AEPA Environmental
Perspective on the
Emerging Oil Shale
Industry
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EPA-600/2-80-205a
ENVIRONMENTAL PERSPECTIVE ON THE
EMERGING OIL SHALE INDUSTRY
by
EPA OIL SHALE RESEARCH GROUP
Editors
Edward R. Bates
Industrial Environmental Research Laboratory
Office of Research and Development
Cincinnati, Ohio 45268
Terry L. Thoem
Office of Energy Policy Coordination
Region VIII
Denver, Colorado 80295
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency, and approved for publica-
tion. 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 recommendation for use.
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FOREWORD
When energy and material resources are extracted, processed, converted, and
used, the related pollutional impacts on our environment and even on our health
often require that new and increasingly efficient pollution control methods be used.
The Industrial Environmental Research Laboratory-Cincinnati is engaged in
developing and demonstrating new and improved methodologies that will meet
these needs both efficiently and economically.
This report provides a preliminary overview of environmental considerations
related to the emerging oil shale industry. The report and similar ensuing reports
are intended to develop the technical basis for eventual regulations.
The recently announced national synfuels program relies on development of the
oil shale industry. We believe that providing information on environmental con-
cerns and developing control technology in concert with development of oil shale
technology will enable the establishment of a mature oil shale industry compatible
with national environmental goals without unnecessary delay.
Further information on the subject of this report can be obtained through the
authors and offices responsible for preparation of each topic or from the Oil Shale
and Energy Mining Branch, Energy Pollution Control Division, Industrial En-
vironmental Research Laboratory, Cincinnati, Ohio 45268.
Steven R. Reznek
Deputy Assistant Administrator
Environmental Engineering and Technology
111
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PREFACE
This document originated as a result of the U.S. Environmental Protection
Agency (EPA) concern that the development of oil shale as an alternative energy
source not be constrained by uncertainties about environmental standards. The
EPA intent is to insure that technology-specific environmental goals are identified
and achieved during the course of oil shale technology development. The concur-
rent development of control technology and oil shale technology will result in the
undelayed establishment of a mature oil shale industry compatible with Federal,
State, and local environmental goals.
This document is intended as part of a series leading toward the establishment of
regulatory standards for the oil shale industry. The entire series is supported by the
EPA oil shale research program and is expected to serve several purposes. First and
foremost, it will communicate EPA regulatory policies to oil shale developers on a
comprehensive basis. Second, the series will update the state of knowledge with
respect to known oil shale pollutants and their potential effects. Third, the series
will describe state-of-the-art control technologies as they evolve and will describe
the remaining needs for which technologies are not sufficient. Fourth, the series
will describe methods for monitoring and for sample collection and analysis ap-
plicable to the oil shale industry. Finally, it will suggest ranges of discharge and
emission limits within which the oil shale industry should strive to operate. Ideally,
as more information becomes available, each document in the series will offer more
definitive limits and more demonstrated confidence in available control
technologies.
This document presents general information relevant to oil shale pollution prob-
lems and their control as they are viewed today. It should be kept in mind that the
present data base is meager and that attempts to define problems and their control
precisely are incomplete. The purpose here is to present a first approximation to
EPA's environmental expectations and thereby to generate, through their publica-
tion, the proper perspective, concern, and approach for the environmental aspects
of oil shale development.
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ABSTRACT
Oil shale deposits in the United States are among the richest and most extensive
in the world. Estimates place total identified resources of medium and rich shales in
the United States at 2 trillion equivalent barrels of oil. About 600 billion barrels are
considered recoverable with present technology. This report summarizes the an-
ticipated regulatory approach taken by the EPA toward oil shale development and
is designed to serve as a reference and guide to EPA offices, Federal agencies, and
private developers involved with the emerging oil shale industry.
The document conveys EPA's understanding and perspective of oil shale
development by providing (1) a summation of available information on oil shale
resources, (2) a summary of major air, water, solid waste, health, and other en-
vironmental impacts, (3) an analysis of applicable pollution control technology, in-
cluding limitations, (4) a guide for the sampling, analysis, and monitoring of emis-
sions, effluents, and solid wastes from oil shale processes, (5) suggestions for in-
terim objectives for emissions, effluents, and solid waste disposal, and (6) a sum-
mary of oil shale technology, emissions, and effluents. The report provides a brief
yet thorough discussion of the environmental problems of oil shale development.
For readers who wish further information on the topics covered in this volume, a
list of Appendices referred to in the text, as well as ordering instructions, is in-
cluded following the list of Tables.
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CONTENTS
Foreword iii
Preface iv
Abstract v
Figures x
Tables xi
List of Appendices xv
Abbreviations xvii
Special Acknowledgment xx
Acknowledgments xxi
1. Introduction 1
Purpose of Document 1
Oil Shale Resources 2
Current Status of Industry Development 11
Applicable Federal and State Pollution Control Laws 21
Applicable Federal and State Pollution Control Regulations 22
References 29
2. Recommendations 31
Proposed Precommercial Approach to Regulations 31
Regulated and Nonregulated Pollutants 33
Proposed Monitoring Procedures 34
Guidelines for an Ambient Monitoring Network in
Oil Shale Development Areas 34
Surface and Groundwater Ambient Monitoring 35
Solid Waste 36
Recommended Research 37
References 50
3. Environmental Impacts 41
Atmospheric Impacts 41
Process Emissions 41
Residual Atmospheric Emissions 51
Trace Element Emissions 58
Water Quality Impacts 63
Sources and Nature of Waters from Oil Shale
Processing 63
Effects of Wastewater Disposal on Surface Waters 65
Effects of Wastewater Disposal on
Groundvvaters—Backflood Waters 69
Long-term Effects of the Oil Shale Industry
on Surface Water Resources of the
Colorado River Basin 73
Solid Waste Impacts 84
Inventory of Solid Wastes 84
Raw Shale Handling and Disposal 86
Spent Shale Handling and Disposal 86
Other Solid Process Wastes 92
Leaching of Solid Wastes 93
vn
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Health Effects of Refining and Use of Shale Oil
and Oil Shale ::
Human Health Effects }""
Biological Experimentation jy-:
Other Environmental Impacts J J"
Shale Products Utilization J j"
Radiation ll3
Noise l *
Socioeconomic Impacts 1''
References 127
4. Pollution Control Technology I33
Air Emission Controls I33
Control of Particulates I33
Control of Gaseous Emissions 138
Wastewater Treatment Controls 151
Wastewater Treatment Methods 152
Wastewater Sources, Quantities, and Characteristics 153
Application of Treatment Methods to Oil Shale
Wastewaters 161
Solid Waste Controls 165
Surface Disposal of Overburden, Lean Shale, and
Spent Shales 165
Underground (Mine) Disposal of Spent Shale 173
Stabilization of In Situ Spent Shale 173
Other Process Controls 176
Storage Tank Vapor Controls 176
Refinery Sludge Controls 177
References 177
5. Sampling, Analysis, and Monitoring 181
Air 181
Gases 181
Particulates 191
Analytical Methods for Ambient Particulate Samples 192
Meteorological Conditions 193
Visibility 193
Water 194
Surface Water Monitoring Methodology 194
Groundwater Monitoring Methodology 206
Standard Water Analyses 216
Analysis of Organic Pollutants in Surface Water
and Groundwater 222
Solid Waste 230
Monitoring Methodology 230
Analytical Methods for Leachates from Oil Shale 239
Solid Inorganics 243
Organics in Solid Samples 245
Health Testing Approach and Methods 247
References 249
6. Environmental Guidelines 257
Criteria for Environmental Goals 257
Suggested Interim Environmental Goals 257
Air 258
Water 260
Solid Waste 262
EPA Policies and Procedures 263
viii
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Industry View of Regulation 269
Editor's Note 269
Industry Position 269
References 275
7. Oil Shale Technology, Emissions, and Solid Wastes 277
Overview of Shale Technology 277
Mining 277
Crushing, Storage, and Transportation 279
Surface Retorting 279
In Situ Retorting 280
Spent Shale Disposal 281
Retort Gas Treatment 281
Shale Oil Upgrading 282
Surface Retorting Processes 284
Gas Combustion Retorting Process 284
TOSCO II Retorting Process 286
Paraho Development 289
Union Oil Development 292
Superior Oil Development 300
Lurgi-Ruhrgas Process 306
IGT HYTORT Process 308
In Situ Retorting Processes 309
Occidental Modified In Situ Process 309
Rio Blanco MIS Process 314
Multi-Mineral Integrated In Situ Process 314
Geokinetics Horizontal In Situ Process : 318
Equity BX In Situ Process 320
References 324
IX
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FIGURES
Number Page
1-1 Principal U.S. oil shale deposits
1-2 Green River Formation oil shale deposits 4
1-3 Detailed stratigraphy of Green River Formation 8
1-4 Project schedules for commercial oil shale projects 13
1-5 Project schedules for field test oil shale projects 14
3-1 Estimated sulfur emissions as function of time 52
3-2 Overview of a possible water management plan 63
4-1 Oil shale water and wastewater utilization 152
4-2 Comprehensive hypothetical schematic diagram for oil shale
wastewater treatment 163
5-1 Percentage of hydrocarbon in the gas stream versus
boiling point of carbons 1-6 189
5-2 Groundwater flow net in homogenous aquifer 212
5-3 Idealized two-dimensional pattern showing relationship
between true direction of groundwater flow and
direction inferred by drawing orthogonal lines to
regional water level contours 213
5-4 Fractured rock aquifer system yielding water of varying
quality, depending on location and perforation of wells 215
5-5 Elements measurable by various instruments 218
5-6 Possible monitoring facilities: soil trenches 238
5-7 Possible monitoring facilities at the toe of the spent
shale pile 240
6-1 Polycyclic aromatic hydrocarbon formation - a comparison
of petroleum and shale oil 272
7-1 Multiple-level room and pillar mining concept 278
7-2 Gas combustion retorting process 285
7-3 TOSCO II retorting process 287
7-4 Diagram of Paraho retorting process 291
7-5 Diagram of Union Oil Retort A 296
7-6 Process flow diagram Union Retort B Process 298
7-7 Diagram of Union Oil Retort B 299
7-8 Diagram of Union Oil SCR-3 retorting process 301
7-9 Cross sectional view of Superior retort 302
7-10 Functional design of Superior retort 303
7-11 Diagram of Superior retorting process 304
7-12 Lurgi-Ruhrgas retorting process 307
7-13 HYTORT commercial plant concept 310
7-14 Occidental's modified in situ retorting process 315
7-15 Flow diagram of OXY MIS plant 316
7-16 RBOSC modular development phase mine diagram 32Q
7-17 Multi-mineral integrated in situ process 321
7-18 Plan and section of a typical Geokinetics horizontal
in situ retort 322
7-19 Equity Oil/DOE Bx in situ shale project flow diagram 323
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TABLES
Number Page
1-1 Total In-place Shale Oil Resources of the Green River
Formation 3
1-2 Green River Formation Oil Shale Ownership 6
1-3 Typical Composition of 104-1/Tonne Green River Formation
Oil Shale 7
1-4 Shale Oil Production and Disposition 17
1-5 Status of EPA Region VIII Delegations to Oil Shale States 23
3-1 Estimated Atmospheric Emissions from 50,000-bbl/day
Oil Shale Surface Mining Operations 43
3-2 Estimated Particulate Emissions from 50,000-bbl/day
Underground Mining Operations 44
3-3 Summary of Sulfur Dioxide and Oxides of Nitrogen
Emissions Reported from 50,000-bbl/day Underground
Mining Operations 45
3-4 Summary of Hydrocarbon and Carbon Monoxide Emissions
from 50,000-bbl/day Underground Mining Operations 46
3-5 Controlled Particulate Emissions from Surface
and Underground Mining Resulting from Crushing,
Transportation, and Storage of Raw Shale 47
3-6 Projected Controlled Sulfur Dioxide Emissions
from the Retorting of Oil Shale 48
3-7 Projected Controlled Particulate Emissions from the
Retorting of Oil Shale 49
