooling tower and boiler blowdown, steam condensate, water
treatment wastes, and general washing water
5. Storm waters, the degree of contamination depending on the
nature of the drainage area.
The characteristics of wastes discharged from refinery complexes depend
on the nature and source of the crude oil processed, the design and type of
production facilities, the age of the facilities, the cooling water require-
ments, and housekeeping and control practices employed.
Waste Disposal
Disposal and stabilization of large volumes of potentially toxic spent
shale from aboveground retorting are significant waste management concerns.
To supply the raw material for a projected 8,000 m3 (50,000 bbl) per day
operation, 66,850 tonnes (73,700 tons) per day of raw shale (.averaging 114
liters [30 gallons] of shale oil per ton) must be mined. The mining and
retorting will generate about 54,420 tonnes (60,000 tons) of spent shale to
be disposed of each day. The 16,000 m3 (100,000 bbl) per day U-a and U-b
operation in Utah will ultimately require about 900 hectares (2,300 acres)
for spent-shale disposal (WRSP, 1976). The leaching of such disposal piles
could be a serious problem. Erosion of spent-shale piles may be eliminated
to a certain extent through physical, chemical, and vegetative methods of
stabilization (Dean et al., 1968). The tailings can be covered with topsoil
removed from underneath the shale residue piles. Studies by Schmehl and
McCaslin (1969) indicated that 10 centimeters (4 inches) or more of topsoil
cover may be required for vegetative stabilization. Chemical stabilization
may be achieved by reacting the spent shale with chemicals to form an air
and water impermeable layer that prevents erosion and groundwater leaching.
Compaction aids to decrease infiltration of water into the processed-shale
pile, thus mitigating formation of leachate. Compaction also aids in reduc-
ing erosion and hence helps stabilize the disposal pile. Sloping and contour-
ing to control runoff and erosion also aids stabilization.
A conceptual spent-shale disposal operation of a type represented by
commercial developments was presented by Parker (1976) (Figure 5-5). In
this design, an upstream flood control reservoir will divert any water that
might flow down the canyon around or under the spent-shale pile to reduce
leaching problems. Runoff water from the spent-shale embankment goes into
a containment pond. The runoff water is returned to the plant and reused to
moisturize more spent shale (Parker, 1976).
98
-------
Runoff
containment
pond
Flood control
reservoir
Plant
ID
Temporary exposed
surface
surface runoff from pile
returned to plant
Permanent stream diversion
Figure 5-5. Disposal of spent shale from a commercial operation (Parker, 1976).
-------
HEALTH AND ENVIRONMENTAL PROBLEMS
As summarized briefly in this discussion, a great deal of work has been
and is being conducted to characterize oil shale products and by-products and
to evaluate the potential effects (toxicity, carcinogenicity, etc.) of these
materials. However, most of the effort to date has been somewhat qualitative
since the likelihood that potentially hazardous materials may be present at
levels high enough to present harm to organisms (including man) is not known.
Water Pollution
Management of spent shale requires considerable amounts of water for cool-
ing, dust control, and compaction. Treatment and handling of the retort waters
constitute another problem area.
The retort water or process water that comes from aboveground retorting
processes may be separated from crude shale oil during storage (e.g., in the
TOSCO II process) or broken up into aerosols (e.g., in the Paraho process).
In order to identify the organic components in retort water, it is important
to define what is collected as retort water. If fine oil particles are dis-
persed in the water, separation times can be lengthy. Therefore, consistent
sampling techniques are very important in the organic analysis of retort water.
Crude shale oil has the highest nitrogen content relative to naturally
occurring oils, as well as to other synthetic oils (Poulson et al., 1976;
Bartick et al., 1975; Jensen et al., 1971; Dunstan et al., 1938). Crude shale
oil contains twice as much nitrogen as high nitrogen petroleum crudes (Table
5-1). Retort waters contain high concentrations of ammonia-nitrogen (Table
5-2). Nitrogenous compounds are unique because they can assume either acidic,
basic, neutral, or amphoteric properties and are recognized as good surface-
active agents. Ammonium salt, nitrogen bases, amines with ester, or amide
linkages are excellent cationic surface-active agents (Schwartz et al., 1970).
Because of this characteristic, the nitrogen components in crude shale oil and
the retort water result in the relatively high water content of crude shale
oil and also the high total organic carbon (TOC) in both retort waters and the
Black Trona water. Anionic detergency from carboxylic acids plays an impor-
tant role, too, particularly for the latter type of water (Dana and Smith,
1973).
Many nitrogen-containing compounds are labeled as potential carcinogenic
agents (Hueper and Conway, 1964); some of the known are shown in Figure 5-6.
Many other compounds can cause a variety of physiological effects. The
specific nitrogen compounds in the retort water have not been completely iso-
lated and identified.
The aromatic hydrocarbon content in retort water is about 30 to 40
percent lower than the nitrogen compound content. Toxicity and bioaccumula-
tion potential of the aromatics are very important. As a general rule, the
very large polycondensed organic matter (POM) compounds, such as graphite,
are quite inert and stable. It is the medium and small molecules that may
be toxic. Also, in water treatment, removal efficiency is in inverse propor-
tion to the molecular weight of the compound; the greater the number of rings,
the more difficult is removal.
100
-------
TABLE 5-1. PROPERTIES OF RAW SHALE OIL AND PETROLEUM CRUDES (Bartick
et al., 1975; Jensen et al., 1971; Dunstan et al., 1938)
Properties
Gravity °API
Sulfur wt%
Nitrogen wt%
Ni ppm
V ppm
As ppm
Viscosity SUS
38°C (100°F)
Conradson Carbon
wt%
Bromine Number
Petroleum TOSCO II LERC in situ Paraho
crude shale oil shale oil shale oil
15 -
0.04 -
0.01 -
0.03 -
0.002 -
0 -
31 -
0.1 -
-
44
4.1
0.65
45
348
0.030
1025
11.4
22
0.9
1.9
6
3
40
106
4.6
49.5
28
0.7
1.4
-
-
-
78
1.7
-
19.3
0.61
2.19
2.5
0.37
19.6
46.8
1.4
-
TABLE 5-2. COMPOSITION OF RETORT WATER FROM DIFFERENT PROCESSES
Constituents
COD
BOD
TOC
NH4-N
Organic-H
Phenol
LERC 10- ton
in situ simulated
20,000
5,500
3,182
4,790
1,510
169
Paraho direct
modeb
19,400
12,000
29,200
14,600
17,340
46
Paraho .
indirect mode
17,100
4,850
9,800
16,800
42
aYen and Findley, 1975.
bCotter et al., 1977.
101
-------
N
nitrosos (Basic)
azabenzanthracenes (Neutral)
carbamic acid esters (Acidic)
aminobiphenyls (Acidic)
N
amino azobenzenes(Basic)
dibenzcarbazoles(Acidic)
Figure 5-6. Known nitrogenous carcinogenic compounds (Hueper
and Conway, 1964).
102
-------
A summary of the acute toxicity data (for fish) of the aromatic hydro-
carbons is shown in Figure 5-7, with acute toxicity (48-hr LCSO plotted
against molecular weight (Herbes et al., 1976). (The 48-hour LC50 here is the
level of exposure resulting in 50 percent mortality of the test animals in 48
hours.) Figure 5-&.contains the same plot for arylamines. The data show a
direct relationship between the acute toxicity and molecular weight. A 50-
unit increase in molecular weight corresponds to a tenfold increase in toxic-
ity. Unfortunately, there is generally a paucity of data available on the
effects of these compounds, particularly with respect to long-term exposure,
mutagenesis, teratogenesis, and carcinogenesis.
Another extremely important parameter in estimating the potential environ-
mental impact of a contaminant is its bioaccumulation potential. Bioaccumula-
tion is the process by which nonmetabolized materials are concentrated by
passage through the food chain. Materials that are present in very low concen-
tration in the abiotic regime can be concentrated in a stepwise manner until,
at higher trophic levels, they may be present in sufficient levels to upset
essential metabolic processes. Figure 5-9 shows potential bioaccumulation for
polycyclic aromatic hydrocarbons (PAH) (Herbes et al., 1976). The higher the
molecular weight of the compound, the greater the bioaccumulation potential.
In addition, higher molecular weight compounds degrade more slowly and tend to
persist in the environment for a longer time.
-,
Air Pollution
Pollution resulting from extraction, processing, and retorting may alter
the present good air quality of the resource region. Atmospheric emissions
from demonstration plants and the transport and fate of organic compounds and
other contaminants must be characterized and defined.
Atmospheric emissions of organics arise from several subprocesses during
an oil shale operation (Table 5-3). Airborne particulates are of interest
because the Aiken-type particulates (particles with diameter less than 0.1
micron), which may be organometallic, are released during the combustion of
shale oil fuels. Because of the biocompatibility of organometallic compounds
and fauna, the resulting particulates could be highly toxic, depending on the
properties of the metal. Overall emission data for a fully developed oil
shale processing facility have been estimated, and potential organic pollu-
tants and particulates are summarized in Table 5-4 (Rio Blanco Oil Shale
Project, 1976; Schmidt-Collerus et al., 1976). Vapors from the product storage
tanks can contribute significantly to organic air pollution (Table 5-5).
Solid Wastes
Surface retorting results in considerable land disruption and requires
the disposal of large amounts of spent shale. The health effects of spent
shale and releated materials are of great concern. A very detailed study has
been conducted by Schmidt-Collerus et al. (1976) on polycondensed (or poly-
nuclear) aromatic compounds in the carbonaceous spent shale. A large number
of polycyclic aromatic compounds including benzo(a)pyrene have been identified.
They have been found to be easily leached out from carbonaceous shale and to
migrate with the leaching water. Animal experiments with spent shale have
103
-------
I03-
•o2-
2
I0'-i
most resistant fish
most sensitive fish
I I I I | | T^
60 80 100 120 140 160 180 200
MOLECULAR WEIGHT
Figure 5-7. Acute toxicity data of aromatic hydrocarbon to fish (Herbes et al., 1976),
-------
o
in
10*-
10'
00
.(*>-
most resistant fish
60 80 100 120 140 160 180 200
MOLECULAR WEIGHT
Figure 5-8. Acute toxicity data of arylamines to fish (Herbes et al., 1976).
-------
o
o*
KT-
I03-
I02-
8
o
CD |0'
,1-
60
most resistant fish
T"
80
most sensitive fish
100
120
140
160
180
200
MOLECULAR WEIGHT
Figure 5-9. Bioaccumulation factor (concentration in organism vs. concentration in abiotic aquatic
phase) for polycyclic aromatic hydrocarbons to fish (Herbes et al., 1976).
-------
TABLE 5-3. PARTICULATES AND ORGANIC AIR POLLUTANTS FROM DIFFERENT SUBPROCESSES
(Herbes et al., 1976)
Subprocess
Source of pollutants
Air pollutants
Parti oil ate matter
Hydrocarbons
Extraction
Transportation
Preparation
Retorting
Upgrading
Product storage
Solid waste disposal
Blasting
Mining equipment fuel use
Equipment fuel use
Crushing, screening, ore storage
Preheat fuel use
Combustion of organic material
Reheat carrier fuel use
Heater and furnaces fuel use
Tank evaporation
Spent shale transport
Coke, spent catalyst
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
-------
o
00
TABLE 5-4. AIR POLLUTION EMISSION INVENTORY ESTIMATED FOR OIL SHALE PROCESSES
(Rio Blanco Oil Shale Project, 1976)
Emission source
Mining equipment (26,000 gal/day diesel fuel)
TOSCO II preheated system
TOSCO II steam superheater belt circulation
TOSCO II shale moisturization
Gas combustion process (Paraho) air heater
Gas combustion shale moisturizer scrubber
Coker feed heater
Gas oil hydrotreater heaters
Gas oil hydrotreater boiler
Naptha hydrotreater heaters
Glycol fired reboiler
Utility boilers
Hydrocarbons
(kg/hr) (Ib/hr)
14
130
15
-
1
-
0
1
1
0
1
5
.74
.2
.4
.18
.82
.54
.4
.41
.27
.44
( 32.
(287
( 34
-
( 2.
-
( 1.
( 3.
( 3.
( 0.
( 2.
( 12
5)
)
)
6)
8)
4)
1)
9)
8)
}
Particulates
(kg/hr) (Ib/hr)
11
107
60
31
0
0
0
• 1
0
0
0
5
.69
.85
.32
.82
.771
.32
.54
.04
.95
.27
.86
.44
( 25.
(238
(133
( 70
( 1.
( o.
( 1.
( 2.
( 2.
( o.
( 1.
( 12
8)
)
)
)
7)
7)
2)
3)
1)
6)
9)
)
-------
TABLE 5-5. VAPOR LOSSES FROM STORAGE TANK
o
vo
Storage tank
contents
Raw shale oil
Raw shale oil residue
Raw naptha
Raw gas oil
Sponge oil
Hydrogen plant feed
Coker residue
Product naptha
Product gas oil
Product diesel
Type of tank
Floating roof
Cone roof
Floating roof
Cone roof
Cone roof
Cone roof
Cone roof
Floating roof
Cone roof
Floating roof
Vapor pressure of
contents, psi
do'3
0.01
0.001
1.8
0.01
0.02
0.001
0.001
2.2
0.01
0.02
kg/cm2)
( 0.703)
( 0.070)
(127 )
( 0.703)
( 1.406)
( 0.070)
( 0.070)
(155 )
( 0,703)
( 1.406)
Vapor
m3/yr
0.3
0.3
14.2
9.4
9.0
0.02
0.05
19.5
9.3
0.08
loss
(bbl/yr)
( 2
( 2
( 89
( 59
( 56
( 0.
( o.
(122
( 58
( 0.
)
)
)
)
)
1)
3)
)
)
5)
-------
been conducted by TOSCO (Hueper, 1953). Hairless mice were kept in spent shale
of various compositions and corncob bedding for the test of skin cancer. The
result showed some susceptability to skin cancer; however, overall data from
these and other experiments have been inconclusive as to the extent of poten-
tial carcinogenicity that may be associated with oil shale products.
In addition to spent shale, other solid wastes are also produced by dif-
ferent processing facilities. They include spent catalysts from hydrotreating,
water-gas shift, naphthanation and sulfur recovery processes, sludge from
water treatment, and spent ceramic balls, from the TOSCO process in particular
(Table 5-6).
Regardless of the configuration of the in situ or modified in situ pro-
cesses, the solid wastes generated are anticipated to be different from those
from aboveground retorting. The quantitative and qualitative characters of
organics may be expected to vary according to the severity of retorting condi-
tions. The in situ process takes months to complete because of the slow
cooling effect in the reaction site (Figure 5-10) (Kwan and Yen, unpublished
data). The model was based on the assumption that the reaction cavity main-
tains a stable temperature for 5 months. The temperature outside the cavity
depends on the thermal diffusivity and the thickness of the shale wall (Prates
and O'Brien, 1975; Kwan and Yen, unpublished data). TOSCO II processed shale
contains 4.5 percent (by weight) organic carbon (Whitcombe and Vawter, 1976);
Paraho processed shale contains about 3 percent (Schmidt-Collerus et al.,
1976). The amount of carbon, and also probably the composition of the organ-
ics, present in spent shale are expected to vary depending upon the retorting
conditions (e.g., time and temperature of retorting; Figure 5-11). '
Occupational Health
The potential carcinogenicity of oil shale was first reported in relation
to a Scottish oil shale plant where 65 cases of skin cancer were identified
during the period 1900-21 (Key, 1974). Mutagenicity may also be associated
with industrial wastes (Mulling, 1972).
Early data from animal tests showed that shale oil has carcinogenic
properties (Hueper, 1953). In Scotland, an experiment conducted to compare
Scottish shale oil and raw shale showed that the shale oil exhibited carcino-
genic properties (Berenblum and Schoental, 1943 and 1944), while the raw shale
was inactive (Berenblum and Schoental, 1944). These results indicated that
the carcinogenic compounds are formed during the pyrolysis or combustion of
organic materials. Santer (1975) reported that workers involved in synthetic
fuel operations such as coal or oil shale conversion have a 16- to 37-times
higher-than-normal chance of contracting skin cancer. Among the carcinogenic
agents in oil shale and its derivatives, benzo(a)pyrene has received the most
attention (Schmidt-Collerus et al., 1976; Hueper and Cahnman, 1958; Colony
Development Operation, 1974), largely because the analytical techniques for
identifying benzo(a)pyrene are well established. However, as-yet-unidentified
carcinogenic agents in the oil shale could be more hazardous. Health pro-
blems could stem from the potential carcinogenic, mutagenic, and teratogenic
nature of some oil shale processing products.
110
-------
TABLE 5-6. PROCESSING FACILITY SOLID WASTES FOR PHASE II OF PROCESSING
PROJECTED FOR FEDERAL TRACTS U-a AND U-b (WRSP, 1976)
Process unit
Solid waste description
Approximate quantity8
kg/yr
Ib/yr
Naptha hydrotreating
Naptha hydrotreating
Gas oil hydrotreating
Gas oil hydrotreating
Hydrogen plant
Shift conversion
Methanation unit
Sulfur recovery
Claus unit
Tail gas unit
Support facilities
Water treating
Spent hydrotreating catalyst 33,000
Proprietary solid 65,500
Spent hydrotreating catalyst-lb 142,500
Spent hydrotreating catalyst-2b 118,000
Proprietary solid 697,000
Spent CO shift catalyst 36,500
Spent CO methanation catalyst 4,500
Spent oxidation catalyst 36,500
Spent hydrogenation catalyst 22,500
Spent zeolites 2,385
Lime sludge 6,500
aAveraged over catalyst life.