3-8 Projected Controlled Oxide of Nitrogen Emissions
from the Retorting of Oil Shale 50
3-9 Projected Controlled Hydrocarbon Emissions from the
Retorting of Oil Shale 51
3-10 Projected Controlled Carbon Monoxide Emissions
from the Retorting of Oil Shale 51
3-11 Fugitive Emissions at the Paraho Shale Transfer Area 54
3-12 Dispersion of Sulfur Dioxide and Its Residual
Time-Averaged Annual Concentrations for 50,000-bbl/day
Operations, EPA Valley Model 55
3-13 Dispersion of Particulates and Their Residual Time-Averaged
Annual Concentrations for 50,000-bbl/day Operations 56
3-14 Dispersion of Oxides of Nitrogen and Their Residual
Time-Averaged Annual Concentrations for 50,000-bbl/day
Operations 57
3-15 Dispersion of Hydrocarbons and Their Residual Time-Averaged
3-Hour Concentrations for 50,000-bbl/day Operations 58
3-16 Dispersion of Carbon Monoxide and Its Residual Time-Averaged
Annual Concentrations for 50,000-bbl/day Operations 59
3-17 Fugitive Dusts and Their Residual Time-Averaged Annual
Dust Concentrations for 50,000-bbl/day Operations 60
3-18 Mean Levels of Selected Trace Elements in Raw Oil
Shale—Comparison of Reported Data for Class I Elements 61
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3-19 Trace Metal Analyses of Raw and Spent Shale Fugitive Dusts
from Anvil Points, Colorado
3-20 Water Quality Characteristics of Geokinetics Oil
Shale Retort Water 66
3-21 Summary of Acute, Flow-through Bioassay Results
for Rainbow Trout (Salmo gairdneri), Fathead
Minnows (Pimephales promelas), and Daphnia pulex
Exposed to Process Waters 68
3-22 Volatile and Semivolatile Organic Compounds Present
at Concentrations of 100 ppb or Greater in Aqueous Samples
from 136-Tonne LETC Oil Shale Retort 76
3-23 Estimated Spent Shale Quantities and Disposal Areas Required 85
3-24 Characteristics of Spent Oil Shales from the Leading
Retorting Processes 88
3-25 Mean Levels of Trace Elements in Processed Oil Shale 89
3-26 Surface Runoff Water Quality for Spent Oil Shale Test Plots 90
3-27 Analysis of Spent Shale Leachates 95
3-28 Estimated Quantities of Some Major Constituents
Leachable from Oil Shale 97
3-29 Permeability of Paraho Spent Oil Shale for Various
Compactive Efforts and Loadings 98
3-30 Range of Reported Permeability Values of Various
Compacted Spent Oil Shales 99
3-31 Leaching Characteristics Under Saturated Conditions
of Raw Surface Stored Oil Shale - Preliminary Results 101
3-32 Carcinogenic Potency of Raw and Upgraded Shale Oil 106
3-33 Repository Distribution of Paraho Above Ground
Retort Materials 107
3-34 Repository Distribution of Sohio-refined Paraho Shale
Oil Materials and Petroleum Equivalents 108
3-35 Estimates of Radioactive Element Concentrations
in Colony Shale 114
3-36 Estimated Radionuclide Emissions to the Air from a
13,600-tonne/day (100,000-bbl/day) Oil Shale Facility 115
3-37 Estimated Socioeconomic Impacts of Oil Shale Development 118
3-38 Estimated Costs for Community Expansion Resulting from
Development of a 45,000-bbl/day Unit Oil Shale Facililty 119
3-39 Summary of Projected Socioeconomic Impacts of Oil Shale
Development at Tracts U-a and U-b 120
3-40 Projected Employment and Population Increases
Resulting from Oil Shale Development at Tract C-a 122
3-41 Summary of Socioeconomic Impacts of Oil Shale
Development at Tract C-b 124
3-42 Average Annual Municipal and Human Service Costs
for Tract C-b for a 31-Year Period 125
3-43 Summary of Socioeconomic Impacts of Oil Shale
Development at the Colony Development Operation 126
4-1 Water Spray as a Control Technique for Particulates 135
4-2 Fabric Filter as a Control Technique for Particulates 136
4-3 Estimated Performance of the Scrubber as a Control Technique
for Particulates 138
4-4 Concentration of H2S in the Paraho Recycle Gas 140
4-5 Utilization of Water and Wastewater for Oil Shale Development 154
4-6 Water Quality Parameters for In Situ Retort Waters 155
4-7 Major Organics in Retort Waters .' 155
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4-8 Trace Element Concentration (ppm) in Waters from Surface
and In Situ Retorts 156
4-9 Trace Elements in Surface and In Situ Retort Waters 157
4-10 Characteristics of Steam Boiler Slowdown, Union B Process 157
4-11 Characteristics of Wastewater from Back washing and
Rinsing Operations, Union B Process 158
4-12 Characteristics of Regeneration Wastewaters, Union B Process 158
4-13 Some Water Quality Characteristics from Groundwaters
in Piceance Basin 159
4-14 Sources and Flow Rates of Water from Tract C-a 160
4-15 Characteristics of Union B Boiler Feedwater and Blowdown 161
4-16 Characteristics of Union B Cooling Tower Blowdown 161
4-17 Percent of Vegetative Cover Established on Spent Oil
Shale Test Plots 167
4-18 Percent of Plant Survival After 1 Year, By Site Treatment
and Topographical Aspect, Roan Plateau 168
4-19 Trace Metal Uptake by Plants Grown on EPA Spent Oil
Shale Test Plots 171
5-1 Precision and Accuracy Ranges for Monitoring Methods
Used in the Analysis of Oil Shale Effluents 182
5-2 Summary of CO2)O2,N2, and CO Data Taken at Paraho 185
5-3 Summary of NH3 and HCN Emissions in the Recycle Gas from
Paraho 187
5-4 Summary of COS and CS2 Data from Paraho 188
5-5 Summary of Gas Chromatograph Conditions for C,-C6 190
5-6 Priority A Chemical and Physical Parameters Recommended
for Monitoring in Surface Waters 200
5-7 Priority B Chemical and Physical Parameters Recommended
for Monitoring in Surface Waters 202
5-8 Priority C Chemical and Physical Parameters Recommended
for Monitoring in Surface Waters 204
5-9 Priority A Biological Parameters Recommended for
Monitoring in Surface Waters 207
5-10 Priority B Biological Parameters Recommended for
Monitoring in Surface Waters 208
5-11 Effects of Well Recompletion on Water Quality 216
5-12 Summary of Solid Waste Pollutants and Pollutant Sources 232
5-13 Preliminary Priority Ranking of Pollutant Sources and
Pollutants for Oil Shale Tracts U-a and U-b 234
5-14 Outline of Preliminary Chemical Analysis Program for
Monitoring Processed Shale Disposal Area 236
5-15 Health Testing in Progress in the Oil Shale Industry 248
7-1 Properties of Crude Shale Oils 283
7-2 Average Composition of Offgas from Gas Combustion Retort 286
7-3 Average Rates of Air Emissions, from Proposed Colony Project 289
7-4 Approximate Composition of TOSCO II Wastewater Used to
Moisturize Spent Shale 290
7-5 Chemical Composition of TOSCO II Spent Shale 290
7-6 Composition of Paraho Spent Oil Shales 292
7-7 Composition of Paraho Retort Gas Product 293
7-8 Average Composition of Paraho Retort Offgas 293
7-9 Inorganic Analysis of Condensate Streams from the
Paraho Process 294
7-10 Analysis of Paraho Condensate Water and Process Water 295
7-11 Composition of Union A Offgas 295
xm
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7-12 Summary of Design Emissions for the Union B Retort and
Related Facilities 3(?
7-13 Composition of Union Spent Oil Shales ™
7-14 Composition of Product Gas from Union SGR-3 Process 305
7-15 Composition of Combustor Flue Gas from SCR-3 Process 305
7-16 Composition of Lurgi-Ruhrgas Offgas 308
7-17 Properties of Lurgi-Ruhrgas Condensate Wastewater 308
7-18 Water Pollutant Loading from Hydroretort Reactors 311
7-19 Estimated Emissions from Commercial HYTORT Plant 313
7-20 Oxy Logan Wash Retorts 7 & 8 Air Emissions Rates 317
7-21 Composition of MIS Retort Gas 318
7-22 Typical Analysis of Oxy Retort 6 Process Water 319
7-23 Rio Blanco MDP Estimated Emissions 324
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LIST OF APPENDICES
The Appendices referred to throughout this document are listed below. In order to
obtain any of these references, address requests to:
National Technical Information Service
U.S. Department of Commerce
Springfield, Virginia 22161
Appendix A — Status and Development Plan of the Oil Shale Industry A-l
Rio Blanco Oil Shale Co A-2
Cathedral Bluffs Shale Oil Co A-7
White River Shale Project A-ll
Colony Development Operation A-14
Union Oil Co A-20
The Superior Oil Co A-22
TOSCO Sand Wash Project A-27
Occidental Oil Shale, Inc A-27
Geokinetics, Inc A-31
Equity Oil Co A-33
Multi-Mineral Project A-34
Dow Chemical Co A-38
Laramie Energy Technology Center A-39
References A-41
Appendix B — Procedures for Ambient Air Monitoring B-l
Introduction B-l
Meteorological Measurements B-l
Visibility B-5
SO2 Methods B-7
CO by Nondispersive Infrared Method B-9
Suspended Particles by High-Volume Sampler B-9
Ozone Methods B-10
NO2 Methods B-ll
Carbon Monoxide, Methane, and Nonmethane Hydrocarbons
by Flame lonization Detection B-12
Hydrogen Sulfide, Mercaptans, and Organic Sulfides
by Rame Photometric Detection B-13
Lead Using Atomic Absorption Spectroscopy B-l4
Mercury Methods B-14
Arsenic Using a High-Volume Sampler B-15
Methods for Particulates B-15
Sulfates Using the Methylthymol Blue Method B-l6
Nitrates Using Copperized Cadmium Reduction B-l7
Fluoride on Hi-Vol Filters B-17
Ammonia Methods B-18
Benzo(o)pyrene Using Flurometric Analysis B-l 9
C, Through C5 Hydrocarbons Using Gas Chromatography B-20
Organics by Absorption, Purge, and Trap Gas Chromatography B-20
PAH Using UV Spectroscopy B-20
Polycyclic Organic Matter B-21
Asbestos and Asbestos-like Fibers B-21
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References.
B-22
Appendix C — Environmental Monitoring Activities - Past, Present,
and Proposed ~^
Tract C-a C-l
Tract C-b c'^
Tracts U-a, U-b c-103
U.S. Department of Energy Rock Springs Research Sites C-129
Paraho C'139
Colony Development Operation C-151
Bx (Equity) Oil Shale Project C-172
Occidental Oil Shale, Inc., Logan Wash Project C-177
Geokinetics Oil Shale Group C-186
Dow Chemical Co C-193
Talley-Frac/Rock Springs Project C-199
References C-206
Appendix D — Applicable Federal, State, and Local Legislation,
Standards, and Regulations D-l
Legislation D-l
Standards D-2
Permit Programs — Existing D-25
Appendix E — Quality Assurance Bibliography E-l
Appendix F — Federal and State Permits Required for Operation
of an Oil Shale Facility F-l
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AA
AAS
ADA
adits
API
ANFO
ARCO
ASTM
BACT
BaP
BAT
BATEA
bbl
BEJ
BLM
BMP
BOD
BPT
BTU
cfm
CFR
CI
cmm
COD
COED
Comm
COS
CRA
CRC
CWACOG
DDP
DDT
de novo
DMEPG
DO
DOC
DOE
DOI
dscf
EOF
EDXRF
El
EIS
EPA
Eh or EH
FID
FWPCA
gal
Dev
ABBREVIATIONS
—atomic absorption
—atomic absorption spectroscopy
—anthraquinone disulfonic acid
—access tunnels
—American Petroleum Institute
—Ammonium Nitrate Fuel Oil
—Atlantic Richfield Corporation
—American Society for Testing and Materials
—best available control technology
—benzo(a)pyrene
—Best Available Technology
—best available technology economically achievable
—barrels (159 litres or 42 gallons)
—Best Engineering Judgment
—Bureau of Land Management
—best management practices
—biochemical oxygen demand
—best practical technology
—British Thermal Units
—cubic feet per minute
—Code of Federal Regulations
—chemical ionization
—cubic meters per minute
—chemical oxygen demand
—char-oil-energy development
Phs.—commercial development phase
—carbonyl sulfide
—compression/refrigeration/absorption
—compression/refrigeration/condensation
—Colorado West Area Council of Governments
—detailed development plan
—dichlorodiphenyltrichloroethane
—starting from scratch
—dimethyl ether of polyethylene glycol
—dissolved oxygen
—dissolved oxygen content
—Department of Energy
—Department of Interior
—dry standard cubic foot
—Environmental Defense Fund
—energy dispersive x-ray fluorescence spectroscopy
—electron impact
—environmental impact study
—Environmental Protection Agency
—oxidation-reduction potential
—flame ionization detector
—Federal Water Pollution Control Act
—gallon
xvu
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GC/MS
OCR
GPM
GPT
ha
IFF
IGT
in situ
in vitro
IPA
IR
kmph
kW
kWh
LC
LETC
LPG
M
MBAS
MCi
MDP
mill
MIS
MMC
Mod. Dev. Phs.
mph
MSSS
MTB
NAA
NAAQS
NAS
NDIR
NESHAP
NEPA
NIH
NMHC
NOx
NPC
NPDES
NSPS
NWS
ORNL
OSHA
OXY
PAD
PAH
PCB
pCi
PDU
PES
PMC
POM
PON
ppb
PPm
— gas chromatograph/mass spectrometer
— gas combustion retort
—gallons per minute
— gallons per ton
— hectare
—Institute Francais de Petrok
— Institute of Gas Technology
—in the original location
—outside the organism in an artificial apparatus
—Intergovernmental Personnel Act
—Infrared
— kilometers per hour
—kilowatt
— kilowatthour
— liquid chromatography
— Laramie Energy Technology Center
— low pressure gas
— molar
— methylene blue active substances
— megacuries
— Modified Development Phase
— tenth of a cent
— modified in situ
— Multi-Mineral Corporation
— modular development phase
— miles per hour
—Mass Spectral Search System
— methylthymol blue
— neutron activation analysis
—National Ambient Air Quality Standards
— National Academy of Sciences
— nondispersive infrared
—National Emission Standards for Hazardous Air Pollutants
—National Environmental Policy Act
—National Institute of Health
—non-methane hydrocarbons
— oxides of nitrogen
—National Petroleum Council
—National Pollutant Discharge Elimination System
—New Source Performance Standards
—National Weather Service
—Oak Ridge National Laboratory
— Occupational and Safety Hazard Act
—Occidental Oil Shale, Inc.
— perchloric acid digestion
— polycyclic aromatic hydrocarbons
— polychlorinated biphenyls
— picocurie
—Process Development Unit
— proton-electron spin spectrometer
—potency of the mixture complex
—polycyclic organic matter
— program opportunity notice
— parts per billion
— parts per billion by volume
— parts per million
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ppmv —parts per million by volume
PSD —prevention of significant deterioration
psig —pounds per square inch (mercury scale)
PTCM —potassium tetrachloromercurate
PUV —pulsating ultraviolet
RBOSC —Rio Blanco Oil Shale Development Corp.
RCRA —Resource Conservation and Recovery Act
RSH —sulfhydryl compounds
scf —standard cubic foot
scfd —standard cubic feet per day
scfm —standard cubic feet per minute
scm —standard cubic meter
scmd —standard cubic meters per day
SCOT —Shell Claus Off-gas Treating
SGR —steam gas recirculation
SIC —Standard Industrial Classification
SNG —synthetic natural gas
SOX —oxides of sulfur
SSMS —spark-source mass spectrometer
STORET —storage and retrieval system
TCM —tetrachloromercurate
TDS —total dissolved solids
THC —total hydrocarbons
TIC —Total Inorganic Carbon
TKN —Total Kjeldahl Nitrogen
TLC —thin layer chromatography
TLV —threshold limit values
TOSCO —The Oil Shale Corp.
TRS —Total Residual Sulfur
TRW, Inc. — Thompson-Raymo-Woolridge
TSCA —Toxic Substances Control Act
TSP —Total Suspended Particulates
TSS —total suspended solids
UBAG —Uinta Basin Association of Governments
UIC —underground injection control
UOC —Union Oil Company
USBM —U.S. Bureau of Mines
USFS —United States Forestry Service
USGS —U.S. Geological Survey
UV —ultraviolet
VTN —Voorheis-Trindle-Nelson
WATSTORE —water data storage and retrieval system (USGS)
WRSP —White River Shale Project
XRF —x-ray fluorescence spectroscopy
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SPECIAL ACKNOWLEDGMENT
Special acknowledgment is made to the late Dr. Charles H. Prien, Denver
Research Institute, University of Denver, for his substantial input to this document
and for his active support and contributions to the advancement of oil shale
technology. During his one year Intergovernmental Personnel Act (IPA) assign-
ment with the U.S. Environmental Protection Agency ending in November 1979,
Dr. Prien provided invaluable assistance in developing the structure and content of
this document and authored several of the topics contained here. His advice on en-
vironmental impacts, control technology, and status of industry development are
gratefully acknowledged. During his more than 30 years of active participation in
advancing oil shale technology, Dr. Prien authored 65 papers or portions of books
on oil shale technology and served on numerous advisory committees, task forces,
and study teams for oil shale development.
xx
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ACKNOWLEDGMENTS
The editors wish to acknowledge the cooperation and assistance of the oil shale
industry in reviewing, commenting ort, and providing additional material for this
document. We are particularly grateful for the assistance of the following com-
panies:
Arco Coal Company
Carter Oil Company
Chevron USA, Incorporated
Colony Development Operation
Development Engineering, Incorporated
Equity Oil Company
Geokinetics, Incorporated
The Institute of Gas Technology
Multi-Mineral Corporation
Occidental Oil Shale, Incorporated
Rio Blanco Oil Shale Company
Standard Oil Company (Indiana)
Superior Oil Company
Tosco Corporation
Union Oil Company of California
White River Shale Project
Rocky Mountain Oil and Gas Association
The editors wish to acknowledge the cooperation and assistance of the following
government agencies in reviewing and commenting on this document:
Area Oil Shale Office, U.S. Geological Survey, Department of the Interior
U.S. Bureau of Mines, Department of the Interior
Colorado State University
Laramie Energy Technology Center, Department of Energy
Lawrence Berkeley Laboratory, University of California
National Park Service, Department of the Interior
Oil Shale Energy Technology Committee, Al Galli, Chairperson,
U.S. Environmental Protection Agency
The editors gratefully acknowledge the contributions of the following authors
whose efforts collectively constitute this document:
Ann Alford, Environmental Research Laboratory, Athens, Georgia 30601
David Coffin, Health Effects Research Laboratory, Research Triangle
Park, North Carolina 27711
Wesley Kinney, Environmental Monitoring Systems Laboratory,
Las Vegas, Nevada 89114
William McCarthy, Office of Environmental Engineering and Technology,
Washington, D.C. 20460
Leslie McMillion, Environmental Monitoring Systems Laboratory,
Las Vegas, Nevada 89114
Paul Mills, Environmental Monitoring Systems Laboratory,
Las Vegas, Nevada 89114
Len Mueller, Environmental Research Laboratory, Duluth,
Minnesota 55804
xxi
-------
Bob Newport, Robert S. Kerr Environmental Research Laboratory,
Ada, Oklahoma 74820
Michael Pearson, Northrop Services, Inc., Las Vegas, Nevada 89114 (formerly
Environmental Monitoring Systems Laboratory,Las Vegas, Nevada 89114)
Thomas Powers, Industrial Environmental Research Laboratory,
Cincinnati, Ohio 45268
The Late Charles Prien, Denver Research Institute, Denver,
Colorado 80208
Robert Thurnau, Industrial Environmental Research Laboratory,
Cincinnati, Ohio 45268
Bruce Tichenor, Industrial Environmental Research Laboratory,
Research Triangle Park, North Carolina 27711
David Sheesley, Laramie Energy Technology Center, Department
of Energy, Laramie, Wyoming 82071
The editors are also thankful for the encouragement and assistance provided by
Mr. Eugene F. Harris, Chairperson, EPA Oil Shale Research Group. It was largely
through the efforts of Mr. Harris and the EPA Oil Shale Research Group that this
effort was undertaken and carried to a successful conclusion.
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SECTION I
INTRODUCTION
The introductory section describes oil shale resources in the United States, with
emphasis on the rich shales contained in the Green River Formation in Colorado,
Utah, and Wyoming. It provides a status report on developmental activity and
technology, and summarizes applicable current environmental control laws.
This report defines and evaluates oil shale on the basis of stratigraphy,
mineralogy, and recoverability of oil. It presents detailed information on the rich
shales, those that yield 62 to 125 I/tonne or 15 to 30 gal/ton of the Green River For-
mation, which is believed to contain 80 percent of all commercially attractive
deposits.
The two general methods of recovering oil or gas from shale are mining plus sur-
face retorting and in situ (in the original place) processing. The first section of this
report describes these methods, discusses the status of mining retorting technology
as it applies to the recovery of oil from shale and presents a short history of
development during recent years.
A review of current Federal and State pollution control requirements applicable
to oil shale facilities follows the technology discussion. Federal legislation generally
establishes the framework for State environmental regulations. Therefore, the
document discusses Federal laws dealing with air and water pollution, solid wastes,
noise, and radiation with less emphasis on the State regulatory process.
PURPOSE OF DOCUMENT
The purpose of this document is to provide preliminary environmental guidance
on the emerging oil shale industry. The report is intended to serve as a reference,
summary, and guide to regulators, developers, and others who are or will be in-
volved with the oil shale industry.
This report conveys the Environmental Protection Agency's (EPA) understand-
ing and perspective of oil shale development by providing (a) a summation of
available information on oil shale resources; (b) a summary of major air, water,
solid waste, health, and other environmental impacts; (c) a brief overview of appli-
cable pollution control technology; (d) suggestions for the sampling, analysis, and
monitoring of emissions, effluents, and solid wastes from oil shale processes; and
(e) suggestions for interim objectives for emissions, effluents, and solid waste con-
trol. The report contains a brief summary discussion of the environmental prob-
lems of oil shale development. For the reader not acquainted with oil shale
technology, Section 7 presents a summation of the major retorting methods and
their probable emissions, effluents, and solid wastes.
Government agencies and private developers will find this document useful as a
source of basic information as well as for identifying EPA concerns and interests
relative to oil shale development. The report discusses those environmental impacts
and control technologies likely to be of importance. Oil shale developers will find
Appendices D and F particularly useful; these appendices provide a discussion of
Federal, State and local laws and permits applicable to oil shale development.
1
-------
OIL SHALE RESOURCES
Charles Prien
Oil shale is commonly defined as a fine-grained sedimentary rock containing
organic matter that is essentially insoluble in petroleum solvents, but that yields
substantial quantities of oil upon pyrolysis (1). Though oil shale deposits occur
throughout the world, those in the United States are among the highest grade, most
extensive, and best explored.
U.S. oil shales (Figure 1-1) occur in four general locations: (a) the Tertiary
period (Eocene) deposits of the Green River Formation in Colorado, Utah, and
Wyoming; (b) the late Devonian and early Mississippian period marine shales of
the central and eastern United States, stretching from Michigan and Pennsylvania
southward through Indiana and Kentucky to Texas; (c) the early Cretaceous and
upper Triassic marine shales in Alaska; and (d) the small Tertiary shale deposits of
Montana, Nevada, Idaho, and California. Estimates place total known U.S. oil
TT n ,
-f-ft
Explanation
Tertiary deposits: Green River Formation in Colorado, Utah, and Wyoming, Monterey Formation,
California; middle Tertiary deposits in Montana Black areas are known high-grade deposits.
Mesozoic deposits: Marine shale in Alaska.
Permian deposits Phosphoria Formation, Montana.
Devonian and Mississippian deposits (resource estimates included for hachured areas only).
Boundary dashed where concealed or where location is uncertain.
Figure 1-1. Principal United States Oil Shale Deposits. (Source: Reference 2)
-------
shale resources in place, for oil shales yielding 42 I/tonne (10 gal of oil per ton of
shale), at well over 270 billion tonnes or 2 trillion barrels (bbl) (2). The Green River
Formation oil shales of the western United States accounts for an estimated 90 per-
cent of this total resource, or some 250 billion tonnes (275 billion tons), and are
thus generally regarded as being the most important commercially.
The Devonian marine black shales of the central and eastern United States are
estimated to contain at least 54 billion tonnes, or 400 billion bbl of equivalent oil in
place, but they are not currently considered to be commercially attractive. The
Alaskan marine shales and the Tertiary shales of California and elsewhere have
received little attention to date and are likewise not considered to be commercially
attractive.
Green River Formation Oil Shale
Description of Resources—
The oil shale deposits of the Green River Formation occur in a 44,000-km3
(16,988 mi-) area in northwestern Colorado, northeastern Utah, and southeastern
Wyoming (Figure 1-2). Total identified shale oil resources in place, which average
63 L tonne (15 gal/ton) or more in strata up to 600 m (2,000 ft) thick, are estimated
to be 163 billion tonnes (179 billion tons) in Colorado's Piceance Creek Basin, 44
billion tonnes (48 billion tons) in Utah's Uinta Basin, and 44 billion tonnes (48
billion tons) in the combined Green River, Washakie, and Sand Wash basins of
Wyoming (Table 1-1"). The three-state total is thus 251 billion tonnes (1,842 billion
bbl).
The total in-place resource is not presently recoverable, but it is estimated by the
U.S. Geological Survey (USGS) that approximately 80 percent of the known shale
that yields 104 I/tonne (25 gal/ton) or more, or some 80 billion tonnes (88 billion
tons) of shale oil are frequently located and of adequate thickness to be reasonably
regarded as the potentially recoverable resource base. Different development
TABLE 1-1. TOTAL IN-PLACE SHALE OIL RESOURCES OF THE GREEN
RIVER FORMATION"-"
Type of shale (yield / tonne)
62.6
I tonne
(15 gal ton)
Location
Colorado
Utah
Wyoming
Total
or
Billions
of
tonnes
163.2
43.7
43.7
250.6
more
Billions
of
equivalent
barrels
of oil
1,200
321
321
1,842
104.
(25
3 I tonne
gal /ton)
or more
Billions
of
tonnes
82.6
8.7
8.2
99.5
Billions
of
equivalent
barrels
of oil
607
64
60
731
125.2
I /tonne
(30 gal/ton)
or
Billions
of
tonnes
48.3
6.8
1.8
56.9
more
Billions
of
equivalent
barrels
of oil
355
50
13
418
3 Source; Reference 3.
b tn beds at feast 3m (IDft) thick.