Two different catalysts involved in gas oil hydrotreating;
( 73,000)
( 144,000)
( 314,000)
( 260,000)
(1,536,000)
( 80,000)
( 10,000)
( 80,000)
( 50,000)
( 5,300)
( 14,450)
-------
(700°F = 371°C)
600
400-
I ,
a H
200
Assumption : Cavity stays at constant
temperature for 5 months.
Equation : T
+ (T0 -
(Schack, 1965)
C32°F, 0°C) Equilibrium temperature
(750°F, 399°C) Heating temperature
X = Thickness feet
a = Thermal diffusivity
Decay efficient
t = Time
I
20
1
30
Distance from center of retort
I 50 ft. • 9.14 m)
Figure 5-10. In situ retort cavity combustion temperatures before
steady-state temperatures are reached.
112
-------
Fig. o Temperature effect on benzene edroct from spent state
derived from combustion (air) and pyralysis (H«)
Fig.b Effect of healing time on benzene extract from epent
•hate derived from combuctian (air) and pyrolrolysis (H«)
2.0
1.0
0.0
I I !
HEATING TIME 2 HOURS
O Ht GAS
A AIR
400
I
500 600
TEMP»C
40
3.0
2.0
1.0
0.0-
700
HEATING TEMP. 500*C -
O He GAS
A AIR
2 4
TIME (HOUR)
Figure 5-11. Effect of (a) temperature and (b) heating time on the proportion of organic carbon
In spent shale extractable with benzene (percent benzene extracted). The spent
shale was derived from combustion (air atmosphere) retorting, and pyrolysis (helium
[He] atmosphere) (Kwan and Yen, unpublished data).
-------
Some of the known human carcinogens are listed in Table 5-7. To date,
these specific compounds have not been identified in oil shale process streams.
Epidemiological data relating cancer to pollutants is still inconclusive.
Exposure histories, particularly for humans, may be extremely complex and, in
most cases, data do not exist for the several decades sometimes required for
an effect to be realized. Also, many pollutant species have not been com-
pletely characterized. Another important factor is the carcinogen conglom-
erate, or the factors that affect the activity of a carcinogen. For example,
the Ci2-C28 n-alkanes can increase the carcinogenicity of benzo(a)pyrene a
thousandfold.
TABLE 5-7. HUMAN CARCINOGENS*
Substance
Body parts affected
4-Aminobiphenyl
Benzidine
2-Naphthylamine
4-Nitrobiphenyl
Bis-(chloromethyl) ether
Chloromethyl methyl ether
Soots, tars, oils
Cigarette smoke
Asbestos
Coke oven fumes
Nickel compounds
Chromate
Coal tar and pitch
Melphalen
Cadmium
Isopropyl oil
Vinyl chloride
Arsenic
Diphenylhydantion
Chloroamphenicol
Cyclophpsphamide
Urinary bladder
Urinary bladder
Urinary bladder
Urinary bladder
Lungs
Lungs
Lungs
Lungs, stomach, colon,
urinary bladder
Bronchi
Bronchi
Bronchi
Bronchi
Bronchi
Blood
Prostate
Nasal cavity
Liver
Lungs, skin
Lymphoma
Blood
Blood
mesothelium
kidneys
skin
a From Hueper and Conway, 1964, and Sawicka, Eugene (EPA-RTP),
1978 personal communication.
114
-------
Atwood and Coombs (1974) indicated that raw shale oil has a mild carcino-
genic potential, comparable to some intermediate petroleum refinery products
and product oils. Upgraded shale oil has a lower carcinogenic potential than
raw shale oil. Most of the polycyclic aromatics are believed to be broken
down by nydrogenation. The chemical character and ultimate fate of many of
the materials used or created in oil shale processing are not clear and pre-
dictable at this time.
Product Combustion
Differences in emissions from the combustion of fuels refined from crude
shale oil and those from combustion of conventional fuels are of interest
because of the potential for widespread use of synthetic liquid fuels for
transportation. The combustion of fuel products recovered from oil shale
exposes occupational and general populations to various atmospheric pollutants.
Health research is required to identify hazardous agents, to develop early
indicators of stress and damage, and, most importantly, to determine the path-
way and the fate of active agents.
The only significant differences between conventional petroleum fuel and
oil-shale-derived fuel may lie in the trace elements, such a? arsenic in shale
fuel oil, and any unburned hydrocarbon emissions. An extensive program was
conducted by the U.S. Navy Energy and Natural Resources Research and Develop-
ment Office to determine the performance and emission characteristics of the
shale-derived fuels in comparison with petroleum-based fuels (Denver Research
Institute, 1976). In terms of combustion efficiencies, the two fuels
showed no basic differences. Also, no appreciable differences were noted in
unburned hydrocarbon emissions. In these tests, shale oil fuels demonstrated
poor thermal and storage stability. These characteristics are attributed to
its high olefin content (Jensen et al., 1971; Jackson et al., 1977).
High concentrations of high-melting-point wax were also noted in the Navy
tests. Long chain paraffin compounds were found in shale oil asphaltene by
Yen et al. (1977). The asphaltene was derived from a residue generated by
processing Paraho syncrude through a delayed coker. Sharp,bands: at 3.70 and
4.15 A from X-ray diffraction patterns (Figure 5-12) indicated the presence
of these long-chain paraffins. Such crystalline peaks have also been found in
petroleum-derived asphaltenes (Yen, 1971). The presence of long-chain paraf-
fins in petroleum and shale oil asphaltene can be explained by the coprecipi-
tation with asphaltene molecules during solvent separation.
Emissions from some combustion experiments using shale oil products have
shown a rather high content of fuel-bound nitrogen. Upgraded shale oil is
known to contain higher proportions of aromatics than do natural crudes (Goen
and Rodden, 1974). The aromatic content of shale-oil-derived fuels will con-
tribute to a high rate of emission of aromatics.
TYPES OF OIL SHALE AND PRODUCT ORGANIC COMPOUNDS
For research monitoring and identification of potential pollutants accom-
panying oil shale development, various analytical techniques have been utilized
115
-------
Figure 5-12. X-ray diffraction patterns of long-chain paraffins
In petroleum-derived asphaltenes (Yen, 1971).
116
-------
or proposed. Chemical separation, gas chromatography separation, and infrared
spectrometer analysis are commonly used in environmental laboratories. Gas
chromatography-mass spectrometry (GC/MS) has played a more important role in
detection and identification of organic pollutants (Evans and Arnold, 1975).
The recognition of high-pressure liquid chromatography (HPLC) in the field of
organic analysis has had some impact. The new technique of liquid chromato-
graphy-mass spectrometry system (LC/MS) will broaden the analytical range which
was previously limited by the gas chromatograph. The application of photo-
acoustic spectroscopy owes its potential mainly to its sensitivity and simpli-
city in operation (Krenzer, 1974; Krenzer and Patel, 1971; Krenzer et al.,
1972; Golden and Goto, 1974; Dewey et al., 1973). Organic compounds found in
oil shale products and by-products are categorized by type (nitrogenous, sul-
fur, oxygen, and aromatic hydrocarbon) and are described in the following
subsections.
Selected compounds identified in shale oil include:
• Neutral compounds
N-alkanes
N-alkenes
Cyclonexane
Alkylcyclohexanes
Branched alkanes
• Aromatic compounds
Indene
Alkylindenes
Naphthalene
Alkylanisole
Biphenyl
Acenaphthylene
AT kylnaphthalenes
• Acidic compounds
Alkylphenols
Naphthol
Alkylnaphthols
• Basic compounds
Pyridine
Alkylpyri dines
Qulnoline
Alkylqulnolines
Acridine
Branched alkenes
Alkylfurans
Alkylthiophenes
Pristane
Phytane
Acenaphthene
Fluorene
Alkylfluorenes
Phenanthrene/anthracene
Alkylphenanthrenes
Fluoranthene
Pyrene
Thionaphthols
Thiophenols
Alkylacridines
Indole
Alkylindoles
Carbazole
Alkylcarbazoles
Chrysene
Methylchrysenes
Cholanthrene
Benzof1uoranthenes
Benzopyrenes
Nitrogenous Compounds
In addition to the high nitrogen content of crude shale oil, other
nitroSen-contalning organic compounds are also found in retort water and spent
sha™ (Figure 5- 3). The nitrogen compounds in crude shale oil have been
Identified as pyrid nes, pyrrols, amides, nitriles, and other condensed-ring
heterocycli« ?Poulson, 1975). Retort water contains complex polar fractions
117
-------
OIL SHALE EXTRACTS
(BITUMENS)
PYRIDINES TETRAHYDROQUINOLINES INOOLES QLHNOUNES
ALKOXYPYRROLINES
OH
MALEIMIDES
SHALE OIL
PYRIDINES
INDOLES
QUNOLINES
PYRROLES
ACRIDINES
CARBAZOLES
RETORT WATER
MALEIMIDES
R
I
SUCCINIMIDES
Figure 5-13. Nitrogenous organic compounds found in crude shale
oil, retort water, and spent shale (Yen, 1976).
118
-------
consisting of maleimides, succinimides, and alkoxypyrrolines (Wen et al.,
1976). Nitrogen heterocyclics found in spent shale are acridine, dibenz(a,j)-
acridine, phenanthridine, carbazole, etc. (Schmidt-Collerus et al., 1976).
Nitrogenous compounds play an important role in life processes and are
part of the genetic coding material of nucleic acids. Many heterocyclic bases
can disrupt the genetic coding by displacing normal bases and/or associating;
with the helix. At present, little is known about the type of nitrogenous
compounds from oil shale and crude shale oil. Decora and Dineen (1961) used
detergent as solid phase in gas chromatography to separate basic nitrogen com-
pounds in shale oil. Dineen (1962) identified indoles, pyridines, quinolines,
and tetrahydroquinolines in shale oil.
The uniquely high content of nitrogen in Green River oil shale is the
result of the algal precursor of kerogen. Under high temperature pyrolitic
conditions, the nitrogen functional groups are released from the kerogen
structure together with other organic materials. After thermal processing,
the nitrogenous compounds are distributed among shale oil, retort water, and
spent shale as the oil soluble, water soluble, and insoluble high molecular
weight fraction, respectively.
Yen (1976) has hypothesized that the nitrogen in oil shale contains amide
bridges or heterocyclic components of the melanin type. It has been suggested
that melanoidins could be the nitrogen-containing humic substance that is
incorporated into kerogen under biostratinomy (Enders and Theis, 1938; Young et
al., 1976; Nissenbaum et al., 1975; Manskaya and Drozdova, 1969; Ishiwatari,
1971).
Recently, Wen et al. (1976) positively identified a number of nitrogenous
compounds in retort water by the use of GC-MS, particularly the succimide
(Figure 5-14) and maleiamide (Figure 5-15). These polar compounds may be water
soluble and thus mobile in the hydrosphere. Numerous similar water miscible
nitrogenous compounds have also been associated with oil shale (Tables 5-8 and
5-9).
Sulfur Compounds
The content .of sulfur is generally lower than of nitrogen in oil-shale-
derived products (Figure 5-16). The fraction of sulfate sulfur and pyritic
sulfur in oil shale is commonly small. The main body of sulfur in oil shale
is combined in the organic matter. Organic sulfur is distributed among hetero-
cyclic, aromatic,, and saturated hydrocarbons. The most abundant compounds
have been identified as 2,2'-dithienyl, 2-phenylthiophenes, thionaphthenes,
and thiophenes (Pailer and Gruenhaus, 1973). When thiophenes in shale oil
undergo hydrogenation, normal alkanes or monomethyl alkanes are obtained as
part of the shale oil product.
Desulfurization of organic sulfur compounds has been approached through
chemical, physical, and biological methods (Davis and Yen, 1976). A large
fraction of sulfur compounds react to form hydrogen sulfide and are removed
simply during retorting processes. However, certain thiols and thiophenols
119
-------
(o)
(b)
100
33
l 1
113
++
•r
t•i
100
MASS NUMBER
(m/e)
M+l
75
M+29
Mt4l
70
1 I
100
MASS NUMBER
(m/e)
ISO
Figure 5-14. Mass spectra of succinimide in retort water: (a) electron
impact and (b) chemical ionization (Men et al., 1976).
120
-------
RETORT WATER
* 186
ELECTRON WRACT
50 IOO
MASS NUMBER (m/e)
Figure 5-15. Organic nitrogen compound (maleimides) analysis from
retort water (Wen et al., 1976).
121
-------
TABLE 5-8. NITROGEN COMPOUND DISTRIBUTION IN OIL SHALE BITUMENS*
General types
Specific types
CnH2n-5N
CnH2n-7N
CnH2n-9N
CnH2n-llN
CnH2n-13N
CnH2n-15N
CnH2n-17N
CnH2n-19N
CnH2n-5NO
CnH2n-7NO
CnH2n-9NO
CnH2n-nNO
alkylpyridines
tetrahydroquinolines, dihydropyri dines,
cycloalkylpyridines
indoles, pyridines, etc.
quinolines, isoquinolines
phenylpyridines
carbazoles
acri dines
cycloalkylacridines
oxygenated pyridines
oxygenated tetrahydroquinolines
tetrahydroquinolines or oxygenated indoles
oxygenated quinolines
a Simoneit et al., 1971.
Not found in Colony Mine.
TABLE 5-9. WATER-MISCIBLE POLAR CONSTITUENTS FROM GREEN RIVER OIL SHALE8
General types
Specific types
CnH2n°
CnH2n-10°
CnH2n-2°2
CnH2n-7N
CnH2n-llN
CnH2n-lNO
CnH2n-5N02.
CnH2n-3N02
substituted cyclohexanols, isoprenoid ketones
tetralones, substituted indanones
gamma lactones
substituted tetrahydroquinolines
quinolines
fllkoxypyrrolines
maleimides
sucdnimides
a From Simoneit et al., 1971.
122
-------
2.4
2.0
1.6
>- en
=3 CD
LL. C3
O I—
I— C3
.8
.4-
NITROGEN
SULFUR
PARAHO CRUDE SHALE OIL
10 20 30 40 50
CUMULATIVE (MIDVOLUME) DISTILLATION FRACTION (PERCENT)
Figure 5-16. Total weight of nitrogen and sulfur in Paraho crude shale oil
as a function of the cumulative midvolume distillation fraction.
123
-------
resist heat treatment. Being polar, they can react with basic solutions to
form ionizable salts.
Methylation-hydrogenation of unsubstituted thiophenes at 2-position by
Raney nickel (Blicke and Sheets, 1949) can open thiophenic rings to yield
corresponding alkanes that can be separated by catalytic cracking. Other-
methods, such as distillation (Kinney et al., 1952) have also been practiced
to isolate the sulfur compounds occurring in oil shale. Generally, a combi-
nation of several of the above processes is applied for removal of sulfur
compounds from the shale oil product stream.
Oxygen Compounds
Phenols are potential pollutants in all fossil-fuel-based refining opera-
tions. Petrochemical and other chemical wastewaters contain fairly large
amounts of phenols. According to published work from the Soviet Union,
phenols are the major organic components of oil shale retort water (Greenberg
and Filts, 1975; Filts, 1977).
Different types of phenols-e.g., p-ethylphenol, isomeric cresols, as well
as phenol-in retort water have been analyzed by gas chromatographic methods
(Wen et al., to be published). Figure 5-17 shows some results of this work.
Actually, the precision of gas chromatographic methods is greater than that of
the traditional colorimetric method (Wen, 1976). Some comparable results are
given in Table 5-10. Mass spectroscopy is another method for the identifi-
cation of phenols (Wen et al., to be published) (Figure 5-18).
Higher homologous series of aromatic phenols, as well as sulfur-containing
phenols, have also been detected in shale oil by GC/MS. Oxygen-containing
heterocyclics such as furans have been identified as well. Many fatty acids
(Wen and Yen, to be published) as well as esters (Figure 5-19) are found in
retort water as well as other shale products.
Aromatic Hydrocarbons
A large number of volatile organics appear in by-product water from oil
shale retorting. Various methods of analytical procedures usually result in
different analytical data. For example, the varying analytical results
reported by two laboratories working on the same retort water are shown in
Tables 5-11 and 5-12.
Shale oil contains large number of aromatic hydrocarbons (Table 5-13).
The degree of condensation of the aromatic system increases with the degree
of severity of heat that has been exerted on the products during processing.
For example, the carbonaceous spent shale or coke will experience association
with highly condensed aromatic systems. The polynuclear aromatic systems also
have been observed in oil shale (Figure 5-20). Biphenyl has been identified
in retort water (Figure 5-21). Both azaares (AA) and polycondensed aromatic
hydrocarbons (PAH) in oil-shale-related materials have been studied by
Schmidt-Collerus et al. (1976). Their results are supported by thin-layer
chromatography (TLC), fluorescence spectroscopy, and HPLC (Table 5-14).