-------
JDAHO
UTAH
LEGEND
l*?%:'JArea of oil shale d
ihcolile
or Iro
[jH^?] Area of m
deposits
^ffj Area of 25 gol. /Ion or richer
oil shole 10ft. or more thick
D Oil shale lease tracts
Figure 1-2. Green River Formation oil shale deposits. (Source: Reference 2)
schemes would result in various recovery percentages from this resource base. If 50
percent of the 104 I/tonne (25 gal/ton) or more resource could be recovered, it
would be large enough to produce 270,000 tonnes/day (2 million bbl/day), or one-
fourth the present daily imports, for more than 400 years. Table 1-1 shows that 80
to 85 percent of the in-place, 104- to 125-1/tonne (25- to 30-gal/ton) oil shale
resources are in Colorado's Piceance Creek Basin, with the remainder divided be-
tween Utah's Uinta Basin and Wyoming.
Resource Ownership—
Oil shale ownership is summarized in Table 1-2. Oil shale resources occur on 4.5
million hectare (ha) (11 million acres) of land in the three-State Green River Forma-
tion oil shale region. Approximately 72 percent of this land is Federally owned and
administered by the U.S. Department of the Interior (DOI). This Federal land con-
tains 79 percent of the total in-place resource. The remaining 28 percent of the oil
shale land is owned by the State, private individuals, and American Indians. This
non-Federal land contains 21 percent of the total in-place resource. Of the total in-
place resource of 252 billion tonnes (1,842 billion bbl), 65 percent is located in Col-
-------
orado, 17 percent in Utah, and 17 percent in Wyoming. Of the 389 billion barrels
of in-place resource on non-Federal lands throughout the region, 54 percent is in
Colorado, 17 percent in Utah, and 29 percent in Wyoming.
Numerous legal proceedings are currently pending that cast doubt on title to oil
shale lands, particularly in Colorado and Utah. As the various cases are decided in
future years, overall ownership percentage will no doubt change.
One of the most significant cases at present concerns ownership of some 64,000
ha (157,000 acres) of oil shale land in Utah, an area that includes Federal lease
tracts U-a and U-b. The state of Utah sued the DOI for title to these lands to com-
plete the state's acquisition of lands pursuant to legislation which led to statehood.
Federal courts at the district and appellate levels have ruled in favor of Utah, but
the Federal Department of Justice has appealed the case to the U.S. Supreme
Court. Thus a final decision is not expected until sometime in 1980.
The other principal type of pending litigation concerns title to hundreds of un-
patented oil shale mining claims. Some of these cases have been underway for
nearly 20 years. Specific details differ, but each case essentially involves private
party or company attempts to obtain outright ownership of numerous claims
originally staked under the 1872 Mining Law. The Department of the Interior has
contested most of these claims on grounds varying from failure to perform assess-
ment work to lack of discovery of valuable minerals. All unpatented mining claims
are included in the Federal lands columns in Table 1-2.
Stratigraphy and Mineralogy—
A knowledge of the general stratigraphy and mineralogy of the Green River For-
mation is important for an understanding of both the mining and surface process-
ing of the oil shale resource and associated minerals, and of problems that may be
encountered during in situ processing. The following description is based largely on
the Piceance Creek Basin, since it contains more than 80 percent of the commer-
cially attractive Green River Formation oil shale.
A continuously identifiable zone of 104 I/tonne (25 gal/ton) or more of Green
River Formation, shale extends throughout all three States. It is known as the
Mahogany Zone in Colorado and Utah, and the Le Clede bed in Wyoming. The
zone averages a thickness of some 30 m (100 ft) in Utah and Colorado, but less in
Wyoming. In many places the zone is exposed at the surface in easily accessible
escarpments, but in other locations it is covered by overburden varying in thickness
from a few to several hundred meters. Below the Mahogany Zone in the central
portion of the Piceance Basin, there are seven additional shale-bearing zones
(called R-6 through R-0, in order of descending depth) totaling 330 to 400 m (1,100
to 1,300 ft) in thickness. Zones R-6 through R-2, together with the Mahogany
Zone, constitute the complete Parachute Cseek Member of the Green River Forma-
tion. Zones R-l and R-0 are in the Garden Gulch.
The R-6 zone roughly corresponds to what is frequently referred to as the
"leached zone," an aquifer of saline water. The R-5 and R-4 oil shale zones com-
monly contain bedded and/or disseminated nahcolite (sodium bicarbonate). Zone
R-5 downward through zone R-2 also normally contain dawsonite (a sodium
aluminum hydroxy carbonate). Below the Parachute Creek Member, the shale
bearing zones R-l and R-0 continue into the Garden Gulch and Douglas Creek
members of the Formation. Below zone R-0, the shale beds become too lean to be
of any significance.
Green River oil shale consists essentially of dolomite, calcite, illite, and quartz,
plus a solvent-insoluble organic material called kerogen. A typical composition of
Mahogany Zone oil shale is shown in Table 1-3. The mineralogy is basically consis-
tent throughout the Basin, except for 1,300 km2 (500 mi2) in the central part of the
Basin (Figure 1-2), where substantial quantities of saline minerals (nahcolite, halite,
and dawsonite) are present, in contrast to their virtual absence along the periphery
of the Basin.
-------
TABLE 1-2. GREEN RIVER FORMATION OIL SHALE OWNERSHIP3
Colorado
Item Federal Non-Federal3 Total
Amount of land:
Thousands of hectares
Thousands of acres 1
As % of total
As % of total Federal
or non-Federal
Amount of in-place resource:
Billions of tonnes
Billions of barrels
As % of total
As % of total Federal
or non- Federal
570
,400
13
18
d
135
990
53
68
160
400
4
13
29
210
12
54
730
1,800
16C
-
164
1,200
65
—
Utah
Federal Non-Federal Total
1,540
3,800
35
48
35
254
14
18
445
1,100
10
35
9
67
4
17
1,985
4,900
45
—
44
321
17°
-
Wyoming
Federal Non- Federal Total
1,090
2,700
25
34
28
209
11
14
650
1,600
15
52
16
112
6
29
1,740
4,300
39C
-
44
321
17
-
Federal
3,200
7,900
72
100
198
1,453
79
100
Total
Non-Federal Total
1,255
3,100
28
100
54
389
21
100
4,455
11,000
100
100
252
1,842
100
100
a Source: References 3 and 4.
Non-Federal land includes private. State, and Indian lands.
c Figures do not add because of rounding.
" Resource expressed as in-place oil shale assaying 63 I/tonne (15 gal/ton) or more, at least 3 m (10 ft) thick.
-------
TABLE 1-3. TYPICAL COMPOSITION OF 104-l/TONIME
GREEN RIVER FORMATION OIL SHALE8
Constituent Wt.%b
Kerogen:
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Inorganic Minerals
Dolomite
Calcite
Quartz
Illite
Albite
K Feldspar
Pyrite
Analcime
14
80.5
10.3
2.4
1.0
5.8
86
32
16
15
19
10
6
1
1
a Source: References 5 and 6.
b Note: All percentages on dry basis.
Six principal stratigraphic units are usually identified (see Figure 1-3). They are
as follows: (1) an overburden layer, the Uinta Formation, which is comprised
mainly of quartz-bearing sandstones and siltstones with minor dolomitic marlstone
and is overlain by alluvium in valleys dissecting the Formation; (2) the Upper Part
of the Parachute Creek Member of the Green River Formation, which is comprised
of oil shale containing the minerals dolomite, calcite, quartz, and albite, and
together with the Uinta Formation forms the "Upper Aquifer"; (3) the Mahogany
Zone of the Parachute Creek Member, containing moderate-to-high grade oil shale
and generally exhibiting very low permeability except in areas of intense fracturing;
(4) the leached zone of the Parachute Creek Member which is comprised of oil
shale devoid of most saline minerals and encompasses the "Lower Aquifer" and
associated saline waters; (5) a saline zone which, in addition to oil shale, contains
halite, nahcolite, and dawsonite; and (6) the Garden Gulch zone of low-to-
moderate grade oil shale with low permeability.
The oil shales of the Uinta Basin are stratigraphically similar to those in the
Piceance Creek Basin, although the oil shale strata are leaner, thinner, less con-
tinuous, and do not contain commercially attractive quantities of saline minerals.
The highest grade of oil shale in the Uinta Basin is located in the east-central por-
tion near the Colorado border (Figure 1-2), where the deposit attains a maximum
thickness of approximately 185 m (600 ft) and contains interbedded intervals with
oil yields as high as 200 I/tonne (50 gal/ton). The range in overburden thicknesses
in the Uinta Basin are comparable to those in the Piceance Basin.
In the Green River Basin of Wyoming, oil shale occurs in thin and geographically
widely dispersed beds distributed in the Tipton, Wilkins Peak, and Laney members
of the Green River Formation. The Wilkins Peak Member contains thick, commer-
cially exploitable beds of trona. In the Washakie Basin, oil shale occurs primarily in
the Laney Member, with leaner and thinner shales in the Tipton Member. The
shales in the Sand Wash and Great Divide basins are too poor to be commercially
significant.
-------
Geologic
Unli
Valley alluvium
0' - HO'
Ulnlu Formation
0' - mo-
Green River
Formation
Wasutch
Formation
Unit
subdivisions
"
£
Is
0-
Ife
•6X
Upper Pan
Parachute Creek
Member
Mahogany
touched
400 e
Hlgh-rosls-
tlvltyor
saline zone
Garden Gulch
0' - MO1
Douglut Creek
0' - 800'
Anvil Polnls
member
O1 - 1670'
Llthologlc
description
Sand, gravel, cluy
Mainly sandstone and
sllistone with minor
amount! of low-grade
oil shale and barren
marlstone.
Low -to -high-grade
oil sliAle
Moderate -to-high-
grade oil shale
Low-to high-grade
oil shale.
Saline minerals and
moderate-to high-
grade oil shale.
Mainly clayey shale
und low- to-moderate -
grade oil shale.
Mainly wnditone
with minor amount}
ol limestone.
Shale, sun d it one,
morlstonc.
Hydrologic
unit
Alluvial
aquifer
Upper
aquifer
Aquliard
Lower
aquifer
Aqullurd
Aqulturd
Minor
aquifer
Minor
nqulter
Aqultard
Water -yielding properties
Limited In or cat extent and
thickness. 1,500 gpm maximum
Well yields about 100 gpm.
locally more where
unit li fractured
TDS from 2M to 1800 ppm.
Thickest In southern portion
of Piceance Creek Basin
Low permeability. Limited
percolation through vertical
fractures IB Important In
regional ground water flow,
Bent developed In north central
purl of basin. Confined aquller.
Well* may yield 1000 gpm. About 2,000
ppm TDS near edges to 1*5,000 TDS
near center.
Relatively impermeable.
Relatively Impermeable.
Relatively Impermeable
About 350 gpm well yields.
TDS from 1,000 to 12,000 ppm.
Relatively Impermeable
Relatively Impermeable.
Figure 1-3. Detailed stratigraphy of Green River Formation.
Various trace elements have been identified as being associated with Green River
Formation oil shale. A selected list of typical elements and their concentrations,
found in various locations in the Piceance Creek Basin are provided in Section 3
under Trace Elements. Attention is directed particularly to the amounts of
fluorine, boron, arsenic, and molybdenum present.
Regional Description—
The 44,000-km2 (17,000-mi2) oil shale region of Colorado, Utah, and Wyoming
(Figure 1-2) is a semiarid land receiving 18 to 50 cm (7 to 20 in.) of precipitation an-
nually. Elevation ranges from 1,500 to 3,000 m (4,920 to 9,840 ft) within the high
plateaus of the Upper Colorado River Basin and the equally high plains of Wyom-
ing. The region is characterized by sparse vegetation, immature soils, and stark
topography. The terrain varies from deeply dissected wooded plateaus bordered by
high oil shale cliffs to poorly vegetated plains with low escarpments. The oil shale
deposits are located in large, well-defined topographic basins with distinctive sur-
face drainage: the Piceance Basin in Colorado, the Uinta Basin in Utah, and the
Green River, Washakie, and Sand Wash basins in Colorado and Wyoming. The en-
tire region lies within the Upper Colorado River Basin and is drained by the Col-
orado River and its tributaries.
Most of the region's precipitation is received as snow during the winter months
(December through April). Rain occurs intermittently during the summer, often as
storms of high intensity. Precipitation varies with elevation, increasing approxi-
mately 8 cm (3 in.) for each 500-m (1,640-ft) increase in elevation above 300 m (984
ft)—hence, the wide range for precipitation mentioned earlier.
-------
Temperatures may reach 38 °C (100 °F) during midsummer at lower elevations,
and as much as -34 °C (-29 °F) at the higher elevations during winter, with 50 to 125
frost-free days annually. Wind patterns vary in the Piceance and Uinta basins,
being generally westerly during the day with drainage winds down the canyons and
gullies at night. Mild temperature inversions are common in the Piceance and Uinta
basins.
Existing air quality throughout the oil shale region is generally acceptable.
Ambient concentrations of sulfur dioxide, nitrogen oxides, hydrogen sulfide, and
carbon monoxide are very low. In both the Piceance and Uinta basins, however,
natural concentrations of particulates, total oxidants (measured as ozone), and
nonmethane hydrocarbons occasionally exceed the National Ambient Air Quality
Standards (NAAQS), even in the absence of any significant activity at present.
Population density is low, averaging about 3 persons/km2 (1 person/mi2)
throughout the entire region but considerably lower in many large areas of the
region. For example, it was reported in 1967 that a 6,500-km2 (2,510 mi2) area in
the southeast portion of the Uinta Basin had a population of only 250, or a density
of only 0.04 persons/km2 (.015 persons/mi2). Total population in the entire region
is about 120,000, of which 62 percent are in Colorado, 17 percent in Utah, and 21
percent in Wyoming. Major communities include Grand Junction, Rifle, Meeker,
Craig, and Rangely in Colorado; Vernal, Utah; and, Green River and Rock Springs
in Wyoming. The region's economy is currently based on agriculture (cattle and
sheep ranching), petroleum and other mineral production (oil, gas, uranium,
trona, and coal), and tourism.
Piceance Basin—The Piceance Basin in Colorado is a structural entity wherein
groundwater moves from recharge areas at the margins and along the Piceance
Creek and Parachute-Roan Creek Divide to discharge areas in the northeastern
part of the basin and along the Southern outcrop by way of secondary permeability
(mainly fractures and joints). Elevations vary from 1,600 m (5,200 ft) along the
White River on the north to 2,740 m (9,000 ft) on the south. The northern part of
the basin is drained by Piceance and Yellow Creeks, both of which discharge into
the White River, which joins the Green River in Utah. The southern part of the
basin is drained by Parachute and Roan Creeks which flow into the Colorado
River.
Groundwater accounts for about 80 percent of the annual water discharge from
the basin. Total dissolved solids in the groundwater varies from about 250 mg/1
(2.09xlO-3 Ibs/gal) in the Upper Aquifer to 63,000 mg/1 (0.525 Ibs/gal) in the
Lower Aquifer. Sagebrush, serviceberry, scrub oak, pinyon, juniper, mountain
mahogany, and other shrubs dominate the vegetation, except for cultivated areas
of alfalfa and other crops on valley floors.
Uinta Basin—The Uinta Basin encompasses some 17,200 km2 (6,650 mi2) in Utah
and 900 km2 (350 mi2) in Colorado, and is separated structurally from the Piceance
Basin by the Douglas Creek Arch. Elevations vary from 3,000 m (9,840 ft) atop the
Roan Cliffs on the basin's southern boundary to 1,310 m (4,300 ft) on the valley
floor of the Green River, 29 km (18 mi) northwest of the Roan Cliffs. The basin
contains deposits of gilsonite, natural gas, petroleum, and tar sands, in addition to
oil shale.
Groundwater in the Uinta Basin ranges from fresh (350 mg/1 or 2.92x10-' Ibs/gal
total dissolved solids) to briny (72,000 mg/1 or 0.60 Ibs/gal), but supplies are much
more limited than in the Piceance Basin. The Green River flows from the northeast
to the southwest through the region, cutting through the major oil shale deposits.
The White River flows westward from Colorado and joins the Green River near
Ouray, Utah.
-------
The basin is semiarid, with 18 to 38 cm (7 to 15 in.) of precipitation annually, 45
percent of which is received as snow. Desert shrub, salt desert shrub, pinyon
juniper, and sagebrush dominate the vegetation. The terrain is deeply dissected and
therefore difficult to traverse.
Wyoming Basins—Oil shales in the Green River and Washakie Basins of Wyom-
ing are leaner and less continuous than in either Colorado or Utah. Oil shale in
Wyoming occurs over an extensive area of approximately 23,300 km2 (9,000 mi2),
bounded on the west by the Wasatch Mountains, on the north partly by the Wind
River Range, on the east by the Medicine Bow Range, and on the south by the
Uinta Mountains. Elevations range from 1,500 to 2,450 km (4,920 to 8,000 ft).
Hills and ridges frequently have a steep incline on one side and a gently facing slope
on the other. Drainage in the area flows into the Green River and the Big Sandy
River. Dissolved solids in surface streams range from 150 to 855 mg/1 (1.25x10"' to
7.13xlO~3 Ibs/gal). Groundwater quality in the region varies from 450 to 7,000 mg/1
(3.75xlO'3 to 5.84xlO~2 Ibs/gal); it occurs primarily in the Laney Member of the
Green River Formation, but also in the Bridger, Wasatch, and Fort Union Forma-
tions.
Principal types of vegetation include sagebrush, mountain shrub, juniper,
greasewood, and salt desert shrub. The climate is semiarid, with 18 to 53 cm (7 to
21 in) of precipitation annually, mostly as snow. Temperature ranges are extreme,
from -40° to 32°C (-40° to 90°F), with 50 to 120 frost-free days. High winds are
typical of the region.
Devonian Shales
The vast deposits of the western Green River Formation lacustrine oil shale have
long diverted attention from the black marine shales of the Mississippian/Devo-
nian periods in the Eastern and Central States. These shales, part of an original
shallow inland sea, occur over an area of more than 1 million km2 (400,000 mi2) in
Ohio, Kentucky, Tennessee, Indiana, Michigan, Alabama (the Appalachian, Illi-
nois, and Michigan basin areas), and even extend as far southwest as Oklahoma
and Texas.
Description of Resources—
The thickness of black shale deposits varies, but it is seldom more than 60 m (200
ft). Strata are exposed at the surface in portions of the Appalachian, Illinois, and
Michigan basins, but gradually dip to the west to a depth of some 915 m (3,000 ft).
Some of the deposits in the 400,000-km2 (160,000-mi2) Appalachian Basin are
associated with significant quantities of potentially recoverable natural gas. Other
deposits, such as the Antrim Shale of Michigan, are being investigated as potential
candidates for in situ gasification.
The Devonian shales are lean by western shale standards, with an average Fisher
assay of only 42 I/tonne (10 gal/ton); however, the carbon content of Devonian
shales is typically about 14 percent, or approximately the same as Green River shale
assaying 125 I/tonne (30 gal/ton). The difference in Fischer assay is due to the
higher carbon to hydrogen weight ratio of the 42-1/tonne Devonian shale (11.2 to 1)
as compared with the 125-1/tonne Green River shale (7.2 to 1). If, however, the
42-1/tonne Devonian shale is retorted in the presence of hydrogen (i.e. hydro-
retorted), oil yield can be increased to 104 I/tonne (25 gal/ton), according to
research conducted by the Institute of Gas Technology (IGT) (7).
The higher oil yields possible with hydroretorting can, of course, have an in-
fluence on defining the Devonian shale resource base. The USGS estimate of
equivalent oil in place in Devonian shales is 54 billion tonnes (400 billion bbl),
without considering the effect of hydrogen in retorting. With hydroretorting, this
value could easily increase to 136 billion tonnes (1 trillion bbl), or 250 percent of
conventional Fischer assay.
10
-------
The Institute of Gas Technology has surveyed the three principal Devonian shale
basins (Appalachian, Illinois, and Michigan) and estimated that some 58 billion
tonnes (423 billion bbl) of oil could be recovered from the 16,000 km2 (6,200 mi2)
of outcrops and relatively shallow deposits in these basins alone if hydroretorting
were employed. Their criteria for a recoverable resource required that a shale
deposit have an organic content of more than 10 percent by weight, a unit rock
thickness of at least 3 m (10 ft), an overburden thickness of less than 60 m (200 ft),
and a stripping ratio of less than 2.5 to 1. The study assumed hydroretorting yields
of 85 percent of the organic carbon present, and strip mining at 90 percent recovery
of in-place shale.
Stratigraphy and Mineralogy—
The stratigraphy and mineralogy of Devonian shales has not been completely ex-
amined. The rock matrix is primarily illite, with little mineral carbonate (0.5 per-
cent) compared with Green River shale (48 percent). Many Devonian shale deposits
contain small amounts of uranium, vanadium, and phosphates.
The Antrim shales of Michigan have probably been studied as much as any of the
Devonian shales. Humphrey and Wise (8) have described Antrim shale as a very
fine-grained, dense (2,323 kg/m3, 145 lb/ft3), impermeable, laminated structure
composed primarily of illite (45 percent), quartz (30 percent), mineral carbonates (5
percent), pyrite (5 percent), miscellaneous mineral (5 percent), and organic material
(10 percent) as a finely dispersed amorphous binder. Fischer assay oil yields range
from 8.3 to 62.6 I/tonne (2 to 15 gal/ton).
Because the Devonian shales are largely located in highly industrialized areas of
the United States, interest in their potential as an energy resource is higher than
might otherwise be the case. Current research programs are aimed at investigating
both in situ and aboveground retorting of Devonian shales, and also at procedures
for stimulating and recovering associated natural gas.
Other Shales
Among other U.S. shale deposits are the thin strata of carbonaceous shales
associated with coal beds, particularly in the Appalachian coal region. It is
estimated that perhaps 8 billion tonnes (60 billion bbl) of equivalent oil may be
present there hi high grade shales assaying from 104 to 417 I/tonne (25 to 100
gal/ton). In California, the Miocene marine shales are believed to constitute a
10-biEion tonne (70-billion bbl) resource in shales varying from 21 to 1041/tonne (5
to 25 gal/ton). In southwestern Montana, beds of Permian black shale, ranging
from 21 to 63 I/tonne (5 to 15 gal/ton), may total up to 1.4 billion tonnes (10
billion bbl) of equivalent oil in place. As with the Appalachian coal shales,
however, neither the Alaskan, Californian, nor the Montana shale are considered
to be of near-term commercial importance (2).
CURRENT STATUS OF INDUSTRY DEVELOPMENT
Charles Prien
The two general methods for the production of oil or gas from oil shale are: (a)
mining followed by surface retorting and (b) in situ processing. Both are under ac-
tive investigation at the present time. Surface retorting may foEow either
underground room-and-pillar mining or other underground mining methods, or
open pit mining.
In situ processing, in which the majority of a target oil shale zone is retorted in
place, may be true in situ or modified in situ. True in situ consists of hydraulically
and/or explosively fracturing shale in place to create permeability for retorting. In
modified in situ procedures, a portion of the shale (perhaps 15 to 40 percent) is
mined and removed to the surface, while the remaining shale in place is explosively
rubblized to fill the void created by mining. The result is, in effect, an underground
11
-------
rubblized to fill the void created by mining. The result is, in effect, an underground
retort filled with fragmented oil shale with a void volume and permeability ade-
quate for retorting.
A brief summary of mining and retorting activities and current project status is
presented in the following pages. Most of the discussion concerns development of
Green River Formation oil shale in Colorado, Utah, and Wyoming. Particular at-
tention is given to the individual field programs where experimental and commer-
cial activities are now scheduled through 1985. Overall project schedules are sum-
marized in Figures 1-4 and 1-5. Technical details of the processes mentioned are
described in greater depth in Section 7.
Mining and Surface Retorting
Industry and government research and development concerning U.S. oil shales,
primarily during the past 30 years, has led to a processing sequence most often in-
volving room-and-pillar underground mining. Commercial-scale room-and-pillar
mining of oil shale has been demonstrated by the U.S. Bureau of Mines (USBM)
and Paraho Development Corporation at Anvil Points near Rifle, Colorado, and
by Colony Development Operation, Union Oil Company, and Mobil Oil Corpora-
tion on their respective properties along Parachute Creek north of Grand Valley,
Colorado. Though these mines were not intended to produce oil shale in quantities
sufficient to feed commercial-scale retorting complexes, they are nevertheless
commercial-scale in all other respects, in that full-size rooms and pillars were
created by full sized equipment. In all of the existing demonstration mines, access
to target oil shale intervals has been gained via horizontal access tunnels (adits)
along cliff faces. Although this is possible at the southern edge of the Piceance
Basin where the oil shale deposit terminates in an abrupt escarpment, access at
other margins and in the interior of the basin would have to be by vertical or in-
clined shaft.
In room-and-pillar mining, a series of rooms is created underground, with 25 to
45 percent of the interval left in place as pillars for roof support. In the USBM
mine, for example, rooms and pillars are squares, 18.3 m (60 ft) on a side; total
room height is 22.3 m (73 ft) in two levels of 11.9 m (39 ft) and 10.4 m (34 ft). Pillar
and room dimensions, and thus percent recovery of in-place oil shale, are functions
of the thickness of overburden present at a given site. Because oil shale is a very
competent rock, little or no surface subsidence is expected during the life of the
mine from well designed room and pillar mining.
Groundwater might pose problems in some locations, but more data are still
needed to determine the exact nature of these potential problems. As mine develop-
ment progresses at a given site, a point could be reached where as much as 70 to 85
percent of the spent shale resulting from surface retorting could be returned to the
mine. This would further reduce the possibility of surface subsidence, would
reduce the amount of spent shale disposal required at the surface, and might pro-
vide for additional resource recovery.
While open pit oil shale mining has been proposed for certain locations in the
Piceance Basin, it has not yet been demonstrated. The technology, however, would
be basically the same as that employed in open pit copper mining. Open pit mining
would result in greater resource recovery than underground room and pillar min-
ing, unless restricted to a very small surface area.