124
-------
ui
a*
UJ
a
-------
TABLE 5-10. PHENOLIC COMPOUNDS DETERMINATION IN RETORT WATER
FROM LERC 10-TON RETORT*
Phenolic compound (mg/1)
phenol and
o-cresol
m-cresol and
p-cresol
p-ethylphenol
Gas chromatograph;
Retort Water Ib
lc
2
3
Retort Water IIb
ld
2
3
Colon'metric:6
Retort Water If
lc
2
3
Retort Water II
28.7
37.9
27.2
22.4
27.1
24.0
31.5
40.3
35.5
32.9
42.8
37.7
21.9
37.6*1
169.9
13.8
15.6
12.9
11.7
14.3
11.6
r
2
37
2
.6"
.29
a From Wen, 1976.
" 1 !_. ^ M. u>«* T t M jJ TT -^ uvst £tf+f\m +-t.if* *4 •! ffr\ wistn +• iftt in <~ f^f + \r\r\ 1 /"I 4>/%n
e
f
g
h
LERC retort.
Samples 1,2, and 3 listed here are repeated determinations from
Retort Water I.
Samples 1, 2, and 3 listed here are repeated determinations from
Retort Water II.
These values represent a composite of all phenolic compounds.
Standard deviation for colorimetric method Retort Water I is 80.0.
Data from Bio-Technics Laboratories, Inc., Los Angeles, California.
Data from A6RI Science Laboratories, Inc., Los Angeles, California.
126
-------
RETORT WATER ELECTRON IMPACT
# 23 TOTAL ION GC
DC .
Q J
50 100
MASS NUMBER (m/e)
OH
M parent mass peak
(for phenol * 94)
Figure 5-18. Mass spectrum of phenol in retort water (from Wen et al.,
to be published).
127
-------
METHYLATED RETORT WATER SAMPLE
* 364 METHYL PALMITATE
(a) ELECTRON IMPACT
100 74
UJ
tr J
. L
50
8
L
CJ
7
I
1 129 | 199 270
V "I ;i 1 1 ' 'j' '• ' 'I1' I • 1 J1! 1 ' . i-TTT-
100 150 200 250
MASS NUMBER (m/e)
(b) CHEMICAL IONIZATION
100
•
ji '
a: "
1;
o .
i-
•
i
M** parent mass peak
1 i j J.l.i. , i. ill i.i .. .Ji ,1, . | , ii L | ... .1 *il...
i" i T i i •»iiiiii'| r i i i i i i i •' | i i r i •! i i 'i T | i i 'i1 1 «i \ i"'| >t v i«j" i
50 100 150 200 250
20
Mt29
• • • | tt
3(
io
MASS NUMBER (m/e)
Figure 5-19. Mass spectra for methyl palmitate in retort water:
(a) electron impact and (b) chemical ionization
(Wen and Yen, to be published).
128
-------
TABLE 5-11. VOLATILE ORGANICS IN RETORT WATERS FROM
150-TON RETORT (LERC)a»b
Chromatographic
peak no.
2
3
4
6
7
8
8A
9
10
12
13
15
16
17
17A
18
20
21
22
23
25
26
27
28
29
29A
30
31
Elution
temperature
(°C)
105
105
106
107
108
109
110
111
115
123
128
131
133
134
138
139
148
153
162
164
172
173
174
175
176
177
177
178
1
Compound
acetone
H-pentane
di ethyl ether
t-butanol
nitromethane
methoxybutene- 1 ( tent . )
cyanoethane (tent.)
3-methyl pentane
n-hexane
methyl ethyl ketone (tent.)
methyl cycl opentane
.2-methylbutan-2-ol
benzene
thiophene
cyclohexane
isobutylnitrile
n- heptane
ji-methylpyrazole
2,3-dimethylbutan-2-ol or
rv-propyl £-butyl ether
toluene
1-methyl thiophene
pyridine
phenol
•• ^ethyl benzene
g-xylene
m-xylene
1,4-dimethyl thiophene (tent.)
thiacyclohexane
••••^•••^•••••••••••B
ppb
200±56
10±3
13±9
130±91
16±7
6±5
53±21
13±2
53±5
6±1
6.8±0.5
17±3
14.5±7
8±4
5±3
9±1
10±2
7±2
trace
300±100
9±7
4±1
210.^
11±2
28±6
24±6
9*2
22±6
? From Pellizzari, 1976b.
These analyses and those listed in Table 5-12 were conducted on samples
of the same retort waters.
These levels are low relative to other reported results (e.g., see
Table 5-10).
(continued)
129
-------
TABLE 5-11 (continued)
Chroma tograpMc
peak no.
32
33
34
35
36
37
39
40
41
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
Elution
temperature
(°O
179
181
184
190
192
194
200
201
203
209
212
215
220
225
229
230
230
233
236
237
240
240
240
240
240
240
240
240
240
Compound
o-xylene
methyl thlacyclohexane isomer
methyl pyri dine Isomer (tent.)
n-propyl benzene
methyl ethylbenzene Isomer
methyl ethyl benzene isomer
C3-alkyl benzene
unknown
dimethyl indene isomer (tent.)
Cj-alkyl benzene
o- methyl phenol
2 ,2,6- tri methyl cycl ohexanone
CH-alky1 benzene
acetophenone
C%-alkyl benzene
unknown
p_-me thy 1 phenol
Ct-alkyl benzene
o-ethyl toluene
4 , 5-di hydro xyheptane
m-ethyl phenol
Chalky! benzene
unknown (aromatic)
naphthalene
dimethyl benzof uran
methyl benzocycl opentenone
unknown
B-methylnaphthalene
o-methyl naphtha 1 ene
ppb
7±1
trace
9 ±2
40±15
24±8
23±9
80±22
NQ
2+2
4±1
10±5
9.5+1
3,.2±5
2.7+0.4
4.6+0.6
NQ
4+1 .
8±1
17+3
68±21
12+3
trace
NQ
75±32
3.6±0.3
4.2±0.3
NQ
61+10
52+17
130
-------
TABLE 5-12. ORGANIC COMPOUNDS DETERMINED IN BY-PRODUCT WATERS
FROM OIL SHALE RETORTING (LERC)a.b
Peak
, 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21'
22
23
Compound
acetic acid
propanoic acid
n-butanoic acid
acetamide
n-pentanoic acid
propionamide
n-hexanoic acid
butyrami de
phenol
n-heptanoic acid
o-cresol
m- and p-cresols
n-octanoic acid
2, 6-dimethyl phenol •
o-ethyl phenol
2, 5-dimethyl phenol
3, 5-dimethyl phenol
2, 3-dimethyl phenol
n-nonanoic acid
3, 4-dimethyl phenol
\
n-decanoic acid
a-naphthol
3-naphthol
Concentration (ppm)
600
210
130
230
200
50
250
10
10
260
30
20
230
-
-
-
-
-
100
-
50
-
"
a from Ho et al., 1976.
b Pellizzari (1976b) and Ho et al. (1976) used the same water
with different results (see Table 5-11),
131
-------
TABLE 5-13. COMPOSITION OF AROMATIC HYDROCARBONS IN TOSCO SHALE OIL3
Percent present in
Compound crude shale oil
benzene 0.01
toluene 0.06
ethylbenzene 0.04
p-xylene 0.03
m-xylene 0.14
o-xylene 0.05
isopropylbenzene 0.01
m-propylbenzene 0.01
1-methyl-4-ethylbenzene 0.15
1-methyl-z-ethylbenzene 0.05
1,3,5-trimethylbenzene 0.05
1,2,3-trimethylbenzene 0.05
1-methyl-2-isopropylbenzene 0.38
1-methyl-3-isopropylbenzene 0.38
1-methyl-4-isopropylbenzene 0.38
tert.-butylbenzene 0.14
sec.-butylbenzene 0.14
1so-butylbenzene 0.14
1.3-d1ethylbenzene 0.04
1.4-diethylbenzene 0.16
other Cio-alkyl benzenes 0.12
t
Cu-alkyl benzenes 0.40
naphthalene 0.002
aFrom Denver Research Institute (1976) and Schmidt-Collerus et al
(1976).
132
-------
30
SPECT
6°3% SP2IOO I20H2.I20-290°I6
STARTING MASS 50
1. C3 BENZENE
2. INDENE
3. METHYL1NOENE
4. NAPHTHALENE
5. OIMETHVLINDENE
6. METHYLNAPHTHALENE
7. METHYLNAPHTHALENE
8. C3 ANISOLE
g. 8IPHENYL OR ACENAPHTHYLENE
10. DIMETHYLNAPHTHALENE
11. DIMETHYLNAPHTHALENE
12. BIPHENYLENE
13. DIMETHYLINOOLE
14. DIMETHYLINDOLE AND
DIMETHYLNAPHTHALENES
15. ACENAPHTHENE
16. DIMETHYLINDOLE
17. TRIMETHYLINDOLE
18. TRIMETHYLNAPHTHALENE
18. FLUORINE
20.. TRIMETHYLINDOLE
21. TETRAMETHVLINDOLE
22. TETRAMETHYLINDOLE
23. METHYLFLUORINE AND
PENTAMETHYLINDOLE
24. PENTAMETHYLINDOLE
25. PHENANTHRENE AND
ANTHRACENE
28. Cg-INOOLE
27. METHYLPHENANTHRENES
28. METHYLPHENANTHRENES
29. C16H16
30. OIMETHYLPHENANTHRENE
31. TRIMETHYLPHENANTHRENE
SO KX> ISO 200 290
I
300
390
4OO
I
490
900
990
600
Figure 5-20. Typical gas-liquid chromatogram of oil shale pna fraction (Schmldt-Collerus et al., 1976),
-------
RETORT WATER ELECTRON IMPACT
M/E 154
BIPHENYL
RETORT WATER ELECTRON IMPACT
27%
50 100 150 200 250 300 350 400 450 500
MASS NUMBER (m/e)
Figure 5-21. Mass spectrum of biphenyl from retort water
(Schmidt-Collerus et al., 1976).
134
-------
TABLE 5-14. POLYCONDENSED AROMATIC HYDROCARBONS IDENTIFIED IN BENZENE
EXTRACTS OF CARBONACEOUS SPENT SHALE3«B
01-
Compound
phenanthcene
benz ( a ) anthracene
dibenz(a,h)anthracene
7,12-dimethylbenz(a)anthracene
fluoranthene
3- methyl chol anthrene
pyrene
benzo(a)pyrene
dibenz(c,d,j,k)pyrene
perylene
benzo ( g , h , 1 ) pery 1 ene
TLC, RD, color
o
X
X
X
X
X
X
X
X
X
X
X
Fl uorescence
spectrum
X
X
X
X
X
_
X
X
X
-
HPLC
retention
time
«•
X
_
-
—
-
_
X
X
X
-
Remarks
Fluorescence spectrum
indicates a possible
mixture with another
compound; separation of
these by HPLC in progress
Further confirmation by
HPLC in progress
•-
Separated by HPLC from
BaP
Fluorometric identifi-
cation in progress
From Schmidt-Collerus et al. (1976).
Spent shale from TOSCO process.
-------
TECHNIQUES FOR POLLUTANT CHARACTERIZATION, MEASUREMENT, AND MONITORING
The current and emerging problems in the development of new sources of
energy, such as oil shale, require new approaches to the abatement and control
of pollution. The following paragraphs provide a discussion of aqueous
effluents from oil shale operations. Potential air pollutants are discussed
in Section 7.
The compositions of liquid effluents from oil shale processing are rather
complicated. The effluents include process water from various types of above-
ground and in situ retorting processes, as well as the leachate and seepage
water from the retorted shale and the underground residues from in situ retort-
ing. They have a high pH value and salt content and contain a large fraction
of polar organic components. Characterization of these organic contaminants
and techniques for measuring and monitoring them are discussed in the following
subsections.
Characterization
When dealing with organic compound identification or characterization,
there is always the question of how far or how much to analyze before
stopping. An analysis may be as simple as total organic carbon (TOC), or as
sophisticated as single compound identification by 6C/MS or differential scan-
ning infrared spectrophotometry with computerized pattern recognition. For a
newly developed process such as shale oil production, many of the potential
environmental impacts from full-scale commercial production are still unknown.
In order to operate a monitoring program, more detailed analyses are needed to
identify certain important organic components before nonspecific parameters,
such as TOC, BOD, and COD, can be used for monitoring purposes.
The most common type of organic pollutant analysis is the determination of
some preselected compounds that have previously (often accidentally) been recog-
nized as harmful, e.g., pesticides and carcinogens. But many other compounds
have been neglected simply because their presence and biological activity are
not known. Also, the knowledge of organic substances is biased by using limited
available methods. There is no one method or technique that can completely
address the problem of organic analysis. Each technique has its own limitations
and advantages.
Several analytical techniques are commonly used in wastewater organic
analysis. They are total organic carbon (TOC), biochemical oxygen demand (BOD),
chemical oxygen demand (COD), gas chromatography (GC), thin layer chromato-
graphy (TLC), liquid chromatography (LC), and GC/mass spectrometry (GC/MS).
Total Organic Carbon Analyzer-
A TOC analysis measures the difference between the total carbon (TC) and
total inorganic carbon (TIC). The quick response and easy operation of TOC
analyzers provide a significant advantage over the BOD and COD tests. However,
TOC analysis may be complicated by the very high concentrations of carbonate
carbon. In addition to monitoring the effluents from waste treatment plants,
automatic carbon analyzers can be used to monitor other industrial processes
136
-------
(Hill, 1968). Because of Its nonspecificity, TOC analysis offers a general
tool for monitoring established processes such as municipal and industrial
effluents. More specific analytical instruments may be applied when changes
are detected in TOC levels or when information on specific pollutants is
required.
Gas Chromatography and GC/MS-
Gas Chromatography is currently being used as a universal instrument for
quantitative analysis of pesticides and most smaller organic compounds. The
technique is suitable for compounds with a moderate boiling point and high
thermal stability. This, of course, limits the range of its application. For
diluted liquid effluents, concentration procedures are required before the GC
analysis can be employed.
Adsorption seems to be the most promising sampling technique compared to
others available (e.g., distillation, freeze-drying, liquid-solid adsorption,
headspace analysis, gas-phase stripping, batchwise and continuous liquid-
liquid extraction, etc. [Mieure and Dietrich, 1973; Grob, 1973; Bentreich et
al., 1975; Bowty et al., 1975; Leoni et al., 1975; Osterroht, 1974]). Acti-
vated carbon is preferred as an adsorbent for aqueous solutions and is widely
used. The advantage of activated carbon adsorption is the high degree of
enrichment from a large volume of water. Its disadvantage, however, is that
a completion elution of the adsorbates (chemically modified or activated
carbon) is not always possible. A GC column packing material-Porapak Q-can
also be used as an adsorbent instead of activated carbon.
The large number of contaminants in the water sample creates problems in
the detection of ultratrace concentrations of pollutants and the positive iden-
tification of structurally similar compounds. The application of GC/MS can
solve both the sensitivity and identification problems (Hites and Biemann,
1972; Eichelberger et al., 1974). These two techniques have been applied to
the organic analysis of process water from shale oil production (Wen et al.,
1976).
Liquid Chromatography-
High-pressure liquid Chromatography may become a major separation method
for polar, high-boiling-point, and thermally unstable compounds. This would
be a great advantage for the analysis of wastewater from shale oil production.
Three modes of operation of HPLC can be fully utilized. First, the organics
are concentrated using a Cie reverse-phase liquid partitioning column. Then
the concentrate is separated using a size exclusion column for molecular
weight distribution. The low molecular weight compounds are trapped for GC
analysis, and the remaining compounds go through further separation by liquid-
solid adsorption column (silica gel or alumina), or liquid-liquid partition-
ing column (Cis or NH2). The eluted peaks can be trapped for mass spectro-
metric (MS) analysis, or the liquid chromatograph can be interfaced directly
to the MS equipment for positive identification.
137
-------
Measurement
In recent studies (Kwan et al., 1977), retort water or process water was
first separated into four fractions (basic, acidic, neutral, and residual) by
liquid-liquid extraction with pH adjustment (Figure 5-22). COD distributions
of these fractions are shown in Table 5-15. The gel permeation chromatography
(GPC) separation is shown in Figure 5-23. Low molecular weight compounds have
been found in both the basic and acid fractions. Figures 5-24 and 5-25 corre-
spond to set 1 and set 2 in Table 5-15. The similarity between the neutral
fraction (in Figure 5-24) and the basic fraction (in Figure 5-25) suggests
that the extraction order may affect the COD distribution. The change of pH
during the extraction process might change the original composition of retort
water. This is why a new extraction procedure is now being used that increases
the polarities of the extraction solvents from benzene, ether, chloroform, and
methylene chloride. Liquid-liquid extraction may have some advantage over the
use of macroreticular resins (Leenheer and Huffman, 1976) in that no solid
matrix is employed in the former approach and hence irreversible adsorption is
not a problem. However, costs and ease of analysis are other considerations
in selection of analytical methods for monitoring purposes.
The micro-Porasil (silica gel) column separations with solvent program-
ming are shown in Figures 5-26 to 5-29. Individual compounds that have not
been identified in these spectra can be identified easily by the LC/MS tech-
nique.
Monitoring
For a monitoring technology, the analysis should be able to ascertain
whether the process is working according to some defined expectation. Although
this monitoring concept is simple, it may be rather sophisticated in terms of
analytical requirements. However, one of the main concerns in monitoring is
quick response and easy operation. Nonspecific analytical techniques, such as
COD, BOD, and TOC, are useful to monitor well-established processes like sani-
tary treatment processes. But it would be rather shortsighted to use only the
techniques for newly developed processes such as shale oil production because
the appreciable uncertainties about the environmental impact of these develop-
ments. More detailed information is needed for successful monitoring investi-
gations. Since individual compound identification can be very time-consuming
and expensive, it may be more practical to separate and analyze complex organic
mixtures by chemical or functional classes.
Figure 5-30 shows a functional group separation chromatograph by HPLC
(Kwan et al., 1977). Three groups are identified: hydrocarbons (saturated
and aromatic), organic acids, and polar compounds (nitrogenous, etc.). Their
elution volumes are 4 milliliters, 9-12 milliliters, and 16-20 milliliters
(9.1, 20.4-27.2, and 36.3-45.4, xlO"* gallons) respectively. An injection
volume of 20 microliters was used for this analysis. The retort water sample
only goes through 0.2 micron membrane filter treatment. This technique shows
high potential for satisfying the requirements of monitoring technique for
liquid effluents from shale oil production. The utilization of this tech-
nique is discussed further in Section 7 for monitoring the biological
treatment of retort water.
138
-------
RETORT WATER (pH = 8,6)
1. FILTERED THROUGH 0,2 MICRON FILTER
2, KOH ADDED TO ADJUST PH TO 14,0
3, DlETHYL ETHER EXTRACTION FOR 2 WEEKS
BASIC FRACTION
AQUEOUS LAYER
CO
to
1, H^JJ ADDED TO ADJUST PH TO 7,0
2, DlETHYL ETHER EXTRACTION FOR 2 WEEKS
NEUTRAL FRACTION
AQUEOUS LAYER
1. I^SO^j ADDED TO ADJUST PH TO 1,0
2, DlETHYL ETHER EXTRACTION FOR 2 WEEKS
ACIDIC FRACTION
I
RESIDUAL
Figure 5-22. Liquid-liquid extraction scheme (Kwan et al., 1977).
-------
TABLE 5-15. COD DISTRIBUTION AMONG THE FOUR FRACTIONS (Kwan et al., 1977)
Fraction
Basic
Neutral
Acidic
Residual
Total recovered
Extrac-
tion
order
2
1
3
COD
290
3,970
2,463
2,460
9,183a
Percent
3
36
22
22
83a
Extrac-
tion
order
1
2
3
COD
2,332
1,572
1,980
4,558
10,442
Percent
21
14
18
42
95a
Based on 11,000 mg/1 COD for original retort water.
-------
SAMPLE- CHCIj EXTRACTED RETORT WATER
COLUMN-- /*STYRA6EL 2 X 100 A I X 500 A
SOLVENT' THF
FLOW i I ml/min
CHART' 0.25 cm/min
UV« 0.5 AT 254 nm
Rl • 8X
FRACTION
tu
en
z
C/D
uj
a:
r
o
T
8
T"
16
24
32
40
—T~
48
56
ml
Figure 5-23. Gel permeation chromatography separation
(Kwan and Yen, unpublished data).
141
-------
ACIDIC FRACTION
16 24
ML
BASIC FRACTION
24
COLUMN: CO.RASIL
SOLVENT: IOO 7. HEXANE TO
PROGRAM: CURVE »6 TIME
CHART: o.s CM/ML
FLOW RATE: 2 ML/MIN.
NEUTRAL
FRACTION
24
EXTRACT
RESIDUAL
i I
8 16
ML
1007. THF
10 MIN.
I
24
Figure 5-24.
Chromatographic separation of set 1 extractions shown
in Table 5-15 (ordinates are UV response).
142
-------
NEUTRAL
FRACTION
ACIDIC FRACTION
ML
I
16
T
24
BASIC
FRACTION
T
8
ML
1
16
I
24
24
COLUMN: CORASIL
SOLVENT; 100% HEXANE TO
PROGRAM: CURVE «6 TIME
CHART: 0,5 CM /ML
FLOW RATE: z ML/ MIN
100% THF
10 MIN.
Figure 5-25. Chromatographic separation of set 2 extractions shown
in Table 5-15 (ordinates are UV response).
143
-------
o
D.
to
Lul
ee.
12
16
20
ml
COLUMN^ /iPORASIL
SOLVENT: IOO% HEXANE
PROGRAM-- CURVE * 6
FLOW' 0.5 ml/min
CHART« 0.5 cm/win
UV. •• 0.5 AT 254nm
TO 100% THF
TIME> 20 min
Figure 5-26. Sample of retort water (pH 8.8), benzene extracted
(Kwan and Yen, unpublished data).
144
-------
CO
o
CL.
CO
12
16
20
ml
Figure 5-27. Sample of retort water (pH 8.8), ether extracted
(Kwan and Yen, unpublished data). Analysis
conditions are shown in Figure 5-26.
145
-------
to
o
o_
CO
16
20
ml
Figure 5-28. Sample of retort water (pH 8.8), chloroform extracted
(Kwan and Yen, unpublished data). Analysis conditions
are shown in Figure 5-26).
146
-------
CO
I
CO
16
ml
20
Figure 5-29.
Sample of retort water (pH 8.8), methylene chloride
extracted (Kwan and Yen, unpublished data). Analysis
conditions are shown in Figure 5-26.
147
-------
oo
o
o.
CO
UJ
oc.
I
SAMPLE'RETORT WATER (FILTERED
COLUMN://. BONDAPAK NH2
SOLVENT: CHjCN—*-H2O:CH3CN:THF
(2:2:1)
PROGRAM: CURVE *4 TIME SOMIM
CHART: O.S CM/MIN
FLOW! I nl/MIN
U.V.: O.S AT 254 nm
r
0
I
8
I
12
i
16
I
20
I
24
I
28
Figure 5-30. HPLC functional group separation spectrum for
hydrocarbons, organic acids, and polar compounds,
148
-------
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Yen, T.F., "Structural Aspects of Organic Components In Oil Shales," Oil
Shale (T.F. Yen, ed), Elsevier, p 127, 1976.
Yen, T.F., "Long-Chain Alkyl Substituents in Native Asphaltic Molecules,"
Nature Physical Science. Vol 233, No. 37, p 36, 1971.
Yen, T.F., and John Findley, Quarterly Report. November, 1975, ERDA E(29-3619),
p 6, 1975.
Yen, T.F., C.S. Wen, J.T. Kwan, and E. Chow, "The Role of Asphaltenes in
Shale Oil," American Chemical Society Preprints. Division of Fuel
Chemistry, Vol 22, No. 3, p 118, 1977.
Young, O.K., S.K. Sprang, and T.F. Yen, "Preliminary Investigation on the
Processes of the Organic Compounds in Sediments-Melanoidin Formation,"
Chemistry of Marine Sediment (T.F. Yen, ed), Ann Arbor Science
Publishers, Chapter 5, 1976.
154
-------
SECTION 6
INORGANIC CONTAMINANTS
Oil shale operations involve mining and processing of huge quantities of
material. In general, a daily production of 16,000 m3 (100,000 bbl) of shale
oil by underground mining with surface retorting will utilize about 45 million
tonnes (50 million tons) of raw oil shale a year. The annual water require-
ment will total 19.2 million m3 (15,600 acre-feet) with a permanent land
requirement of 242 hectares (600 acres). Each year, 61 hectares (150 acres)
of land would be disturbed by the disposal of spent shale (U.S. Energy Research
and Development Administration, 1976a). In addition to these solid wastes,
tons of sulfur dioxide (S02), particulates, oxides of nitrogen (NOX), and hy-
drocarbons (HC) would be generated as potential atmospheric pollutants (Table
6-1). Potential impacts of the developing oil shale industry include effects
on soils, water resources (both surface and subsurface), and air quality. Oil
Shale development may pose serious pollution impacts on the environment; some
of them are significant locally and others affect wider regions. Oil shales are
composed of tightly-bound organics (13.8 percent) and inorganics (86.2 percent)
(Table 6-2). In this section, potential inorganic contaminants are discussed.
TABLE 6-1. EMISSION OF AIR POLLUTANTS FROM TOSCO II OIL SHALE .
RETORTING AND UPGRADING (PER 100,000 BBL OF PRODUCT)3'0
Emission constituent Amount in tonnes (tons)
S02
Particulates
' N0x
Hydrocarbons
aFrom U.S. Energy
(1976a).
36.3
9.1
65.3
6.9
-..,-:. ^40 >;
.•..^•••'.•'i(10 '-R
(72 )
( 7.6)
Research and Development Administration r;
•* LA A f*****f*f*4*s^*4 4-jr* u^iitts t.iA ftr\ i if
^4r%nr^iny4^ iftfv ^m
retorting and emission control technology.
155
-------
TABLE 6-2. AVERAGE MINERAL COMPOSITION OF GREEN RIVER OIL SHALE3
Mineral matter Weight percent
Dolomite and calcite, 43.1
CaMg(C03)2, CaC03
Feldspars, KAlSi308 16.4
Clays, KAUSi7A1020(OHK 12.9
Quartz, Si02 8.6
Anal cite, NaALS106H20 4.3
Pyrite, FeS2 0.86
Approximate total inorganic matter 86.2
aFrom Hendrickson (1975).
Mining, retorting, upgrading processes, and vehicular transportation all
produce possible inorganic contaminants. The most direct and effective manner
of addressing the environmental impacts is through both identification and
quantification of the emissions, effluents, and solid wastes associated with
each process. Sources of pollutants are discussed in the following sub-
sections.
WATER POLLUTION
Contamination of both surface and underground waters is a potential hazard
associated with surface mining. In general, physical disturbance as a result
of mining may cause deeper saline groundwater to contaminate upper, good qual-
ity waters. Groundwater percolating into the mined area from a highly saline-
zone may necessitate dewatering of the mine, producing large quantities of
saline wastewater for disposal. Leaching from raw shale storage piles, as well
as overburden, may also contaminate surface water and groundwater. Explosions
and overburden handling will result in sediments and mineral matter that are
easily picked up in surface runoff.
Underground and In Situ Mining
Much of the groundwater in the oil shale region is saline as a result of
the leaching of soluble salts present in various geologic strata. Groundwater
in the mining zone interferes with both mining and in situ processing, and,
thus, dewatering may be required in some areas. Relatively good quality
groundwater lying above the shale layer can be contaminated by the saline
groundwater during mining operations if connection with saline strata occurs.
Subsidence caused by mining operations could change local surface water drain-
age patterns and degrade water quality.
Groundwater or surface water contamination might be caused by materials
156
-------
used in well drilling, including drilling fluids containing crude or refined
oil, organic acids, alkali, and asphalt, and muds with high salt content (20
percent sodium chloride and high pH of 12), corrosion inhibitors, and other
compounds added to well systems (Weaver, 1974). Improperly cased wells or
well blowouts would result in interformational leakage of native brines (high
in carbonates, sulfates, calcium, and magnesium), contaminated retort water,
retort gas, and shale oil.
Process Waters
Retort Water-
Durinq surface retorting, water is produced as well as oil and gas. Up to
38 liters (10 gallons) of retort water per ton of shale may be produced, with
an average range from 7.6 to 18.9 liters (2 to 5 gallons) per ton (Cook, 1971).
Retort waters contain large amounts of dissolved minerals. The inorganic com-
ponents are mostly ammonium, sodium, magnesium, calcium, bicarbonate, carbo-
nate, sulfate, and chloride ions. The concentration of inorganics depends on
the characteristics of the oil shale and the retorting process. Major compo-
nents in different process retort waiers are shown in Table 6-3 (Hendrickson,
1975). Some trace metals identified in retort water are shown in Figure 6-1
(Wen, 1976).
TABLE 6-3. COMPONENTS IN DIFFERENT OIL SHALE PROCESS RETORT WATERS9
(Concentrations in gm/1)
Components
Ammonia (NH3)
Carbonate (C03)
Chloride
Sodium
Sulfate (SOJ
Sulfur, nonsulfate
Water lc
12.4
14.4
5.4
1.0
3.1
1.9
Water 2d
4.8
19.2
13.3
3.1
4.5
0.3
Water 3e
2.4
20.8
1.8
0.5
1.2
1.0
aFrom Hendrickson (1975).
bThe major components are similar in retort waters from different
retort processes.
cWater 1 is from gas combustion retorting.
dWater 2 is from in situ retorting.
6Water 3 is from 150-ton batch retorting.
157
-------
CJ1
00
UJ
1
UJ
CC
Cu
EMISSION ENERGY (KeV)
Figure 6-1. Deposited metals on cathode from electrolytical treatment of oil shale retort water
and determined by X-ray fluorescence method (Wen, 1976).
-------
In situ processing demonstrations have reportedly had greater rates of
retort water production than surface retorting processes. In situ retorting
produces approximately one unit volume of retort water per unit volume of oil
produced (McCarthy and Cha, 1975). This wastewater stream is expected to con-
tain the same types of inorganic contaminants as aboveground retorting.
Anticipated inorganic contents of in situ retort water are shown in Tables
6-4 and 6-5 (Jackson et al., 1975). Similar levels of potential pollutants
may be expected from both in situ and ex situ retorting.
TABLE 6-4. WATER EXTRACTED FROM EXPERIMENTAL IN SITU RETORT
TEST AREA NEAR ROCK SPRINGS (ppm)a
Constituent
Calcium
Magnesium
Sodium
Potassium
Carbonate (C03)
Bicarbonate (HC03)
Sulfate (SOJ
Chloride
Nitrate (N03)
Fl uori de
Dissolved solids
Boron
Silica (Si02)
pH
Site 9
production
wellsb
13.8
26.0
5,947.8
14.8
1,621.1
7,791.1
1,327.8
2,156.7
2.3
33.0
15,578.9
45.3
16.8
8.7
Site 9
observation
we! 1 sc
5.9
11.1
5,286.6
12.3
3,499.0
3,219.2
550.4
2,024.0
1.4
16.0
13,303.0
46.0
12.4
9.6
aFrom Jackson et al. (1975).
bAverage of analyses from 9 wells.
cAverage of analysis from 10 wells.
159
-------
TABLE 6-5. TRACE ELEMENTS IN WATER EXTRACTED FROM EXPERIMENTAL
IN SITU RETORT TEST AREA (ppm)a
Element
Uranium
Lead
Mercury
Cadmium
Molybdenum
Stronti urn
Bromine
Selenium
Arsenic
Zinc
Copper
Nickel
Cobalt
Manganese
Chromium
Vanadium
Al umi num
Fluorine
Boron
Site 9
production
wellsb
1.082
0.0356
0.00152
0.0035
4.1
0.56
0.48
0.007
0.1487
0.774
0.087
0.329
0.0146
0.0503
0.0149
0.0779
4.779
33.25
30.17
Site 9
observation
we! 1 sc
0.064
0.1924
0.00086
0.00175
1.0411
0.3544
5.7598
0.00475
0.0189
0.0904
0.0417
0.11125
0.0155
0.1562
0.0075
0.05175
2.1228
31.99
41.03
From Jackson et al. (1975).
Average of analyses from 9 wells.
cAverage of analyses from 10 wells,
Recycle-Gas Condensate-
Recycle-gas condensate water contains inorganic contaminants similar to
those contained in retort water (Table 6-6). Trace metals (lead, mercury,
molybdenum, selenium, arsenic, zinc, manganese, chromium, and vanadium) are
also present in both retort water and condensate water. Trace metal contami-
nants are discussed in more detail in Section 7.
160
-------
TABLE 6-6. INORGANIC COMPONENTS OF RECYCLE-GAS CONDENSATE (ppm){
Components
Ammonia (NH3)
Ammonium (NHi»+)
Bi carbonates (HC03)
Calcium
Fluoride
Magnesium
Nitrate (N03)
Potassium
Sodium
Sulfate (SOO
Sulfide (S)
Total solids
Suspended solids
pH
Total alkalinity
Direct heating
mode
14,060
5,652
31 ,265
60.7
0.35
<0.1
118
0.08
0.2
113.6
0.1
22,000
200
9.8
68,550
Indirect heating
mode
16,800
13,540
6,280
39.2
0.10
<0.1
1.0
0.18
0.29
1.65
390
429
-
9.5
12,900
aFrom Cotter et al. (1977).
These data are for Paraho process. Data for the TOSCO II process (an
indirect heatinq process) would be similar to the indirect mode of the
Paraho process (see Section 3).
Retort and condensate waters also contain high concentrations of ammonia
and some hydrogen sulfide, both volatile and toxic substances. Other sulfur
forms such as thiosulfite and sulfate are also present. Ammonia stripping and
sulfur recovery systems will be designed to handle these wastes (Section 3).
Other Wastewater-
Several other kinds of liquid wastes are associated with shale oil recovery
and processing. These include cooling-tower blowdown, boiler water blowdowns
(with high salt and trace metal levels); mine dewatering wastes (saline water
containing mining contaminants); and sour water from refining operations (oily
cooling waters and waters with appreciable ammonia and hydrogen sulfide con-
tent). Data on these waste streams are limited.
161
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Processed Shale
Spent shale is moisturized with process water (an amalgam of mine, retort,
condensate, sour, and cooling waters) and transported to the disposal site.
Runoff and leachate from the spent shale disposal pile, resulting from rain or
melting snow, is expected to be highly saline and alkaline because of the
characteristics of spent shale and process waters.
In in situ operations, spent shale and retort waters are mixed together
in the retorting zone. The mechanism of their interaction is not clear.