Surface oil shale technology was initiated over 60 years ago. Much of the early
work came on the heels of World War I. In 1925, at least 28 pilot plants were
operating in Oregon, California, Utah, Colorado, Montana, Kentucky, Penn-
sylvania, and New York. By 1930, all of these operations had ceased. Renewed in-
terest in oil followed World War II and for the most part provided the atmosphere
which led to the development of five surface retorting processes which have been
developed to a stage of potential industrial scale-up on Green River Formation Oil
12
-------
PROJECTS UNDERWAY ACCORDING TO SCHEDULES SHOWN
PROJECT
C-.
MOD. DCV. PNS.
COHM. OIV. PHS.
C-b
MOO. OCV. PHS.
COMM. DCV. PHS.
1678
1979
CONST.
19SO
I
1981
1982
1983
1984
198S
1986
OPERATION J
1987
1988
| MINE 4 FACILITY CONST | OPERATION
PREPRODUCTION MINING |
I
tiHS-
| OPERATION ]
IRETC
RT WIN
NO 1
:ONST.
OPEH
ATION <
PROJECTS HAVE NOT STARTED, BUT WOULD FOLLOW
GENERIC SCHEDULES SHOWN
YEARS FROM START
PROJECT
U-«/U-b
SINGLE RETORT
COMMERCIAL
COLONY
UNION
SUPERIOR
TOSCO SANP
WASH
MULTI-MINERAL
|_1
2
3
4
S
6
MINE DEVELOPMENT | MINING
| CONSTRUCTION | RETORT OPERATION
I
7
8
9
10
1 1
MINING ;
CONSTRUCTION | OPERATION
CONSTRUCTION | OPERATION
CONSTRUCTION | OPERATION ;
CONSTRUCTION | FULL SCALE OPERATION \
CONST
IUCTION
MODULE TESTING
OPERATION ^
, CONSTRUCTION
OPERATION ^
Figure 1-4. Project schedules for commercial oil shale projects.
Shale. These are: The Oil Shale Corporation (TOSCO) II and Lurgi Ruhrgas proc-
esses, which employ recycled hot solids for heating; the Paraho Direct Mode proc-
ess, a gas combustion type process in which heat is furnished by an internal com-
bustion zone within the retort; and the Union B Retort and Superior Oil processes,
which have external, fuel-fired furnaces as heat sources.
The TOSCO II process has been tested at a throughput capacity of some 900
tonnes/day (1,000 ton/day) at the Colony semi-works plant on Parachute Creek,
and the Paraho process has been operated at a capacity of 365 tonnes/day (330
ton/day) at Anvil Points. Both could be considered amenable to early scale-up to
commercial modules of as great as 9,000-tonne/day (10,000-ton/day) capacity.
This is also true of the Union B retort, which is based on an earlier retort design; a
1,100-tonne/day (1,210-ton/day) retort of the earlier design was successfully
operated 20 years ago at Union property on Parachute Creek.
A Lurgi Ruhrgas pilot plant of 14.5- to 22.7-tonne/day (15.6- to 25.0-ton/day)
nominal capacity has been used in West Germany to process Colorado shale, and
based on that experience, a 3,600-tonne/day (3,960-ton/day) demonstration unit
has been designed. Superior Oil Company has operated a 2,200-tonne/day
(2,420-ton/day) pilot plant in Cleveland and has proposed a 2,200-tonne/day
(2,420-ton/day) commercial plant.
13
-------
PROJECT
1978
1979
1980
1981
1982
OCCIDENTAL OIL
SHALE
GEOKINETICS, INC
EQUITY OIL
DOW CHEMICAL
LARAMIE ENERGY
TECHNOLOGY
CENTER
BURN RETORT *«
DRILL, BLAST, RETORT
6-6 RETORTS (80X30'X80')
zss
OPERATE
RETORTS 74 8
DRILL, BLAST, RETORT
2-3 CLUSTER RETORTS
SITE EVALUATION EXPERIMENTAL STARTUP I PHAaE ,
ft DRILLING STEAM INJECTION | PM*3E z
IN SITU WELL TESTING EXPERIMENTAI^
IN MICHIGAN ANTRIM SHALE BURN S
IN SITU FIELD RESEARCH AT ROCK SPRINGS, WYO.
Figure 1-5. Project schedules for field test oil shale projects.
In addition to these five processes, a 0.9-tonne/hour (1.0-ton/hour)
hydrogasification pilot plant has been operated for several years by the Institute of
Gas Technology in Chicago. The unit has been operated on both Green River and
Devonian shales.
In Situ Processing
The retorting of oil shale in situ has always been an attractive alternative to sur-
face retorting since it eliminates the need for: the construction and operation of a
large surface retorting facility; other attendant facilities such as crushing, handling,
and oil shale feed storage systems; and, the material handling and surface disposal
of spent shale. Depending on market conditions for product shale oil from in situ
processing, on site upgrading facilities could be required.
In situ processing generally falls into one of two categories: True (borehole) in
situ or modified in situ. True in situ generally involves the drilling of injection and
production holes from the surface into the oil shale strata to be retorted. These
holes are also used to fracture (hydraulic and explosive) and create permeability in
the oil shale. Other variations include using the injection and production holes to
inject fluids for the dissolution of soluble saline minerals. Once permeability is
established, hot fluids or fire fronts are passed from injection wells to production
wells where the retorted product shale oil is pumped to the surface. Modified in situ
differs from true in situ in that mining is utilized to remove a volume of the oil shale
(perhaps 15 to 40 percent). The remaining oil shale in-place is explosively expanded
(rubblized) into the void created by the mining. In effect, an underground vertical
or horizontal retort is prepared through which hot fluids or a fire front may be
passed to produce shale oil.
14
-------
Research along the line of true or borehole in situ was initiated by private in-
dustry 26 years ago. Field tests were performed by Sinclair Oil and Gas Company in
1953-54 and again in 1965. From 1965 to 1971, Equity Oil conducted tests in a
naturally fractured zone in the Piceance Basin. Between 1964 and 1970, two
nuclear in situ experiments (Project Bronco and Operation Utah) were proposed,
but never conducted. Within the past 10 years, additional in situ field experiments
have been conducted in the Piceance Basin by Mobil Oil (at shallow depth), by Ex-
xon (in lower zone shales) and by Shell Oil (with hot miscible fluids). All of these
efforts have now been discontinued.
In 1975, Geokinetics began field tests of its true in situ process at a site in the
Uinta Basin of Utah. This work is currently being conducted under a Program Op-
portunity Notice (PON) contract with the Department of Energy (DOE). Some 20
retorts have been constructed and 11 have been tested to date, all at relatively
shallow depths. Geokinetics' Retort No. 18, for example, is 55 by 48 by 5 m thick
(180 by 156 by 17 ft), with 6 m (20 ft) of overburden. Blasting and burning of two
three-retort clusters is planned from 1980 to 1982.
The Federal government became interested in true in situ oil shale retorting in the
early 1960's. A series of true in situ field experiments was begun by the U.S. Bureau
of Mines, Laramie Energy Research Center (now DOE, Laramie Energy
Technology Center) in 1965 at a site near Rock Springs, Wyoming, where
experimentation continues today. Also in 1965, the Laramie Energy Research
Center constructed a 9-tonne (10-ton) batch retort to simulate underground condi-
tions expected from the detonation of a nuclear device in oil shale. A much larger
unit, a 136-tonne (150-ton) batch retort, was constructed in 1969 for the same pur-
pose. These two retorts are still used today and over the years have provided useful
engineering data for both in situ and surface retorting research.
Modified in situ research was initiated only seven years ago. In 1972, Occidental
Oil Shale, Inc. began field experimentation of its vertical, modified in situ process
at Logan Wash near Debeque, Colorado at the southern edge of the Piceance
Basin. To date, six experimental retorts of increasing size have been rubblized and
retorted at this site, and additional tests are planned through 1982. Part of these
tests are being financed under a DOE PON contract. The Department of Energy
has recently proposed a horizontal modified in situ project at a site in Cowboy Ca-
nyon near Bonanza, Utah.
Shale Oil Production
Shale oil production over the years has been largely undocumented. Data com-
piled from literature searches and shale oil producers reveal the limited quantities
of shale oil that have been produced over the years. Table 1-4 lists various opera-
tions which have produced shale oil. Production is listed for each of the operations
in which quantity could be determined as well as shale oil disposition and number
of barrels currently in storage.
Current Project Status
In 1972, Colony Development Operation (now composed of Atlantic Richfield
Corporation (ARCO) and TOSCO) completed operations on its 900-tonne/day
(1,000-ton/day) TOSCO II semi-works plant on Parachute Creek and prepared a
design for a 6,392-tonne/day (47,000-bbl/day) commercial plant.
A final environmental impact statement for the project was approved in 1977.
Colony is now in the process of applying for the permits necessary to construct a
commercial project on their Davis Gulch site. The Environmental Protection
Agency issued a conditional Prevention of Significant Deterioration (PSD) permit
in July 1979, and Colony is awaiting approval of a State Mined Land Reclamation
Permit. Definite plans to proceed with plant construction have not yet been an-
nounced.
15
-------
In 1974, Paraho began a 3-year, industry-sponsored demonstration program on
the Paraho vertical kiln retorting process at Anvil Points. This work was completed
at the end of 1976. During operation of the demonstration plant, the U.S. Navy
signed a contract with Paraho for production of 100,000 barrels of crude shale oil
which was subsequently refined at Sohio's Cleveland refinery. Paraho has since
proposed construction of a 10,400-tonne/day (11,500-ton/day), $90 million com-
mercial module. Funding for the $3 million engineering design phase of this project
is currently being sought. Also, an Environmental Impact Study (EIS) is being
developed by the DOE.
Union Oil Company has for several years tested the Union B and steam gas recir-
culation (SGR) surface retorting processes in a 3-tonne/day (3.3-ton/day) pilot
plant in Brea, California. These are successors to Union's A retort, which was suc-
cessfully operated at a rate of 1,100 tonnes/day (1,210 tons/day) in a semi-works
plant near Grand Valley, Colorado, in 1957 and 1958. Union announced plans in
1978 for construction of a 9,000-tonne/day (10,000-ton/day) commercial module
using the Retort B design at its Long Ridge site near the location of the earlier semi-
works plant. Union hopes to begin construction during 1980 and operate the plant
through 2000. All required permits for this project have been secured, but Union
has stated that the project is contingent on approval of a $3/barrel income tax
credit.
The Superior Oil Company is continuing its efforts to exchange 1,041 ha (2,572
acres) of its private lands at the north edge of the Piceance Basin for 828 ha (2,045
acres) of adjacent Federal land to block up a more manageable tract for develop-
ment. The lands in question contain substantial quantities of sodium minerals such
as nahcolite and dawsonite. A draft EIS covering the land exchange was prepared
by the U.S. Bureau of Land Management (BLM) in July 1979. Superior proposes
to develop a 23,700-tonne/day (26,200-ton/day) multi-mineral project at the site
that would produce shale oil, nahcolite, and alumina.
The State of Utah has permitted TOSCO Corp. to unitize 5,900 ha (14,000 acres)
of noncontiguous state oil shale leases in the central portion of the Uinta Basin. In
return, TOSCO has agreed to spend a minimum of $8 million by 1984 for pre-
development activities on what is referred to as the Sand Wash Unit. Site explora-
tion, environmental monitoring, and shaft sinking are currently underway on the
unit.
On April 30, 1979, Multi Mineral Corporation (MMC), U.S. Bureau of Mines
and U.S. Bureau of Land Management signed an agreement which permits MMC
to conduct a one-year experimental mining program at the U.S. Bureau of Mines
Horse Draw Facility. The Multi Mineral Corporation has developed the Integrated
In Situ process which would produce raw nahcolite, shale oil, fuel gas, alumina,
and soda ash in one integrated operation. Upon completion of the experimental
program, MMC hopes to enter into a three-year cooperative agreement with DOE
and DOI to construct and test a full scale module of the Integrated In Situ process.
Upon successful completion of this phase, MMC would bring the plant to commer-
cial production of 4,500 to 9,000 tonne/day (5,000 to 10,000 ton/day) raw
nahcolite, 6,800 tonne/day (50,000 bbl/day) shale oil, 900 tonne/day (1,000 ton/-
day) alumina, and 4,500 to 9,000 tonne/day (5,000 to 10,000 ton/day) soda ash by
1986.
In 1974, the U.S. Department of the Interior issued Federal leases on four
2,065-ha (5,100-acre) tracts of oil shale land—Tracts C-a and C-b in Colorado and
Tracts U-a and U-b in Utah. Original lessees on the tracts were as follows: Tract
C-a, Gulf Oil Company and Standard of Indiana; Tract C-b, ARCO, Ashland Oil,
Shell Oil, and TOSCO; Tract U-a, Phillips Petroleum and Sun Oil; and Tract U-b,
White River Shale Oil Corporation, owned equally by Sun, Phillips, and Sohio.
Detailed development plans (DDP's) were filed by the original lessees in early 1976.
16
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TABLE 1-4. SHALE OIL PRODUCTION AND DISPOSITION8
Dates
May 1947-June 1951
Jan 1950-July 1955
1957-1958
Producer-
location
Bureau of Mines-
Anvil Points, CO
Bureau of Mines-
Anvil Points, CO
Union Oil Co.-
Parachute Creek, CO
Retort type
N-T-U
Gas combustion
Union A
Production
(bbls)
20,300
11,000
20,000
Shale oil disposition
Refined in shale oil refinery of
BuMines at Rifle. Products used in
passenger cars, buses, diesel trucks
and other equipment at the plant.
Residuals used on roads.
Same as above
Concurrent with mining and retorting
tests, refining tests were conducted
In storage
(bbls)
None
None
None
July 1959-Dec 1966
1962
May 1964-Sep 1967
The Oil Shale Corp/
Denver Research Inst.
Zuni Street, Denver, CO
Mobil-Rio Blanco Cty.
Colorado, Beaver Bluff
in situ project
Six Company* Group-
Anvil Points, CO
TOSCO I
In situ
(2 burns)
7,500±
23
Gas combustion 25,000
on product of retort in Brea,
California. In 1961, 15,000 barrels of
this shale oil was refined in the
American Gilsonite Co. refinery at
Fruita, Colorado and the products
marketed in the Grand Junction
area.
Some used for laboratory research None
and the remainder was incinerated.
Laboratory testing None
Distributed to six participants for None
research purposes. Final disposition None
unknown.
1 Source: The PACE Company Consultants & Engineers, Inc., 1980.
-------
TABLE 1-4. (continued)
Dates
Producer-
location
Retort type
Production
(bbls)
Shale oil disposition
In storage
(bbls)
1966-1967
1971-1972
1966-1968
1968-1971
Apr 1969-May 1970
Oct 1969 to present
1970-1972
1974-Aug 1976
*Mobil, Humble, PanAm,
Sinclair, Continental
& Phillips, with
CSMRF assistance
Colony Development
Company-Parachute
Creek, CO
Equity Oil Co.-Rio
Blanco County, CO
Equity/ARCO
Rio Blanco County, CO
Laramie Energy Research
Center (BuMines) —
Laramie, WY
Laramie Energy Research
Center (BuMines) —
Laramie, WY
Shell Oil Co. —Piceance
Creek Basin
Seventeen Company
Group-Anvil Points, CO
TOSCO II 180,000
demonstration
plant
"Bx" Experi- Unknown
mental in situ
"Bx" Experi- Unknown
mental in situ
570
In situ test
sites 4 & 7
1,000+E
150-Ton &
10-Ton
batch reports
Leaching & in 420
situ retorting
Paraho 10,000 +
Industrial fuel, incinerated, small
quantities to refinery feed.
Unknown
Unknown
Tested in laboratory and
characterized
9,956 barrels processed into NATO
gasoline, JP4, JP-5/Jet A,
DFM/DF-2and heavy fuel oil, 5756
bbls of products, by Gary Western
Refining at Fruita, CO. Products
disposed of by U.S. Navy.
20
Unknown
Unknown
Unknown
Unknown
None
Unknown
-------
TABLE 1-4. (continued)
Dates
Dec 1975 to present
Producer-
location
Occidental Oil
Shale, Inc.
Logan Wash, CO
Retort type
Modified
in situ
retorts 1-6
Production
(bbls)
99,500
and con-
tinuing
Shale oil disposition
Internal use for steam generation,
commercial boiler tests (Consumers
Power, Kalamazoo, Michigan) boiler
fuel for small refinery, Mich.
In storage
(bbls)
40,000
July 1975 to present Geokinetics, Inc.
Kamp Kerogen, UT
1976-1979
1976; 1978
1977-Sep 1978
IGT, Chicago, IL
Sunoco-Toll Processed
Brea, CA
Anvil Points, CO
U.S. Navy/Development
Engineering Corp.
Anvil Points, CO
In situ
HYTORT
(1 ton/hr.)
Union B
Paraho
Paraho
12,000 +
24.5
25
24
100,000
3,500 bbls sold to Plateau Refinery, 8,500
Roosevelt, Utah. Some used as
boilder fuel. Remainder blended with
normal feedstock refined to diesel
fuel and gasoline, marketed locally.
2.7 bbls for Air Force upgrading 21.8
tests.
Comprehensive analytical examina- Unknown
tions, rheology, crystallography, and
upgrading studies
Refined at Standard Oil Company's Unknown
(Ohio) Toledo OH, refinery under
contract to U.S. Navy for the
Department of Defense and Depart-
ment of Energy joint program.
Refine fuels distributed to various
government and contractor facilities
for testing in early 1979.
June 1979-contin.
Equity Oil Co.-
Piceance Creek, CO
In situ
None at
this time
E - estimated by Pace Rocky Mountain Division
-------
The original DDP for Tract C-a proposed an open pit mine with surface retort-
ing. For various reasons, including the nonavailability of off-tract land for solid
waste disposal, the lessees (now doing business as Rio Blanco Oil Shale Company)
submitted a revised DDP in early 1977 describing plans to use vertical modified in
situ processing on the tract rather than open pit mining. Shaft sinking and other
preparations for construction of five experimental retorts are currently underway.
The process involves removing some 40 percent of the underground void space and
retorting that on the surface using Lurgi Ruhrgas technology. A decision concern-
ing a full-scale commercial project will be made on completion of a 4-year modular
development phase program. Commercial efforts would lead to a production level
of 10,340 tonnes/day (76,000 bbl/day) by 1987.
The original lessees of Tract C-b proposed that it be developed using
underground room and pillar mining followed by TOSCO II retorting. Further
studies indicated that serious mining problems would probably be encountered.
Participation in the project subsequently changed, and in early 1977, the newly
formed C-b Shale Oil Venture (composed of Occidental and Ashland) submitted a
revised DDP outlining plan to use the Oxy modified in situ process on Tract C-b.
The schedule provided in the second DDP was further revised in 1978. In early
1979, Ashland withdrew from the project, leaving Occidental as the sole partici-
pant. However, in September 1979, Tenneco joined Occidental in the Tract C-b
venture, renamed the Cathedral Bluffs Shale Oil Company, as a 50 percent partner.
Shaft sinking for a series of retorts is currently in progress. Occidental, as operator,
and Tenneco intend to continue project development to a commercial scale of
7,750 tonnes/day (57,000 bbl/day) by 1987.
The 1976 DDP for the White River Shale Project (combined Federal Tracts U-a
and U-b) proposed the use of underground mining plus surface retorting (TOSCO
II, Union and Paraho Direct Mode processes) for development. Two clouds to
lease title, involving pre-1920 oil shale claims and an overfiling for State leases,
resulted in suspension of lease terms in May 1977 pending court resolution of the
conflicts. At present it is not known when or on what basis future development of
Tracts U-a and U-b will proceed.
In May 1979, the DOE issued a PON inviting proposals for the design and plan-
ning of a surface oil shale retorting demonstration module. The PON solicitation
stems from a $15 million appropriation approved by Congress in 1978. Work
resulting from any contracts awarded under the PON would not begin until late
1979. The goal of the proposed program is to demonstrate one or more surface
retorting technologies at a scale necessary to prove commercial feasibility. The pro-
gram will be composed of two phases. Phase I (approximately 18 months) will in-
clude engineering design of the commercial module and planning for Phase II.
Phase II, which is optional at this point, would include a construction period of ap-
proximately 30 months and an operating period of about 24 months. The May 1979
PON covers Phase I only. The Department of Energy will wait until completion of
Phase I before deciding whether or not to proceed with Phase II. The form of
award under the PON will be a cost sharing cooperative agreement. Planning on
the PON by DOE has been based on government/contractor cost sharing at the
rate of 50/50.
This, then, is the current (late-1979) status of industrial oil shale developments in
the United States. The technology of mining, the present major surface retorting
processes, and the in situ processes that are currently under investigation are
described in more detail in Section 7. Appendix A describes in more detail specific
plans of oil shale development mentioned herein.
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APPLICABLE FEDERAL AND STATE
POLLUTION CONTROL LAWS
Terry L. Thoem
In general, environmental legislation and regulations established by the U.S.
Congress provides a framework for State legislation and implementation of Federal
and State regulations. State legislation and regulations can be more (but not less)
stringent than Federal requirements if a State is delegated responsibility for admin-
istering the program in a given media. The Federal government retains an over-
sight/reviewing role for those programs that are delegated to the States. State
legislation in general parallels Federal legislation in form and substance. A com-
pilation of Federal and'State legislation is provided in Appendix D. The following
discussion highlights the major aspects of the legislative mandates of EPA as ap-
plied to an oil shale industry. These mandates are: to protect air and water quality,
to insure a safe drinking water supply, and to provide for an environment con-
ducive to the enjoyment of man. To accomplish these goals, EPA and the States
are involved in a partnership with State and local environmental agencies in the
planning, implementation, and enforcement of environmental policies.
Clean Air Act
Under the Clean Air Act (PL 95-95) shale developers must: (a) employ Best
Available Control Technology (BACT), (b) insure that National Ambient Air
Quality Standards (NAAQS) are not violated, (c) not violate the prevention of
significant deterioration (PSD) ambient air quality increments (40 CFR 52.21), (d)
not significantly degrade visibility in mandatory Class I areas (40 CFR 51), and (e)
obtain as much as up to 1 year of baseline data before applying for a PSD permit to
construct and operate. The BACT has been defined in the form of allowable emis-
sions limits and control device operational characteristics. Source monitoring, am-
bient monitoring, record keeping and reporting requirements are also part of the
PSD permit (40 CFR 60.7). Also EPA is authorized to request monitoring data, to
take enforcement actions, and to take administrative and judicial actions if there
are any emergency episodes of pollutants that present an imminent and substantial
endangerment to public health.
Clean Water Act
The Clean Water Act (PL 95-217) established goals of: (a) no discharge of
pollutants into navigable streams by 1985; (b) attainment by July 1, 1983, of water
quality suitable for protection and propagation of fish, shellfish, and wildlife and
for recreational use; and (c) prohibition of discharges of toxic amounts of toxic
pollutants. The Act contains requirements in Sections 402 and 404 for potential
permits for an oil shale developer. A National Pollutant Discharge Elimination
System (NPDES) permit must be obtained under requirements of Section 402 if
water is discharged to a navigable stream (defined as waters of the United States
and, in fact, could be a dry creek bed which flows during runoff). Neither effluent
guidelines (Section 304) nor New Source Performance Standards (NSPS) (Section
306) have been promulgated for an oil shale industry. However, in their absence,
NPDES effluent limits are established on a best engineering basis. A Section 404
permit must be issued by the Army Corps of Engineers and concurred upon by
EPA if any dredge and fill operations take place in a navigable stream (defined for
404 purposes as stream flow greater than 85 I/sec or 3 cfs). Section 303 of the Act
provides the mechanism for establishing water quality stream standards. Plans
developed by State Water Pollution Control Agencies must define water courses
within the State as either effluent-limited or water-quality-limited. Best manage-
ment practices (BMPs) to control nonpoint source runoff may be defined via Sec-
tions 208 and 304 (e) of the Act.
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Safe Drinking Water Act
Underground injection control (UIC) regulations proposed on April 20, 1979
(Title 40 of the Code of Federal Regulations [CFR], Part 126) and portions pro-
mulgated in the May 19, 1980, Federal Register under the Safe Drinking Water Act
will govern the injection or reinjection of any fluids. Permits (40 CFR 122.36) will
be required for in situ operations and for mine dewatering reinjection. The State of
Colorado requires reinjection permits under existing regulations. The basic thrust
of the UIC program is to require containment of reinjected fluids. Monitoring (40
CFR 146.34) and mitigation measures (40 CFR 122.42) to prevent the endanger-
ment of the groundwater system are requirements under these UIC regulations.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act (RCRA) will govern the disposal
of solid and hazardous wastes generated by an oil shale facility. Criteria for the
identification of hazardous wastes were proposed by EPA on December 18,1978 at
40 CFR 250. Final regulations were promulgated in the May 19, 1980, Federal
Register at 40 CFR 261-265. It appears that processed shale will not be considered a
hazardous waste. Instead, it will be subject to requirements at 40 CFR 257
(September 13, 1979, Federal Register). A concept of Best Engineering Judgment
will govern the disposal of hazardous wastes such as American Petroleum Institute
(API) separator sludge.
Toxic Substances Control Act
Testing of effects, record keeping, reporting, and conditions for the manufac-
ture and handling of toxic substances are defined under the auspices of the Toxic
Substances Control Act (TSCA) of 1976. A tentative inventory of all commercially-
produced chemical compounds was published in May 1979. If a substance is placed
on the inventory, it is "grandfathered" from the TSCA premarket notification re-
quirements. Ten synthetic fuels including shale oil were identified on this list of
43,000 compounds. Being on the list does not "protect" a product from possible
control requirements included in Section 8. If a material is found to be a hazard,
certain restrictions including labeling, precautionary handling requirements or even
a ban on its production may be imposed by EPA.
National Environmental Policy Act
The final piece of environmental legislation in which EPA participates and which
is relevant to the production of oil shale is the National Environmental Policy Act
(NEPA). The Environmental Protection Agency reviews, and in limited cases
writes, the EIS when a project involves a major Federal action. The Agency's role
as a reviewer is to comment on the environmental aspects of the project.