Retort water may leach out inorganics from retort shale. Conversely, spent
shale may absorb inorganics from retort water. In addition, soluble retorting
products may be leached by infiltrating groundwaters. Thus, inorganic con-
taminants produced during retorting (salts, alkaline materials, and trace
metals) may be mobilized. The contact time between spent shale and retort
waters may be shorter in surface retorting than in situ processes because of
the longer in situ cooling (and condensation) period. Thus, in surface retorts,
their interaction would be lessened.
AIR POLLUTION
Mining
Emissions of particulate matter and gases result from blasting to loosen
overburden and shale. The use of ammonium nitrate-fuel oil (ANFO) mixture in
explosives produces carbon monoxide, nitrogen oxides, ammonia, and particulates.
The use of fuel oils in mining equipment produces carbon monoxide, sulfur
dioxide, and nitrogen oxides, as well as particulate matter. Preparation of
oil shale for retorting, including crushing and screening, also generates
particulate matter (Figure 6-2; Kirkpatrick, 1974).
Underground and in situ mining reduces the dust and particulate problems
associated with surface mining. However, gaseous emissions still occur as with
surface mining. Carbon monoxide, sulfur dioxide, nitrous oxides, and particu-
lates are created by using fuel oils in mining and transport equipment. The
major source of dust is wind erosion of access roads and graded mine sites.
Fracture interconnection with open surface joints and underlying in situ
retorts may result in gaseous emissions. For underground mining safety, gases
produced during blasting will be removed through ventilation systems to the'
atmosphere. Thus, nitrogen oxides, carbon monoxide, ammonia, and other gases
may be released.
Process Gases
The internal combustion, or directly heated process, yields gases that
are diluted with nitrogen and oxygen from air injection. The gas produced from
the internal combustion process has low heating value, but it may be utilized
as fuel gas for the generation of power and process steam. The gas from an
indirectly heated retorting process, such as TOSCO II or Paraho IH mode, is
composed only of undiluted constituents from the oil shale itself and is less
limited for further utilization (i.e., it has a higher heat content) (U.S.
Energy Research and Development Administration, 1976b). The properties of the
162
-------
PART.
PART
FUGITIVE DUST
t
MINE
T
VEHICULAR
TO Am/*
TRAFFIC
RAW
SHALE.
fc
PART.
1
CRUSHING
PART.
NO?
HC
CO
NO;
HC
CO
i
RETORT
NO:
88
t
•
GAS
GAS AND
OIL
HC
T
RECOVERY
>$% SPENT SHALE
^ff %• K ^ \ V
\
PART.
ur
no
GAS a OIL
1
STEAM AND/ OR FLUE
GAS
FOR PROCESS HEATING
i
OIL
' STORAGE
» SULFUR S AM^
TO MARKET
BOILERS
PART
S02
N0»
HC
CO
IONIA
Figure 6-2. Emissions from oil shale operations (from Kirkpatrick, 1974).
-------
retorting gases from the Paraho operation and the TOSCO operation are shown
in Tables 6-7 (Jones, 1974) and 6-8 (U.S. Department of the Interior, 1973).
TABLE 6-7. PARAHO RETORTING GAS PROPERTIES (PERCENTAGE, VOLUME, DRY BASIS)*
Constituent
H2
N2
02
CO
CH,,b
C02
H S
2
NH3
Direct heating mode
2.5
65.7
0.
2.5
2.2
24.2
2,660 ppm
2,490 ppm
Indirect heating mode
24.8
0.7
0.
2.6
28.7
15.1
3.5
1.2
aFrom Jones (1974).
bOther hydrocarbons less than 1 percent (C2Hi, [0.7 percent], C2H6
[0.6 percent], C3 [0.7 percent], Cu [0.4 percent]).
TABLE 6-8. PROPERTIES OF UNTREATED RETORT GASES FROM DIFFERENT
RETORTING PROCESSES3
Composition,
Vo. Pet.
N
C02
CO
H2S
HC
Gross heating value:
KJ/m3
Btu/scf
Yield:
scf/bbl oil
m3/8,000 m3 (50,000 bbl ]
oil
Para ho
(Internal Combustion)
60.1
4.7
29.7
0.1
3.2
3,071
83
20,560
>
29.1xl06
TOSCO
(Indirectly heated)
_
4.0
23.6
4.7
42.9
28,675
775
923
1.3xl06
aFrom U.S. Department of the Interior (1973).
164
-------
Carbon monoxide, nitrogen oxides, sulfur dioxide, and particulates are the
dominant emissions from the generation and use of recycle gas. The major
source of carbon monoxide, nitrogen oxides, and sulfur dioxide is fuel combus-
tion in process heaters.
Nitrogen oxides (NOX) are formed in almost every step of the oil shale
process. Retorting is the major source, since nitrogen is chemically bound
with organic components of the kerogen matrix. This organic bounded nitrogen
is released as nitrogen oxides and ammonia during the retorting process.
Combustion of product gas and shale oil also generates nitrogen oxides. Gas
concentrations from the TOSCO process are shown in Table 6-9 (U.S. House of
Representatives Hearings, 1974). TOSCO II and other indirect heating processes
produce much lower emissions of sulfur dioxide and nitrous oxides than does the
Paraho direct heating mode. This is because air is not used in the indirect
heated processes. However, the indirect heated processes produce higher
carbon monoxide emissions as a result of incomplete combustion. Particulate
emissions are comparable for both (Paraho) indirect and direct heating pro-
cesses. Emission sources are identified in Table 6-10 (TRW and Denver
Research Institute, 1976).
TABLE 6-9. MAXIMUM EMISSION RATE IN kg/hr (Ib/hr), TOSCO PROCESS3
Source S02b
Raw shale crushing low
N0¥c Particulates CO
A
low 91 (200) low
and handling
Retorting 363 (800) 2268 (5000) 273 (600) 18 (40)
Gas and oil 91 (200) 363 (800) 7 (15) 6 (14)
recovery
Boilers and 50 (110) 317 (700) 7 (15) 2 (5)
superheater
Total 504 (1110) 2948 (6500) 378 (830) 26 (59)
aFrom U.S. House of Representatives Hearings (1974).
bValues given are maximum rates; reported average rate is
approximately 130 kg/hr (286 Ib/hr).
cValues given are maximum rates; reported average rate is
approximately 700 kg/hr (1,540 Ib/hr).
165
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TABLE 6-10. SOURCES AND NATURE OF ATMOSPHERIC EMISSIONS FROM
OIL SHALE EXTRACTION AND PROCESSING*
Process and
activity
Potential criteria
pollutants
Potential noncriteria
pollutants
Blasting and
explosion
Mine equipment
(fuel use)
Preparation of
retort feed
Retorti ng
Spent shale
discharge
Refining
Tail gas
cleaning
sulfur recovery
Solid waste
disposal
PM, CO, NO. HC
J\
PM, CO, NO . S0?, HC
A
PM
PM, CO, NOX, SO2, HC
PM, HC
PM, CO, NOX, S02, HC
SO 2
PM, CO, NO . SO2, HC
Hg, Pb salts, silica
silica
silica
trace element and trace
organics
H2S, NH 3, volatile compounds
CS2, COS
trace organics
trace metals (Ni, Co, Fe, Mo)
From TRW and Denver Research Institute (1976).
Processed Shale
Fugitive dust emissions from spent shale piles may create air quality
problems. Particulate emissions from fugitive cEpt and spent shale handling
and disposal contain certain toxic trace metals. Spent shale may release
gases, ammonia, hydrogen sulfide, and other volatile compounds during mois-
turizing and subsequent cooling. Carbon monoxide, nitrogen oxides, and sul-
fur dioxide are generated during spent shale handling processes. Under-
ground disposal would result in less air pollution than surface disposal.
SOLID WASTE
Mining \
i
As discussed in Section 2, solids handling (overburden, raw shale, and
processed shale) requirements vary widely with the mining approach used.
166
-------
Strip mining and open-pit methods have the largest materials handling need.
The requirement for moving large volumes of oil shale and overburden is
reduced in underground and in situ mining. Only oil shale strata are affect-
ed with about 75 percent removal for room-and-pillar mining and perhaps 20
percent for modified in situ. True in situ, of course, requires no mining.
Processed Shale
Spent shale is the major solid waste from mining and retorting processes.
Each type of retorting process produces a specific spent-shale product. The
characteristics of the retort feed also affect the properties of spent shale.
For example, the feed shale contains soluble sodium minerals. Several soluble
compounds may be found in the spent shale because sodium compounds may contrib-
ute to the fusion of spent-shale particles by lowering the softening, or melt-
ing, temperatures of certain inorganic mineral constituents (Hendrickson, 1975).
The disposal of spent shale is potentially the most serious source of
environmental impact of a surface retort oil shale facility. Spent shale is
approximately 85 percent of the original resource mass. During retorting, the
volume of shale expands by 10 to 30 percent. The high content of water-soluble
minerals in spent shale creates a great potential for environmental contamina-
tion from leaching. Trace metals from processed shale also contribute to the
hazard potential of shale oil recovery.
Spent shale from retorting is highly saline and alkaline. The chemical
properties of spent shale are shown in Tables 6-11 and 6-12 (Hendrickson, 1975).
Alkaline minerals present in the inorganic portion of oil shale are transform-
ed during retorting into expanded alkaline-oxides, accounting for some of the
increase in volume of spent shale over that of the raw shale material. The
rest is a function of crushing.
There are two options for spent-shale disposal— namely, surface and under-
ground. Since the volume of processed shale exceeds that of the original shale,
some surface disposal is required even where the underground disposal option
is utilized.
HEALTH AND ENVIRONMENTAL PROBLEMS
Oil shale operations will create some potential for direct and indirect
adverse effects on human health. The major categories of inorganic pollutants
and their hazardous effects are discussed in the following subsections.
Emission Gases and Particulates
Regulations addressing the Clean Air Act provide primary and secondary
standards for air quality. Primary standards are intended to protect the
public health. These standards are set at levels below which no deteriorative
health effects are expected to be observed. Secondary standards are intended
to protect the public welfare from any known or anticipated effects of a pollu-
tant. Secondary standards deal with nonhealth-related impacts.
167
-------
TABLE 6-11. CONSTITUENTS OF SPENT SHALE8)b
Constituents
Si02
Fe203
A1203
CaO
MgO
S03
Na20
K20
Average values
(average percent)
43.8
4.6
12.1
22.1
9.3
2.2
3.4
2.4
aFrom Hendrickson (1975).
Data are from Fischer assay spent shales
obtained from Colorado Green River Forma-
tion oil shale.
TABLE 6-12. LEACHABLE INORGANIC IONS FROM SPENT SHALE (kg/tonne)
OF DIFFERENT RETORTING PROCESSES3
Ion
K+
Na+
Ca++
Mg"1"1"
HCO;
CL"
S0*=
Total :
- kg/ tonne
- Ib/ton
TOSCO II
0.32
1.65
1.15
0.27
0.20
0.08
7.3
10.7
22.0
USBM
0.72
2.25
0.42
0.04
0.38
0.13
6.0
9.94
19.9
Union A
6.25
21.0
3.27
0.91
0.28
0.33
62.3
94.34
189.2
Trom Ward et al. (1971).
168
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In addressing the Clean Air Act, the U.S. Environmental Protection Agency
has promulgated regulations for prevention of significant deterioration (PSD)
of air quality in areas already cleaner than Federal secondary standards
require. PSD permits are a method of government assurance that given projects
will not result in detrimental effects on ambient air quality.
Sulfur dioxide, nitrogen oxides, carbon monoxide, and particulates are
discussed in the following paragraphs. Projected levels listed are from
development plans by Colony Development Operation and the White River Shale
Project. A Gaussian air-dispersion model developed by Battelle Pacific North-
west Laboratories (1975) was used for the Colony projections. Developers of
Tracts U-a and U-b (White River Shale Project, 1976) utilized EPA's PTMTP model
for short-term (less than 24 hours) predictions and EPA's terrain model for
long-term predictions.
Sulfur Dioxide
t
Sulfur dioxide (S02) is a pungent respiratory irritant. Below about 25
ppm, it affects only the upper respiratory system. It becomes an irritant of
the lower respiratory system when S02 is absorbed onto the surface of aerosols
and can thereby be carried deep into the lungs. In the atmosphere, sulfur
dioxide can react with water vapor and be oxidized to form sulfuric acid mists.
Thus, sulfur dioxide may cause health problems including eye irritation, acute
and chronic respiratory stress, and possibly pulmonary disease. Sulfur dioxide
also causes plant leaf damage and corrosive damage to materials such as metals.
The predicted highest annual mean concentration for the Colony oil shale opera-
tion is 3.5 ygm/m3, which is about 4.3 percent of the primary Federal standard
(Colony Development Operation, 1975). The maximum average expected for Tracts
U-a and U-b is 2.66 ygm/m3 (White River Shale Project, 1976).
Nitrogen Oxides -
Two important oxides of nitrogen found in air pollution are nitric oxide
(NO) and nitrogen dioxide (N02). The term nitrogen oxides (NOX ) represents
a composite atmospheric concentration of nitrogen oxides and nitrogen dioxide.
Nitrogen oxides are poisonous and acutely irritating gases. They are also
associated with chronic pulmonary disease. Nitrogen dioxide can result in
restrictions in respiratory passages and puTmonary edema (Ross, 1972). Nitrous
oxides can react with organic compounds to form secondary nitrous oxide pollu-
tants including ozone (03) and aerosol. The combination of these primary and
secondary pollutants is known as photochemical smog. Plant damage, material
damage, coloration of the atmosphere, eye irritation, and toxic effects are
all possible effects of ozone and nitrous oxides (Williamson, 1973). The pri-
mary and secondary Federal standards for nitrous oxides are 100 ugm/m3 (0.05
ppm). The predicted maximum annual mean concentration is 15.85 ygm/m3, or 15
percent of the Federal standards (Colony Development Operation, 1975). The
maximum mean expected for the U-a and U-b project is 14.1 ygm/m3 (White River
Shale Project, 1976).
169
-------
Carbon Monoxide-
Carbon monoxide (CO) is a toxic gas formed from incomplete combustion.
In the lungs it can combine with the hemoglobin in the bloodstream to form
carboxyhemoglobin (CON^). As a result, the ability of the hemoglobin to
carry oxygen to body tissues is reduced. Thus, the most critical pathological
effect of carbon monoxide is the elimination of the red blood cell function.
Federal primary and secondary standards for CO are 40 mg/m3 (35 ppm) for 1
hour and 10 mg/m3 (9 ppm) for 8 hours, respectively. The estimated annual
mean concentration ranges from 0.1 to 0.8 ygm/m3 (Colony Development Opera-
tion, 1975).
Particulates-
Particulates are composed of such constituents as ions, molecular clus-
ters (e.g., unburned hydrocarbon), dust, soot, and raindrops. The particle
size and chemical composition affect optical and toxicological properties
considerably. Three size ranges are used for the classification and discus-
sion of particulates: smaller than 0.1 micron, 0.1 to 1.0 micron, and larger
than 1.0 micron.
Particules of the size of 0.5 micron are retained by the nose while those
smaller than 0.5 micron are easily transported to the pharynx or the lungs.
Various respiratory and pulmonary problems may be caused by these particulates.
Smaller particles are likely to be deposited in the lungs and pose the greatest
hazard to human health. Soot is an example of the small particulates that can
be retained in the lungs. Aqueous droplets may dissolve gaseous constituents
and form acids, resulting in so-called "acid rain."
The Federal primary standard for particulate matter is 75 gm/m3 (as an
annual mean). The secondary standard is 60 gm/m3. The estimated annual mean
concentration for particulates ranges from 1 to 10 ygm/m3 (Colony Development
Operation, 1975), while for U-a and U-b operations it is 39.3 ygm/m3 (White
River Shale Project, 1976). \
Trace Metals
Another major source of inorganic pollution resulting in health and envi-
ronmental problems is trace metals. The Green River oil shale contains many
trace elements. The major portion of most trace metals remains with the spent
shale although portions of some are found in process water, shale oil, and
retort gases. Metals, including nickel, cobalt, molybdenum, zinc, and chro-
mium, are used as catalysts in upgrading processes. Spent shale, wastewater,
and particulate emissions contain components of spent shale catalysts.
Arsenic-
Arsenic (As) poisoning is commonly the result of the cumulative effect on
the general system. It causes dermatitis and bronchitis. It is carcinogenic
to mouth, esophagus, larynx, and bladder tissues. It inhibits ATP synthesis
as well as thiodependent enzymes (i.e., enzymes that utilize or convert sulfur
compounds). The median lethal dose (LD50) from rat experiments is 0.07gmAs/kg
170
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(Dulka and Risby, 1976). Most arsenic associated with oil shale processing is
found in spent shale, retort water, and raw shale oil.
Lead- :
Lead (Pb) is toxic and can accumulate in bones and soft tissues. It
causes reduction of brain functioning, interferes with the formation of amino
acids and enzymes, and can cause damage to the kidneys. The LD50 for rats
consuming lead is 0.15 gm/kg (Dulka and Risby, 1976). Spent shale is the major
source of this contaminant.
Vanadium-
Vanadium (V) poisoning in man results from impairment to tissue metabolism.
It inhibits activities of enzymes and adversely affects tissue oxidation. Va-
nadium also inhibits many other metabolic processes in the human body. The
toxicity, LDso (rabbits), is 0.2 gm/kg (Dulka and Risby, 1976). Most vanadium
associated with oil shale processing is found in spent shale and shale oil.
Selenium-
Selenium (Se) can cause irritation of nose, throat, and respiratory tract
tissues. It may also cause liver cancer, pneumonia, degeneration of liver and
kidney tissue, and general gastrointestinal disturbance. The LD50 for selenium
(on rats) is 0.003 gm/kg (Dulka and Risby, 1976). The selenium of oil shale
and waste products is relatively low in comparison to other trace elements.
Zinc-
In comparison with other trace metals such as arsenic, lead, and vanadium,
zinc (Zn) is relatively nontoxic. Zinc is noncumulative since the proportion
absorbed is inversely related to the amount ingested (Prasad and Oberleas,
1976). However, large quantities of zinc will cause malaise, dizziness, vomit-
ing, dehydration, and loss of muscular coordination. The toxicity of zinc
(LD50 for rabbits) is 2 gm/kg (Dulka and Risby, 1976). Most zinc is found in
the processed shale and coke, which contain spent catalytic materials.
Chromium-
Chromium (Cr) in the hexavalent state is much more toxic than trivalent
chromium. It is considered to be a potential carcinogen (Van Hook and
Schultz, 1976). Cancer of the respiratory tract can be caused by chromium.
It causes perforation of nasal septum, congestion, hyperemia, bronchitis, and
dermatitis. The toxicity of chromium (LD50 for rats) is 0.18 gm/kg (Dulka and
Risby, 1976). Processed shale and coke contain most of the chromium associ-
ated with oil shale processing.
Nickel-
Nickel (Ni) can cause respiratory disorders and cancer of the respira-
tory system It acts to reduce the activity of cytochrome oxidase, isocitrate
dehydrogenase of the liver, and maleic dehydrogenase of the kidneys. The
171
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toxicity (LDso for dogs) is 0.8 gm/kg. Most of the nickel is to be found in
the spent shale.
Beryllium-
Beryllium (Be) is toxic and causes chemical pneumonitis. Beryllium also
acts as a potential carcinogen in lungs and bones. It will do damage to skin
and mucous membrances and inhibit metabolic activities. The toxicity (LD50
for mice) is 0.5 mg/kg (Dulka and Risby, 1976). Spent shale contains most of
the beryllium associated with oil shale processing.
Mercury—
JL^,
Mercury (Hg) is highly toxic as Hg , which is formed in tissues from
oxidation of Hg+ salts. Mercury can accumulate in brain, lung, heart, kidney,
liver, and muscle tissues. Complexation with HS~ groups may occur. It can
inhibit some amino reactions and damage the central nervous system. The
toxicity (LD50 for mice) is 0.027 gm/kg (Dulka and Risby, 1976). Most of the
mercury in oil shale probably either will remain in the processed shale or
will be in the gas streams of retorting.
Other Trace Elements-
Some other toxic trace elements including cobalt, molybdenum, manganese,
and strontium are also found in processed shale in appreciable quantities.
Toxic metals found in trace amounts in spent shale and retort water are shown
in Table 6-13 (University of Southern California, 1976-77). Metals are the
most insidious pollutants because of their nonbiodegradable and bioaccumula-
tive properties. Only a few metals are nontoxic at any level. In general,
spent shale contains most of the trace metals. Trace metals in raw shale are
relatively insoluble. Thus, disposal methods and control technology should
be oriented toward prevention of leaching problems.
CHARACTERIZATION, MEASUREMENT, AND MONITORING
Heavy Metals
The potential environmental effects of toxic metals in oil shale
conversion processes are an important consideration. Highly toxic metals,
such as arsenic, lead, mercury, cadmium, selenium, and others, are poten-
tially capable of entering the air, water, or soil and posing environ-
mental and human hazards.
The fate of the heavy metals in oil shale processing has not been thor-
oughly studied. Some volatile elements (e.g., arsenic, mercury, and lead)
are introduced into the air and process water during retorting and upgrading,
while the nonvolatile elements are primarily found in the spent shale. The
leaching problem caused by spent shale may also contribute to contamination
by trace metals. Toxic heavy metal levels observed in the Green River oil
shale are shown in Table 6-14 (Colony Development Operation, 1974). Trace
metals are also present in crude shale oil products. Twenty-nine trace ele-
ments have been identified in raw shale oil (Colony Development Operation,
172
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TABLE 6-13. SEMIQUANTITATIVE X-RAY EMISSION ANALYSIS OF METALS IN
RETORT WATER FROM EXPERIMENTS USING A UTAH OIL SHALE9
Metals Concentration (ppm)
Ti, Ag, Ba 0.06 - 0.6
Ni, B, Co, Mn, Fe 0.6-6
Si, Mo 6-60
Al, Uc, Ca, Cu 60 - 600
aData from University of Southern California (1976-77).
Retort water was obtained from a simulated in situ retorting
operation, ERDA Laramie Energy Research Center.
°The uranium (U) content of this sample may be unusually high.
TABLE 6-14. TOXIC HEAVY METALS CONTENT IN OIL SHALE3
Element Concentration (wt, ppm)
Arsenic 7.2
Beryllium 35.
Cadmium °-14
Fluorine 1JQQ.
Lead 10-
Selenium °-08
Mercury <0-^
aFrom Colony Development Operation (1974).
173
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1974). A large fraction of the heavy metals remains in the spent shale (Table
6-15). Upgrading processes also introduce trace metals into wastewater streams
(Table 6-13).
TABLE 6-15. HEAVY METALS CONTENT IN RAW SHALE AND
RETORTED SHALE (VALUES IN ppm)a
Element
Arsenic
Boron
Barium
Cobalt
Chromium
Copper
Lead
Manganese
Mercury
Molybdenum
Sel eni urn
Strontium
Titanium
Uranium
Vanadi urn
Zinc
Raw shale**
50
30
300
-
70
80
900
800
-
10
10
800
600
-
600
1 ,000
Retorted shalec
35
48
180
19
230
57
23
800
0.06
14
0.5
970
1,000
5
180
22
These data are provided as a general characterization of trace
metal levels. Actual levels are expected to be site specific
and to vary with process conditions. In addition, density
changes during retorting of the oil shale must be considered
to assess the mass balance of trac'e metals.
bFrom Hendrickson (1975).
cFrom Cotter et al. (1977).
Heavy metals can be measured and monitored by using the following
methods:
•<*•*. Standard wet chemical or atomic absorption procedures
(American Public Health Association, 1974; U.S. Environ-
mental Protection Agency, 1974)
174
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• Spark source mass spectrometry (SSMS)
• X-ray emission and X-ray fluorescence methods.
Cations
Major cationic species may be examined using the following methods:
• Calcium - Permanganate and EDTA, titrimetric, and gravimetric
standard methods
• Magnesium - Gravimetric, photometric, and atomic absorption
spectrophotometric standard methods
• Sodium - AA and flame photometric standard methods
• Potassium - AA and flame photometric standard methbds
• Ammonium - Computed value based on NH3-N determination,
equilibrium constant and pH and specific ion
electrode standard methods
• Aluminum - AA standard method
• Silica - Gravimetric standard method
• Boron - Potentiometric standard method
• Iron - AA and specific ion electrode standard methods.
An ions
Major anionic species may be examined using the following methods:
• Carbonates - Computed value based on total inorganic carbon (TIC)
• Bicarbonates - Computed value based on total inorganic carbon (TIC)
• Sulfates - Gravimetric standard method
• Sulfide - Photometric standard method and titrimetric
(iodine) method
• Chloride - Potentiometric standard method and specific ion
electrode method
• Fluoride - EPA manual-automated complexone method and specific
ion electrode method
• Nitrate - EPA manual-brucine sulfate method, spectrophoto-
metric standard method, and specific ion electrode
method
175
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Nitrite
- Diazotization and photometric standard methods.
Gases
Gaseous emissions may be monitored using the following methods. Gaseous
samples can be captured in impinger solutions and analyzed by standard methods
from American Society for Testing and Materials (ASTM 1974 and 1977) or USEPA
Parameters
SO,
NO.
NHa
H2S
CO
Particulates
Character!zation
Major sources are from
retorting, plant fuel use,
and tail gas cleaning.
Mostly produced from retort-
ing and upgrading processes.
High concentrations are
found in retort water,
condensate, recycle gas,
and sour water.
High concentrations are
found in recycle gas, con-
densate, and sour water.
Largely from mining and
transport mobile equipment.
Mining, crushing, shale
handling, and disposal are
the major sources. Fuel
combustion also generates
large amounts of particu-
lates.
Measurement
Barium perchlorate titration,
conductivity and electroly-
sis, or EPA Pararosaniline
method.
Total NOX is measured as N02
using Kjeldahl distillation,
titration, chlorimetric, or
EPA gas phase chemilumines-
cence method.
Kjeldahl distillation,
titration, or direct
Nesslerization.
Colorimetric method.
Nondispersive infrared
spectrometry method (EPA).
Mass concentration and light-
scattering method, filter
method, or EPA high-volume
method.
176
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SECTION 6 REFERENCES
American Public Health Association, Standard Methods for the Examination of
Water and Wastewater. 13th ed, Washington, D.C., 1971.
American Society for Testing and Materials, Annual Book of ASTM Standards.
Part 26: Gaseous Fuels. Coal and Coke; Atmospheric Analysis, 1974.
American Society for Testing and Materials, Annual Book of ASTM Standards,
Part 31: Water. 1977. ~
Battelle Pacific Northwest Laboratories, Transport and Diffusion of Airborne
Pollutants Emanating from a Proposed Shale Oil Production Plant,
supplementary report to Colony Development Operation, Vol 1, pp 36-54,
April 1975.
Colony Development Operation, An Environmental Impact Analysis for a Shale Oil
Complex at Parachute Creek, Colorado, Part I. 1974.
Colony Development Operation, Draft Environmental Impact Statement-Proposed
Development of Oil Shale Resources, Chapter IV, 1975.
Cook, E.W., "Organic Acids in Process Water from Green River Oil Shale,"
Chemistry and Industry, p 485, May 1971.
Cotter, J.E., C.H. Prien, J.J. Schmidt-Collerus, D.J. Powell, R. Sung,
C. Habenicht, and R.E. Pressey, Sampling and Analysis Research Program
at the Paraho Shale Oil Demonstration I PIant, TRW Environmental Engineer-
ing Division and Denver Research Institute, 1977.
Dulka, J.J., and T.H. Risby, "Ultratrace Metals in Some Environmental and
Biological Systems," Journal of Analytical Chemistry, Vol 48, No. 8,
pp 640A-653A, 1976.
Hendrickson, T.A. (ed), Synthetic Fuels Data Handbook. Cameron Engineers,
Inc., pp 3-11i 1975.
Jackson, L.P., R.E. Poulson, T.J. Spedding, T.E. Phillips, and H.B. Jensen,
"Characteristics and Possible Roles of Various Waters Significant to
In Situ Oil-Shale Processing,11 Symposium on the Environmental Aspects
of Oil Shale Development, Laramie Energy Research Center, Energy Research
and Development Administration, Golden, Colorado, October 1975.
Jones, J.B., Jr., "Paraho Oil Shale Retort," Proceedings of the 9th Oil Shale
Symposium, Quarterly of the Colorado School of Mines, Vol 71, No. 4,
pp 39-48, 1974.
Kirkpatrick, L.W., "Air Pollution Aspects of Proposed Oil Shale Development
in Northwestern Colorado," Proceedings of the 7th Oil Shale Symposium,
Quarterly of the Colorado School of Mines, Vol 69, No. 2. pp 103-108,
1974.
177
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McCarthy, H.E., and C.Y. Cha, "Development of Modified In Situ Oil Shale
Process," presented at 68th National Meeting of American Institute of
Chemical Engineers, Los Angeles, California, November 1975.
Prasad, A.S., and D. Oberleas, Trace Elements in Human Health and Disease,
Vol II, Chapter 26, Academic Press, 1976.
Ross, R.D., Air Pollution and Industry, Chapter 4, Van Nostrand Reinhold Co.,
1972.
TRW Environmental Engineering Division and Denver Research Institute, A Pre-
liminary Assessment of Environmental Impacts from Oil- Shale Development,
1976.
University of Southern California, Progress Report on Retort Water Project,
U.S. Energy Research and Development Administration-Laramie Energy
Research Center, E(29-2)-3619, 1976-77.
U.S. Department of the Interior, Final Environmental Statement for the Proto-
type Oil Shale Leasing Program. 1973.
U.S. Energy Research and Development Administration, Synthetic Liquid Fuels
Development: Assessment of Critical Factors, ERDA 76-129/2, Vol II,
pp 151-152, 1976a.
U.S. Energy Research and Development Administration, "Balanced Program Plan,"
Analysis of Biomedical and Environment Research, Vol 5, 1976b.
U.S. Environmental Protection Agency, Methods for Chemical Analysis of Water
and Waste, EPA 625/74-003, 1974,
U.S. Environmental Protection Agency, Code of Federal Regulations. Title 40-
Protection of Environment, Chapter 1, EPA, Part 50, July 1977.
U.S. House of Representatives 93rd Congress, Oil Shale Technology, Hearings
before the Subcommittee on Energy of the Committee on Science and
Astronautics, Second Session on H.R. 9693, No. 48, p 468, 1974.
Van Hook, R.I., and W.D. Schultz (eds), "Effects of Trace Contaminants from
Coal Combustion," Proceedings of a Workshop, August 1976, Knoxville,
Tennessee, ERDA 77-64, p 62, 1976.
Ward, J.E., G.A. Marghein, and G.O.G. L'df, Water Pollution Potential of Rain-
fall on Spent Shale Residues, Colorado State University, EPA No.
14030EDB, December 1971.
Weaver, G.D., "Environmental Impacts of an In-Situ Shale Oil Industry," Oil
Shale Technology, Hearings before the Subcommittee on Energy of the
Committee on Science and Astronautics, U.S. House of Representatives,
93rd Congress, Second Session on H.R. 9693, No. 48, pp 65-89, 1974.
178
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Wen, C.S., "Electrolytic Processes of Oil Shale and Its Derivatives," Ph.D.
Dissertation, University of Southern California, 1976.
White River Shale Project, Detailed Development Plan, Federal Lease Tracts
U-a and U-b, Vol II, Parts 4, 5, and 6, 1976.
Williamson, S.J., Fundamentals of Air Pollution. Chapter 10, Addison-Wesley
Publishing Co., 1973.
179
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SECTION 7
ENVIRONMENTAL CONTROLS IN OIL SHALE DEVELOPMENT
INTRODUCTION
The water requirements and its availability for synfuel production may be
major constraints on this emerging industry. In oil shale development, one of
the primary concerns is the disposal of spent shale in an economic and envi-
ronmentally acceptable way. This requires large volumes of water for cooling,
dust control, and compaction. Since the water supply in the Western United
States has become a very important natural resource issue, especially in terms
of agricultural irrigation, it is essential to minimize environmental impair-
ment and to emphasize water reclamation and reuse from oil shale retorting
processes.
The Colorado River supplies water for irrigation, energy production,
municipal and industrial use, mining, recreation, and livestock watering. In
all these activities, the river serves as both a source of water and as a
carrier for manmade as well as natural residues. Salinity is the most serious
water quality problem in the Colorado River Basin. The heavy salt burden is
due to a variety of natural and manmade causes. Depletion of streamflow
caused by natural evapotranspiration and consumption of water for municipal,
industrial, and agricultural uses reduces the volume of water available for
dilution of this salt burden. As a result, salinity concentrations in the
lower river system exceed desirable levels and are approaching critical levels
for some water uses. Future water resource development and economic develop-
ment may be expected to increase streamflow depletions and consequently to
result in higher salinity concentrations.
It is estimated that when the Colorado River was in its natural state,
salinity concentrations at the site of Hoover Dam averaged about 330 ppm
(U.S. Environmental Protection Agency, 1972). By 1960 the average concentra-
tion had more than doubled (697 ppm) and it may triple by 2010 if further
development and utilization of water resources are undertaken.
WATER AVAILABILITY
The production of synthetic liquid fuel from oil shale requires extensive
water use. The problem in this semiarid western region is getting enough
water to meet this demand while also considering other use priorities and
future water allocations. This is both a legal and economic problem.
For example, an adequate amount of water for development of Tracts U-a
and U-b is available from existing impoundment facilities on the Green River.
180
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However, it would be costly to deliver the water to the facilities to be built
in the White River Basin (Schramm, 1975). Reservoirs on the White River may
be a less expensive source of water supply. Groundwater may also play a role
but this is as yet undefined.
The factor that may limit the ultimate growth of the shale oil industry
is water supply. Based on existing and authorized storage facilities, the
amount of surface water potentially available for the oil shale operation in
the western oil shale area has been estimated at 541 million m3 per year
(451,000 acre-feet per year) (Schramm, 1975). The distribution among the
three states is: Colorado, 108 million m3 per year (90,000 acre-feet per
year); Utah, 154 million m3 per year (128,000 acre-feet per year); and Wyoming,
280 million m3 per year (233,000 acre-feet per year). It is not likely that
all of this water will be available for the oil shale operation since there
are competing demands such as agricultural, municipal, and other industrial
uses. The role of groundwater in future development is unclear at this time.
Approximately 1.53-2.29 million m3 (2-3 million bbl) per day is the upper
limit of the shale oil production capacity, assuming full use by the oil shale
industry of the 555 million m3 (451,000 acre-feet) per year of surface water
potentially available. Constraints on the industry might be reduced by reduc-
ing the water consumption per cubic meter of oil produced and using ground-
water resources where possible.
Several possible means of increasing water supply are being studied. A
plan is being developed by the Colorado River Basin Project Act to increase
the flow below Lee Ferry by 3.1 billion m3 per year (2.5 million acre-feet per
year) using weather modification techniques to increase precipitation.
Another possibility being considered is the utilization of the superheated
water in the geothermal reservoirs of the Imperial Valley. The geothermal
energy can be used both in power generation and in water desalination.
Another alternative is to build a nuclear seawater desalting plant and trans-
port the water to the lower Colorado River Basin.
The water availability will also be affected by the population growth.
One estimate of population growth from the construction and operation of a
16,000 m3 per day (100,000 bbl per day) oil shale industry would add an esti-
mated 1,700 primary-jobs personnel, plus their families, and the associated
service personnel (THK Associates et al., 1974). Actual population increases
from oil shale development will depend on the retorting technology employed,
the rate of construction of facilities, and the ultimate production rate for
the region (i.e., the size of the oil shale industry).
The increase in water consumption as the result of population growth will
cause stream quality degradation from flow reduction. Domestic waste disposal
poses additional environmental problems. There are many indirect environ-
mental consequences accompanying oil-shale-associated population growth that
are related to the water quality and availability in this area. Potential
problems include modified runoff patterns and availability of recreational
facilities. Detailed consideration of these factors is beyond the scope of
this discussion but a summary is provided by ERDA (1976).
181
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Water Rights
A major factor in water availability for energy development in the West-
ern States is the role of the Federal Government-both as a claimant to the
water and as an institutional disburser of water. The Federal Government has
the authority to develop, regulate, and allocate all water resources. Of re-
lated importance is the large amount of federally owned land in the Colorado
River Basin (U.S. Public Land Law Review Commission, 1970). In the oil shale
region of the upper Colorado River Basin, 72 percent of the land is federally
owned. Reservations have been made on the Federal land for future Navy fuel
needs (U.S. Government, 1916 and 1924) and for the purposes of investigation,
examination, and classification (U.S. Government, 1930). Conflicts for water
among the various alternative uses are expected to be of key importance to
future western energy development. The role of the Federal Government,
States rights, Indian water rights, and existing compacts and treaties make
this an extremely complex legal-economic problem area.
Interstate Allocation of Water
In addition to the aforementioned problem of basic water rights and con-
flicts between alternative water uses, there are energy development water
problems related to water allocation among the basin states. Allocations for
the Upper Colorado River Basin are as follows:
billion m3 acre-ft
Arizona 0.06 50,000
Colorado 3.82 3,183,000
Utah 1.69 1,414,000
Wyoming 1.03 861,000
New Mexico 0.83 692,000
All of the states in the Colorado River Basin have their own energy develop-
ment, irrigatijon, and municipal growth water requirements. These issues are
further complicated with regard to energy development since intrastate water
is needed for recovery of energy for out-of-state use. It may be necessary to
reexamine the allocation of the already limited Colorado River water supply
as western energy development accelerates. This is true for both interstate
and intrastate allocations.
WATER REQUIREMENTS
. Water requirements for synfuel production arise mainly from the need for
cooling water to dispose of waste heat, the chemical need of hydrogen in the
conversion process, and the need for moisturizing processed shale. The cool-
ing requirement is variable, depending on whether wet cooling or dry cooling
is used. Other uses of water in the plant systems include the quenching of
gaseous products to remove oil and particulates, dust suppression, solid waste
disposal, and, potentially, the generation of steam to drive turbines or gas
compressors.
182
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A summary of water consumption from oil shale development is given in
Table 7-1. According to the maximum credible scenario, there will be 20
large (16,000 m3 per day [100,000 bbl per day]) oil shale plants by the year
2000. The total water supply required will be 384 million m3 per year
(320,000 acre-feet per year) using a water-scaling factor of 19.2 million m3
per year per plant (16,000 acre-feet per year per plant) (U.S. Energy Research
and Development Administration, 1976). Table 7-2 shows the projected increase
in water demand for the Upper Colorado River Basin by the year 2000. The
total water supply required for oil shale development is about 12 percent of
the total demand increase (U.S. Department of the Interior, 1974).
Mining
The water requirements for mining operations on Oil Shale Tracts U-a and
U-b are shown in Table 7-3 (WRSP, 1976). Potable water will be piped into the
mine and distributed to the work force. The nonpotable water for dust
suppression and fire control will come from mine drainage and the wastewater
ponds associated with surface operations on U-a and U-b. Mine drainage is
expected to be small but adequate for dust suppression within the mine, thus
reducing freshwater or treated wastewater requirements. In situ mining is
expected to have a mining water requirement of about one-fourth that of sur-
face mining.
Retorting and Upgrading
Retorting units, shale*oil upgrading units, and power plants require
cooling water. Approximately 4.6 million m3 per year (3,800 acre-feet per
year) of water are expected to be consumed for evaporative cooling on Tracts
U-a and U-b. This quantity could be reduced significantly if dry cooling
were utilized to a greater extent.
The type of cooling system selected has a significant impact on the water
resource requirements. The principal types of cooling system alternatives are:
once-through, cooling ponds, and wet and dry cooling towers (Jimeson an'd
Adkins, 1971). The once-through cooling system is used with adequate water
supplies and has no significant adverse effects on water quality. When the
water supplies are limited, cooling ponds can be constructed if suitable sites
are available. Heat is dissipated through natural surface evaporation. In
the wet cooling tower, warm water is in direct contact with air flow (develop-
ed by natural draft or fan assisted). Because of the construction and pumping
costs, wet cooling towers may be more expensive than ponds or once-through
systems. They also have the highest rate of water consumption. The dry cool-
ing towers use no water but are substantially more expensive than the wet
cooling towers.
Chemical consumption of water in oil shale processing occurs in the steam
reforming furnaces, where hydrogen is produced for use in hydrotreating raw
shale oil products. Water consumption for this purpose is approximately 1.8
million m3 per year (1,500 acre-feet per year).
183
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TABLE 7-1. AVERAGE WATER CONSUMED FOR .VARIOUS RATES OF SHALE OIL PRODUCTION
oo
-F*
Underground
50,000 bbl/day
(7,945 m3/day)
acre-ft/yr 106m3/yr
Mining and crushing
Retorting
Upgrading
Spent shale disposal
Power generation
Regeneration
Domestic Use
Total
440
650
1,825
3,650
875
350
950
8,740
0.53
0.78
2.19
4.38
1.05
0.42
1.08
10.43
Surface mine
In situ
100,000 bbl/day 50,000 bbl/day
(15,890 m3/day) (7,945 m3/day)
acre-ft/yr 106m3/yr acre-ft/yr loV/yr
875
1,315
3,650
7,295
1,750
350
1,515
16,750
1.
1.
4.
8.
2.
0.
1.
20.
05
58
38 1,840 2.21
75
10 1,275 1.53
42 350 0.42
82 885 1.06
10 4,350 5.22
Technology mix
400,000 bbl/day
(63,560 m3/day)
acre-ft/yr 10^m3/yr
3
4
14
25
7
2
6
64
,100
,600
,600
,650
,500
,450
,950
,950
3
5
17
30
9
2
8
77
.72
.52
.52
.78
.00
.94
.34
.82
Technology mix
1,000,000 bbl/day
(158,900 n>3/day)
acre-ft/yr 106m3/yr
7,000
10,500
36,500
58,500
19,000
6,000
17,500
155,000
8.4
12.6
43.8
70.2
22.8
7.2
21.0
186.0
-------
TABLE 7-2. PROJECTED INCREASE IN WATER DEMAND FOR THE UPPER
COLORADO RIVER BASIN BY THE YEAR 2000
Category of use
Municipal
Environmental (fish, wildlife,
recreation, water quality)
Agricultural (primary irrigation)
Mineral production
Coal -fired electric generation
Coal gasification
Syncrude from oil shale
Total
• 1 ,
Increase in
100 million
mVyr
9.0
1.8
9.6
1.38
5.7
1.68
3.84
33.0
*" * * ' - iii •I,..
water demand
thousand
acre-ft/yr
750
150
800
115
475
140
320
2,750
TABLE 7-3. MINING OPERATION WATER REQUIREMENTS
10,000 TPCDa
Potable Water
Nonpotable Water
acre-ft/yr
3
56
10*m3/yr
0.36
6.7
160,000 TPCD
acre-ft/yr
43
1,100
10V/yr
5.16
132
185
-------
Waste Disposal
During the retorting and upgrading of oil shale, wastewater is generated
as excess moisture from the retorting process and the gas recovery unit.
Most of these wastewater streams will be used to moisturize the spent shale.
Essentially all process wastewater will be reused. An overall water utiliza-
tion flow diagram from a TOSCO II oil shale plant is shown in Figure 7-1 (U.S.
Department of the Interior, 1973).
DUST
SUPPRESSION
DUST
SUPPRESSION
-3»
DUST
CONTROL ON
PROCESSED
SHALE
EMBANKMENT
t-
4
1
r
FOUL
WATER
STRIPPER
IU
• RIVER WATER SUPPLY
ALL RATES IN GALLONS PER MINUTE IGPMI
A WILL INCREASE TO 700 GPM IN 12 YEARS
TOTAL RIVER WATER SUPPLY
FOR YEARS 1-tl 4970GPM
FOR YEARS 12- 20: 5600 GPM
FOR DESIGN PURPOSES, NO CREDIT TAKEN
FOR SURFACE RUNOFF
25
STRIPPED WATER
PURGE FROM
S AMMONIA SEPARATION
f -
UNIT
GAS
RECOVERY
AND
TREATING
UNIT
COKER
PROCESSED
SHALE
MOISTURIZING
-WASH WATER—180-
Figure 7-1. River water utilization for 50,000 bbl/day TOSCO II
oil shale plant (Colony Development Operation, 1974)
186
-------
Excess mine water and spent-shale runoff water will be used for spent-
shale moisturization. The water used for spent-shale disposal accounts for
nearly 40 percent of the total water needed for an oil shale industry.
The prospect of achieving a long-term, stable ecosystem on a massive
spent-shale pile remains one of the major problems in oil shale development.
It has been indicated that a wide variety of plants can be grown on the spent-
shale pile if it is carefully fertilized and watered. However, only a few
types of wheat grass can survive on the unattended spent shale (Bloch and
Kilburn, 1973). Experimental work has indicated that about 1,200 m3 per year
(1 acre-foot per year) of water is required to reestablish vegetation at a
spent-shale disposal for for an 8,000 m3 (50,000 bbl) per day plant (Hutchins
et al., 1971).
Domestic Mater Use
The water requirements for sanitary and domestic uses of the work force
population are relatively low. They are only about 10 percent of the total
water used (U.S. Department of the Interior, 1972).
WATER TREATMENT AND REUSE
The major waste liquid product from oil shale retorting processes is the
retort water. It must either be upgraded for reuse in various plant process-
es or be disposed of in an environmentally acceptable way. Waste treatment
may be required to make the water acceptable for reuse.
The original, raw retort water contains small amounts of suspended oil
and particles. Most of these suspended materials are removed by filtration.
The types of soluble materials that may remain in retort waters are listed
in Table 7-4 (Yen et al., 1976b). The soluble organics can be classified as
acidic, neutral, and basic fractions (Table 7-5). The high concentrations
of organic components, NH£ and HCOa, cause the retort water to behave very
differently from conventional wastewater. A comparison of different waste
characteristics is shown in Table 7-6. The applicability of state-of-the-
art water purification technology to the treatment of retort water is cur-
rently the subject of extensive research and testing.
The quantity and quality of the produced retort water depend on the type
and the operating conditions of the retorting process and the nature of the
oil shale. Several physical and chemical processes have been tested for the
treatment of retort water. The main limitation of these methods is the prob-
lem of ultimate disposal. They require continuous addition of chemicals,
which increases the quantities of contaminants in the environment as well as
the operation cost. Since many microorganisms are capable of metabolizing
organic compounds, biological treatment may be useful as a waste treatment
process, in conjunction with other physical and chemical processes. These
physical, chemical, and biological treatment processes are outlined and
discussed as follows.
187
-------
TABLE 7-4. ANALYTICAL RESULTS FROM TWO SAMPLES OF IN SITU RETORT WATER
Parameter
COD
BOD
NH3-N
Organic-N (dissolved)
Phosphorus
N03-N
TOC
Chloride
Iodide
Bromide
Sulfate (S)
Phenols
Bicarbonate (CaCOa)
Sulfide (S)
Potassium
Sodium
Magnesium
Calcium
Iron
Zinc
Copper
Silica (Si)
Concentration
Sample No. la
20,000
5,500
4,790
1,510
0.26
38
3,182
-
0.003
0.46
59
169
16,000
16.1
3.5
312
48.4
14.9
3.3
1.6
5.6
-
(ppm)
Sample No. 2a
12,500
250
-
-
19.0
-
19,000
1,560
1.3
0.01
930
2.2
4,200
15.4
-
-
16.4
4.63
3.75
2.8
0.94
78.3
a
No. 1 retort water is from the 1-bbl lot and No. 2 retort
water from the 5-bbl lot; both were sent from LERC.
188
-------
TABLE 7-5. TOTAL SOLUBLE MATERIALS IN RETORT WATER
Inorganics
67-75
(% wt)
Organics
25-33
(X wt)
Cations
15-25
(% wt)
Anions
40-55
(X wt)
Trace
metals
Acidic
organics
10-15
(X wt)
Neutral
organics
3-5
(% wt)
Basic
organics
7-10
(% wt)
NaT 1000 ppm
Mg 100 ppm
K 50 ppm
Ca 10 ppm
NHi, 8000 ppm
HCO? 20,000 ppm
CO 3 5,000 ppm
Cl" 4,000 ppm
SOl 1,000 ppm
NOs
S"
F"
Pb, Zn, Cu, U, Cr, Fe,
Mo, As, etc.
Short-chain carboxylic acids
Ci - CM
Long-chain carboxylic acids
C IB ~ Ca«t
Phenols
Substituted benzenes
n-alkanes
Nitrogen base organics
(quinolines, pyri dines, maleimides,
succinimides, etc.]
Organic-sulfur compounds
(thiophenes, sulfides, disulfides,
etc.)
189
-------
TABLE 7-6. COMPARISON OF DIFFERENT WASTE CHARACTERISTICS
Waste
Domestic
Chemical
Refinery-chemical
Petrochemical
Retort water (filtered)
COD/TOC
4.15
3.54
5.40
2.70
6.28
BOD5/TOC
1.62
-
2.75
-
1.73
Physical and Chemical Processes
Activated carbon and resinous adsorbers have been evaluated for the reduc-
tion of high organic concentrations in retort water (Harding et al., to be
published). The treatment data are shown in Table 7-7. They also investi-
gated the removal of ammonia and carbon dioxide gases by thermal stripping.
The performance of column experiments indicates that these gases can be
stripped simultaneously from the retort water (Table 7-8). Weak-acid ion
exchange appears to affect the removal of ammonia, carbon dioxide, and bi-
carbonates. The interference by organics remains an unsolved economic problem.
TABLE 7-7. ACTIVATED CARBON ADSORPTION DATA
Parameter
COD
Alkalinity
Phenol
NH3-N
Organic N
Influent (mg/1)
12,544
38,300
31
10,690
654
Effluent (mg/1)
1,418
36,700
0
9,540
161
Percent reduction
88.7
4.2
100.0
10.8
75.4
TABLE 7-8. THERMAL STRIPPING COLUMN RESULTS
Parameter Before treatment
pH
NHt (mg/1)
Alkalinity (mg/1)
COD (mg/1)
8.65
10,000
24,300
14,064
After treatment Percent reduction
8.44
5,700
16,300
15,328
2.4
43.0
32.9
_
190
-------
Many refractory organic compounds (i.e., those that cannot be utilized by
microorganisms) are sensitive,to photo-oxidation (including nitrogen hetero-
cyclics, phenol, and benzenoid and aromatic heterocyclic compounds) (Spikes
and Straight, 1967). Most of these substances are found in retort water (Wen,
1976), which therefore should be susceptible to photochemical oxidation. The
decrease of the peak intensity of polar components on the right side of the
liquid chromatographic spectrum (Figure 7-2) shows the effectiveness of photo-
oxidation on water treatment (Yen et al., 1976a). The breakdown of high mole-
cular weight components in the retort water by a DuPont Size Exclusion Column
after ozone treatment has been reported (Yen et al., 1976a). Extensive
investigation has been undertaken to explore the electrolytic treatment for
the purification and recovery of valuable materials from retort water (Yen et
al., 1976a; Wen, 1976). The results of this treatment method are shown in
Table 7-9.
(a) ORIGINAL RETORT WATER
in
CM
(b) PHOTODEGRADED RETORT WATER
ELUTED VOLUME
Figure 7-2. High-pressure liquid chromatography spectra of highly
polar constituents (Kwan and Yen, unpublished data).
191
-------
TABLE 7-9. SUMMARY OF ELECTROLYTIC TREATMENT OF RETORT WATER3
10
IVJ
Portion
Original
retort water
Processed solutions
%
Anodic
solution
Cathodic
solution
Organic
carbonb
(% wt)
9.16
0.42
4.04
Nitrogen6
(% wt)
19.48
1.88
22.98
Total solid
residue0
(% wt)
1.68
1.05
2.01
COD
(mg/1 )
16,600
6,283
9,991
Benzene-
soluble
material
(% wt)
0.45
0.05
0.24
Color .
intensity
3441
255
1214
a Treatment in U-type membrane cell at current density of 20 mamp/cm2, cell voltage of 15 volts,
and 10-hour treatment time.
b Elemental analyses of the lyophilizing solids (ELEK Microanalytical Lab., Torrance, California).
c Values for waters subject to lyophilization.
Color intensity = 750,nm A dX, where A is adsorbance and X is the wavelength.
250 nm
-------
Biological Processes
The low operating cost of biological treatment processes makes them
attractive for organic removal. Results from activated sludge treatment of
retort water show a 37 to 43 percent COD reduction (Yen et al., 1976b). The
refractory components in biodegradation have been determined to reside in
the basic and residual (highly polar) fractions (Table 7-10).
TABLE 7-10. RESULTS OF AEROBIC TREATMENT OF FRACTIONATED RETORT WATER
COD .TOC
Percent Percent
Fraction Initial Final reduction Initial Final reduction
Acidic
Neutral
Basic
Residual
1000
991
1349
1958
345
452
930
1740
65
54
31
11
295
251
324
105
116
235
65
54
27
The aerobic treatment of retort water with mutant bacterial species
(Phenobac and Polybac) has been investigated to study the effects of mutant
bacteria on the reduction of organics in retort water (Yen et al., 1977).
The TOC results indicate that further organic reduction can be achieved by
mutant species.
Recently the rotating biological contractor system has been recognized
as an effective biological process for wastewater treatment (Antonie, 1976).
The preliminary data on retort water treatment show that the TOC reduction
is a function of the concentration of retort water (Yen et al., 1977).
Toxicity is of major concern in the operation of the biological treat-
ment. The development of effective biological processes for removing persis-
tent organic components depends on the identification and monitoring of the
organic components during the biological treatment processes. The TOC and
COD data give no information on the alternative paths the organic matter may
take, other than being completely decomposed in gaseous form and leaving
the system. Monitoring of the intermediate products will help select the
appropriate treatment method and improve the overall process. The application
of high-pressure liquid chromatography (HPLC), mentioned previously, will
provide more detailed information on treatment intermediates. The liquid
chromatography spectrum shows a dynamic change of intermediates (Figure
7-3), in which the TOC or COD data of the residual fraction show no decrease
under biological treatment. It is understood that the bacteria do break down
some of the polar components. The data also provide information on the
193
-------
DAY 0
DAY 1
DAY 4
DAY 8
e
LO
-------
improvement of process control and treatment efficiency (Kwan et al., 1977).
Since the organic components in retort water have been recognized to
be extremely complex, various combinations of unit processes are necessary
to reduce organic contaminants to a level that is acceptable to both reuse
and discharge. The effectiveness of converting high-molecular polar refrac-
tory compounds into biodegradable low molecular species by ozone, photo- or
electro-oxidation, could be used as a pretreatment. The biological treat-
ment will still be used to remove gross organic contaminants for economic
purposes. Processes such as activated carbon adsorption, ion exchange,
and electrolytic oxidation might be chosen for tertiary treatment.
CONTROL TECHNOLOGY AND ABATEMENT
The preceding paragraphs provide a discussion of oil shale wastewater
treatment technology. Environmental control technology for abatement of air
quality emissions from oil shale development is discussed in sections of this
document dealing with mining (Section 2), retorting processes (Section 3),
and shale oil upgrading processes (Section 4).
The development of control technologies is necessary for future oil shale
operations because of the great potential for environmental impact. Many
techniques are available for environmental control. However, many of these
approaches remain to be tested on commercial-scale operations. Water treat-
ment and reuse were discussed in the preceding paragraphs. To summarize some
of the available or proposed control approaches, the following sections
present technologies initially proposed for use on Colorado Tract C-a (initially
proposed as a surface mining operation [Rio Blanco Oil Shale Project, 1976])
and Utah Tracts U-a and U-b (an underground mine [White River Shale Project,
1976]). Other available technologies are also listed.
Control of Water Pollution
On Tract C-a, mine water problems would have been mitigated by collection
of surface runoff, mine seepage, and dewatering well discharges at a central-
ized collection point for reuse. On U-a and U-b, water is to be stored in a
collection pond for use in dust control within the mine.
Various methods were proposed for control and treatment of process waters
(retort water, condensates, sour water, and cooling tower and boiler blowdown
waters) on Tract C-a:
• Boiler and cooling tower blowdown used for moisturizing
processed shale
• Retort and sour water treated with API separator, stripping
system, retention pond
• Surface runoff collected in a conventional storm sewer system
and conveyed to an effluent lagoon
195
-------
• Sewage treatment plant for wastewater from processing and
discharge into the effluent lagoon for reuse.
Tract U-a and U-b systems include the following:
• All clean condensates generated in the processes segregated
and reused in boilers and cooling towers
• Sour water stripped and reused in hydrotreating units
• Process wastewater streams collected in storage tanks for
further treatment.
The use of chemical treatment (such as liming to reduce carbonates and
ammonia), ion exchange resins (Hubbard, 1971), and electrolytic methods (Wen,
1976) have also been discussed.
Control of water pollution from spent-shale disposal requires a variety
of approaches:
• Surface runoff collected by a series of lined ditches, then
conveyed to a lined collection pond at the edge of the pile;
water evaporates or is returned to the pile
• Disposal pile constructed to minimize the discharge of
leachate by surrounding the main body of processed shale
on all sides with an impermeable layer of highly compacted
processed shale (ERDA, 1976; Prien, 1974)
• If some leachate is discharged, it will be conveyed to a
lined collection pond
• Effluent lagoons will be lined with impermeable material
as will the water collection ponds and ditches.
Control of Air Pollution
Control of air pollution during surface mining may include the following
measures:
• Prewatering and wetting for dust control
• Treating with dust palliatives, such as oil emulsions,
polymers, and soil stabilizers
• Restricting the construction and mining vehicle activity
• Proper drill patterns and quantities of explosives to
minimize fugitive dust.
196
-------
Underground mining, such as proposed on Tracts U-a and U-b, may include
the following for air pollution control:
• Application of water and wetting agents applied during drilling
• Muck pile of blasted shale wetted before and during rock loading
• Conventional road wetting and chemical stabilization techniques
use for haulage roads
• Catalytic converter or wet scrubber used to control emissions
from mining equipment.
Dust suppression during shale preparation (crushing and sorting) may be
accomplished by several techniques. Developers of Tract C-a initially pro-
posed the following:
• Primary and secondary crushers enclosed with fabric filter dust
collector baghouse
• Dust collected from baghouse slurried to the processed shale
moisturizer
• Conveyor covered
• Transfer points equipped with dust suppression systems.
The following methods are proposed for Tracts U-a and U-b:
• Primary and secondary crusher units equipped with water sprays
or wet scrubber
• Fully enclosed belts and wet scrubbers at transfer points in
disposal system.
Air pollutant emissions from proposed Tract C-a retorting and refining
facilities included the following:
• Purified gas used to minimize emissions of particulates
• Desulfurization in sulfur recovery plant for untreated gas
• High energy venturi scrubber used to remove entrained shale
dust in flue gas and vapors from shale moisturizing system
• Steam stripping used to remove hydrogen sulfide and ammonia
in sour water
• The ammonia containing gas treated with special burner in the
thermal oxidizer.
197
-------
Tract U-a and U-b systems include:
• Feed hoppers and processed shale moisturizer scrubbed to
remove dust
• Retorts and refining plants provided with clean fuels
• Vent gas from processed shale moisturizer scrubbed to
remove dust
• Exhaust gases from the ball elutriators and the shale
preheater cleaned in the wet scrubbers; sulfur plants will
recover sulfur from crude shale oil and off-gases will be
treated by the tail gas treatment unit.
Solid Waste Disposal
Pollution control for spent-shale disposal, the largest solid waste
problem from oil shale operations, includes drainage control, compaction,
and stabilization. Some of the approaches for disposal and control are as
follows:
• Processed shale dumped, spread, and compacted in disposal
areas to form a stable disposal pile
• Processed shale kept at a moisture content of 11 to 19
percent by adding water to aid compaction and stabili-
zation
• Excess construction overburden or local material used to
cover the material in order to minimize rainwater percola-
tion through the spent shale
• A catchment dam constructed downstream of the pile to
collect runoff or leachate from the disposal area
• Drainage ditches located around the pile prevent surface
water from percolating through the spent-shale pile
• The processed shale pile graded and revegetated.
Spent catalysts are another important solid waste problem. Disposal
requires special handling, such as transfer in airtight containers. Spent
catalysts will be disposed of in landfills or in the spent-shale pile, or
they may be reclaimed.
198
-------
SECTION 7 REFERENCES
Antonle.R.L Fixed Biological Surface Wastewater Treatment-the Rotating
Biological Contactor, CRC Press, Cleveland, Ohio, 1976.
Bloch, M.B., and P.O. Kilburn, Processed Shale Revegetation Studies 1965-1973,
Colony Development Operation, December, 1973. -
Colony Development Operation, An Environmental Impact Analysis for a Shale Oil
Complex at Parachute Creek, Colorado, Part 1. 1974.— ~~
Harding, B., K.D. Linstedt, E.R. Bennett, and R.E. Poulson, "Treatment Evalua-
tion for Oi.1 Shale Retort Water," Journal of the Environmental Engineer-
ing Division, American Society of Civil Engineers, (1977), to be published.
Hubbard, A.B., "Method for Reclaiming Waste Water from Oil-Shale Processing,"
American Chemical Society, Division of Fuel Chemistry. Vol 16, No. 1, 1971.
Hutchins, J.S., W.W. Knech, and M.W. Legatski, "The Environment Aspects of a
Commercial Oil Shale Operation," American Institute of Mining, Metallurgy,
and Petroleum Engineers, Environmental Quality Conference for the Extrac-
ua 11 ty
7^9711
tive Industries, Washington, D. C., June 7-9, 1971.
Jimeson, K.M., and 6.6. Adkins, "Factors in Waste Heat Disposal Associated with
Power 6eneration," presented at 68th National Meeting of American Institute
of Chemical Engineers, Houston, Texas, February 28-March 4, 1971.
Kwan, J.T., and T.F. Yen, unpublished data.
Kwan, J.T., J..I.S. Tang, W.H. Wong, and T.F. Yen, "Application of Liquid
Chromatography to Monitor Biological Treatment of Oil Shale Retort
Water," American Chemical Society, Division of Petroleum Chemistry.
Vol 22, No. 2, March 1977.
Prien, C.H., Current Oil Shale Technology, Denver Research Institute, University
of Denver, 1974.
Rio Blanco Oil Shale Project, Detailed Development Plan. Federal Lease Tract
C-a, 1976.
Schramm, L.W., Shale Oil, U.S. Bureau of-Mines. Bulletin 667, pp 963-988, 1975.
Spikes, J.D., and R. Straight, "Sensitized Photochemical Processes in Biological
Systems, Ann. Rev. Phys. Chem.. No. 18, p 409, 1967.
U.S. Department of the Interior, Final Environmental Statement for the Proto-
type Oil Shale Leasing Program. Vol IV. Section C. 197Z.
U.S. Department of the Interior, Final Environmental Statement for the Proto-
type Oil Shale Leasing Program, Vol I. 1973.
199
-------
U.S. Department of the Interior, Report on Water for Energy in the Upper
Colorado River Basin, Washington, D.C., p 11, July 1974.
U.S. Energy Research and Development Administration, Synthetic Liquid Fuel
Development: Assessment of Critical Factors, Division of Transportation
Energy Conservation, ERDA 76-129/4, Vol II, p 191, 1976.
U.S. Environmental Protection Agency, Proceedings of the Conference in the
Matter of Pollution of the Interstate Water of the Colorado River and
its Tributaries-Colorado. New Mexico, Arizona, California. Nevada.
Wyoming, Utah, Seventh Session, Las Vegas, Nevada, three volumes,
February 15-17, 1972.
U.S. Government, Executive Orders of December 6, 1916.
U.S. Government, Executive Orders of September 27, 1924.
U.S. Government, Executive Orders of April 15, 1930.
U.S. Public Land Law Review Commission, One Third of the Nations Land. U.S.
Government Printing Office, Washington, D.C., p 327, 1970.
Wen, C.S., "Electrolytic Processes for Oil Shale and Its Derivatives," Ph.D.
Dissertation, University of Southern California, Los Angeles, 1976.
White River Shale Project, Detailed Development Plan, Federal Lease Tracts
U-a and U-b, Vol 1, pp 35-49, 1976.
Yen, T.F., C.S. Wen, and J.E. Findley, Degradation of the Organic Compounds in
Retort Water. Final Report, ERDA E(29-2)-3758, 1976a.
Yen, T.F., C.S. Wen, and J. Findley, Quarterly Report. September 1976. ERDA-
LERC E(29-2)-3619, p 47, 1976b.
Yen, T.F., C.S. Wen, and J. Findley, ERDA-LERC E(29-2)-3619, Quarterly Report,
June 1977. 1977. * * K ~
200
-------
APPENDIX
METRIC CONVERSION TABLE
Symbol When you know Multiply by To Find
Symbol
ac-ft
ac-ft
atm
cm
°C
*g, gm
ha
Kcal
kg
km
1
m
m
m
m2
m3
m3
Q
tonne
tonne
acre-feet
acre-feet
atmospheres
centimeters
Celsius
grams
hectares
kilocalorte
kilograms
ki 1 ometers
liter
meters
meters
meters
square meter
cubic meter
cubic meter
Quad
metric tons
metric tons
43,560
325,850
14.7
0.3937
9/5 + 32
0.002,21
2.47
3.96
2.2
0.6214
0.2642
3.281
39.37
1.09
10.76
6.28
264.2
1015
1.1
2.2xl03
cubic feet
gallons
pounds per square inch
inches
Fahrenhei t
pounds
acres
British thermal unit
pounds
miles
gallons
feet
inches
yard
square feet
barrel
' gallons
British thermal unit
ton
pounds
ft3
gal
psi
in.
°F
Ib
ac
Btu
Ib
mi
gal
ft
in.
yd
ft
bbl
gal
Btu
short tons
Ib
Used interchangeably in text.
201
-------
Abbreviations for Units of Measure
atm atmospheres
bbl barrel
bblD=BPD barrel per day
gpd gallons per day
gpm gallons per minute
kg/hr kilograms per hour
LPM liters per minute
mmhos/cm
MSCF/D
MSCM/D
*ygm, yg
nm
ppm
Psi
Psig
standard ft3
standard m3
TmPD
TPD
wt. %
millimhos per centimeter
million standard cubic feet per day
million standard cubic meters per day
microgram
nanometer
parts per million
pounds per square inch
pounds per square inch gage
quad
standard cubic foot
standard cubic meter
tonne per day
ton per day
percentage of weight
* Used interchangeably in text.
202
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-039
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
COMPENDIUM REPORTS ON OIL SHALE TECHNOLOGY
5. REPORT DATE
January 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
G.C. Slawson, Jr., and T.F. Yen (Editors)
8. PERFORMING ORGANIZATION REPORT NO.
6E77TMP-52
9. PERFORMING ORGANIZATION NAME AND ADDRESS
General Electric Company-TEMPO
Center for Advanced Studies
Santa Barbara, California 93102
10. PROGRAM ELEMENT NO.
1NE625
11. CONTRACT/GRANT NO.
68-03-2449
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency-Las Vegas, NV
Office of Research and Development
Environmental Monitoring and Support Laboratory
Las Vegas, NV 89114
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/600/07
15. SUPPLEMENTARY NOTES
EMSL-LV Project Officer for this report is Leslie G. McMillion.
(702)736-2969, x241 or FTS 595-2969, x241.
Commercial telephone
^.ABSTRACT
development of western oil shale resources has been an evolutionary
process in which production and environmental control technologies have evolved from
current mining and petroleum industry practices. In addition, new technologies are
being developed which are specific to shale oil recovery. The compendium or summary
reports included in this document consider the various production processes (mining,
retorting, and oil upgrading) and key environmental factors (organic and inorganic
characterization, environmental control, and limitations) related to oil shale develr
opment. This state-of-the-art survey supports a study designing groundwater quality
monitoring program for oil shale operations such as that proposed for Federal Oil
Shale Lease Tracts U-a and U-b located in northeastern Utah. Hence, the reports
emphasize technologies applicable to this development while also providing a general
overview of oil shale technology.
This report was submitted in partial fulfillment of Contract No. 68-03-2449 by
General Electric-TEMPO, Center for Advanced Studies, under the sponsorship of the
U.S. Environmental Protection Agency.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Oil shale
Mining
Waste disposal
Groundwater
Retorts
Waste water
Refining
Utah ;
Organic pollutants j
Inorganic pollutants
Pollutant identification
Groundwater pollution
08G
08H
081
13B
13H
8. DISTRIBUTION STATEMENT
RELEASE TO PUBLIC
19. SECURITY CLASS (ThisReport)
UNCLASSIFIED
!1. NO. OF PAGES
224
20. SECURITY CLASS (Thispage)
UNCLASSIFIED
22. PRICE
A10
Form 2220-1 (R«v. 4-77) PREVIOUS EDITION is OBSOLETE
•fr U.S. GPO:1979-684-281/2ll9
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