Legislation as described above normally provides a permit process mechanism.
Companies wishing to construct and operate an oil shale facility must receive a per-
mit from EPA or from the State which permits the facility to be operated. A
description of the permits required for an oil shale facility is provided in Appendix
F.
APPLICABLE FEDERAL AND STATE
POLLUTION CONTROL REGULATIONS
Terry L. Thoem
Federal and State legislation generally prescribes the establishment of National
and State environmental standards for a given media (i.e. air, water, solid waste,
etc.). Regulations designed to control emissions/effluents from an individual facil-
ity are promulgated to achieve the stated environmental standards. This section
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briefly describes this concept of standards/regulations. In almost all cases, the
standards/regulations concept requires an oil shale developer to obtain a permit to
construct and operate his facility. It is the intent of EPA to delegate the permit pro-
grams to the State. Table 1-5 summarizes the current status of these delegations for
oil shale states.
Air
Regulations to protect air quality exist in two forms—ambient air quality stand-
ards and stack emission standards. All EPA regulations are codified in Title 40 of
the Code of Federal Regulations. Applicable parts are referred to in discussions of
the various regulations below. Pursuant to Section 109 of the Clean Air Act, EPA
has established NAAQS for seven criteria pollutants (40 CFR 50). Primary stand-
ards are designed to protect public health, secondary standards (which are more
restrictive) are to protect public welfare (vegetation, materials corrosion,
aesthetics, etc.). States may also establish ambient air quality standards.
The prevention of significant deterioration of air quality concepts provided for
in the Clean Air Act is designed to protect clean air areas (40 CFR 52.21). Class I
areas include national parks larger than 2,428 ha (6,000 acres), national wilderness
areas greater than 2,023 ha (5,000 acres), international parks, and national
memorial parks that exceed 2,023 ha (5,000 acres). Areas in the United States that
presently have lower ambient air quality than that specified in the NAAQS are
designated as nonattainment areas Class III; the remainder of the United States is
designated Class II. Redesignation of Class II areas to either Class I or Class III by
the state is possible.
A second ambient air quality consideration is the visibility protection afforded to
Federal Mandatory Class I areas via Section 169A of the Clean Air Act (40 CFR
51). Regulations are to be promulgated by EPA (November 1980) and the States
(August 1981) that are designed to prevent visibility impairment in the Federal
Mandatory Class I areas. Since there are many issues to be resolved, it is too early
to delineate the potential implications of the visibility regulations. Proposed
TABLE 1-5. STATUS OF EPA REGION VIM DELEGATIONS TO OIL SHALE
STATES
Delegation to States
Type of permit Colorado Utah Wyoming
NPDES
Drinking water (UIC)
Hazardous waste (RCRA)
Construction grants
Dredge & fill permit
(Sec. 404)
NESHAP (beryllium, asbestos,
mercury and vinyl chloride)
Noise
Radiation
PSD
Yes
No
No
Yes
No
Yes8
No
No
No
No
No
No
Yes
No
Yes
No
No
No
Yes
No
No
Yes
No
No
No
No
Yes
States have partial delegations, depending on their need for authority.
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regulations appeared in the May 22, 1980 Federal Register at 40 CFR 51-300. An
EPA Report to Congress on visibility was published in November 1979.
Limitations on the amounts of pollutants emitted from an oil shale facility are
the enforceable mechanism to assure that the NAAQS and PSD increments are not
violated. The Environmental Protection Agency establishes New Source Perform-
ance Standards (NSPS) (40 CFR 60); States establish emission standards; and EPA
(or the State) must define emission limits that reflect the BACT. NSPS have not
been defined for oil shale facilities, but BACT has been defined for five oil shale
facilities via the PSD permit process. These are further described in Section 6 and
in Appendix D. Also, Colorado has an emission limitation specifically for oil shale
production and refining. Utah and Wyoming do not have oil shale-specific emis-
sion limits.
Water
Water pollution control requirements exist in the form of Water Quality
Criteria, State Water Quality Standards, Drinking Water Standards, National
Pollutant NPDES limits, and effluent guidelines. The following discussion sum-
marizes the major aspects of surface water and groundwater quality standards. A
complete discussion of the enforceable mechanism to attain these standards, that
is, the NPDES and VIC permits system, is found in Appendix D.
Surface Water Quality Standards—
Water quality standards are addressed in Section 303 (Water Quality Standards
and Implementation Plans) of the Clean Water Act. Excerpts and summaries of re-
quirements for establishment and implementation of water quality standards of
that section are presented below:
Water quality standards shall be reviewed at least every 3 years by the Gover-
nor or State Water Pollution Control Agency and shall be made available to the
EPA Administrator.
State revised or adopted new standards shall be submitted to the EPA Ad-
ministrator for approval. Such revised or new water quality standards shall con-
sist of the designated uses of the navigable waters involved and the water quality
criteria for such waters based upon such uses. Such standards shall be such as to
protect the public health or welfare, enhance the quality of water, and serve the
purposes of the Act (FWPCA). Such standards shall be established, taking into
consideration their existing or intended potential use and value for public water
supplies, propagation of fish and wildlife, recreational purposes, agricultural, in-
dustrial, and other purposes, while also taking into consideration their use and
value for navigation.
Each State shall identify those waters for which existing or proposed effluent
limitations are not stringent enough to attain established water quality standards
and establish waste load allocations for those waters. Regulations promulgated
at 40 CFR 131.11 and further discussed in the December 28, 1978 Federal
Register describe the Total Maximum Daily Load concept.
Each State shall identify those waters or parts thereof within its boundaries for
which controls on thermal discharges are not sufficiently stringent to assure pro-
tection and propagation of a balanced indigenous population of shellfish, fish,
and wildlife.
Colorado Water Quality Standards—
Water quality standards for the State of Colorado were promulgated pursuant to
Section 66-28-202 (b) and Section 66-28-204 C.R.S. 1963, as amended, and were
most recently amended by the State on January 15, 1974 to become effective June
19, 1974. The Colorado Water Quality Control Commission is in the process of
revising these standards via a document entitled Regulations Establishing Basic
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Standards and an Antidegradation Standard and Establishing a System for Classi-
fying State Waters, for Assigning Standards, and for Granting Temporary
Modifications on May 22, 1979 (effective July 10, 1979). The 1974 standards and
these 1978 regulations are the subject of litigation at the present time. Ten public
hearings are being held during 1979 and 1980, following which, the Commission
will establish stream classifications and numeric standards designed to protect a
stream's designated use. The 1974 standards entitled "Water Quality Standards
and Stream Classifications," as promulgated by Colorado, were approved by EPA
on August 13, 1974, with the exceptions stated below.
1. The salinity control policy, procedures, and requirements for establishing
water quality standards for salinity control in the Colorado River System are
those established by Federal promulgation on December 18, 1974, as set forth
in 40 CFR 120.104(b)(9). (It should be noted that the salinity litigation has
recently been decided.) A more complete discussion on salinity is found in
Appendix D.
2. In the Flow Criteria and Exceptions section of the Water Quality Standards
and Stream Classification document, EPA has excepted from its approval on
August 13, 1974, the following sentence of the Colorado Standards: "Excep-
tions on specific parameters may be allowed through discharge permits."
There are general criteria that apply to all Colorado "State Waters," one of
which is an antidegradation statement that specifies:
Waters of the State, whose quality exceeds the limits set in these standards,
shall be maintained at existing quality unless and until it can be demonstrated to
the State that a change in quality is justified to provide necessary economic or
social development. In that case, treatment to the extent necessary to protect the
current classification of such waters shall be required.
This 1974 statement has been revised in the 1978 regulations. Due to the litiga-
tion on the 1978 regulations, the 1974 standards are the ones in effect. In Colorado,
streams may be classified as one of four designations under the 1974 standards: Al,
A2, Bl, or B3. The general differentiation is between groups A and B:
Class Al or A2 waters are suitable for, or can become suitable for, customary
raw water purposes including primary contact recreation.
Class Bl or B2 waters are suitable for, or can become suitable for customary raw
water purposes except primary contact recreation.
Al and Bl relate to cold waters and A2 and B2 to warm waters. The 1978 regula-
tions changed the classification system. Streams will now be classified as: (1)
recreation (primary contact Class I and secondary contact Class II); (2)
agriculture; (3) aquatic life (Class I - cold water, Class I - warm water, and Class II-
cold water and warm water); (4) domestic water supply (Class I and Class II); or (5)
existing high quality waters (Class I and Class II). The 1978 regulations include
guidelines for four types of parameters: (1) physical and biological, (2) inorganic,
(3) metals, and (4) organics.
The Federal oil shale lease Tracts C-a and C-b are in the Colorado River
Basin/White River Sub-Basin. Potential drainage from both tracts will discharge to
the reach of the main stem of the White River from the mouth of Piceance Creek to
the Colorado-Utah State line. This reach is classified as B2. It should be noted that
Piceance Creek is presently undesignated but has been proposed to be classified
under the "aquatic life Class I - cold water" classification. Yellow Creek and most
of Parachute Creek have been proposed as "agriculture."
Utah Water Quality Standards—
The Utah Board of Health adopted water quality standards on May 19, 1965,
and amended in 1967, 1968, and most recently on October 23, 1978. The En-
vironmental Protection Agency approved the 1968 amended document entitled
25
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vironmental Protection Agency approved the 1968 amended document entitled
"Code of Waste Disposal Regulations, Part II, Standards of Quality for Waters of
the State "on December 13, 1973, with the exception:
A salinity control policy, procedures, and requirements establishing water qual-
ity standards for salinity control in the Colorado River System are those
established by Federal promulgation on December 18, 1974, as set forth in 40
CFR 120.104 (b) (10).
The Utah Water Quality Standards (Wastewater Disposal Regulations, Part II,
Standards of Quality for Waters of the State) adopted by the Utah State Board of
Health on October 23, 1978, was approved by EPA with certain exceptions. The
Agency will be promulgating standards to take the place of those identified dif-
ferences in late 1980 or early 1981. Specific areas disapproved are further discussed
in Appendix D.
In specifying Utah's water quality standards the following should be noted:
"No water quality degradation is allowable which would interfere with or
become injurious to existing instream uses "(9).
Utah further has an antidegradation policy stating:
"Waters whose existing quality is better than established standards for the
designated uses will be maintained at high quality unless it is determined by the
Committee that a change is justifiable as a result of necessary economic or social
development"(9).
Utah also has designated certain raw water sources for drinking water supplies as
"antidegradation segments."
Where Colorado has four (under 1974; five under 1978) stream classifications,
Utah has six with several subclassifications. The general differentiations in the
classifications are presented below. The White River and its tributaries are
classified as 3C and 4. Water quality standards associated with these classifications
are presented in Appendix D.
Class 1 - protected for use as a raw water source for domestic water systems.
a.Class 1A - protected for domestic purposes without treatment.
b.Class IB - protected for domestic purposes with prior disinfection.
c. Class 1C - protected for domestic purposes with prior treatment by standard
complete treatment processes as required by the Utah State Division of Health.
Class 2 - protected for in-stream recreational use and aesthetics.
a.Class 2A - protected for recreational bathing (swimming).
b.Class 2B - protected for boating, water skiing, and similar uses, excluding
recreational bathing (swimming).
Class 3 - protected for in-stream use by beneficial aquatic wildlife.
a. Class 3A - protected for cold water species of game fish and other cold water
aquatic life, including the necessary aquatic organisms in their food chain.
b.Class 3B - protected for warm water species of game fish and other warm
water aquatic life, including the necessary aquatic organisms in their food chain.
c.Class 3C - protected for nongame fish and other aquatic life, including the
necessary aquatic organisms in their food chain. Standards for this class will be
determined on a case-by-case basis. (See Appendix D.)
d.Class 3D protected for waterfowl, shorebirds and other water-oriented
wildlife not included in Classes 3A, 3B, 3C, including the necessary aquatic
organisms in their food chain.
Class 4 protected for agricultural uses including irrigation of crops and
stock watering.
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Class 5 protected for industrial uses including cooling, boiler make-up, and
others with potential for human contact or exposure. Standards for this class will
be determined on a case-by-case basis.
Class 6 - protected for use of waters not generally suitable for the uses identified
in Sections 2.6.1 through 2.6.5 above. Standards for this class will be determined
on a case-by-case basis.
The 208 Process-
Section 208 of the Federal Water Pollution Control Act (FWPCA) required
States to designate areawide waste treatment planning agencies. The Colorado
West Area Council of Governments (CWACOG) was so designated for the oil
shale area in Colorado. The Uinta Basin Association of Governments (UBAG) was
designated for Utah oil shale country. These 208 agencies are to plan, promulgate,
and implement a program designed to protect surface water quality. Stream
classifications and water quality standards are to be developed. The Colorado
Council and UBAG have submitted plans to their respective states. The UBAG 208
plan was certified by the State on November 22, 1978, and approved by EPA on
October 2, 1979. The CWACOG 208 plan is anticipated to be certified by the State
by April 1980 and approved by EPA by May 1980.
Local input in Colorado on the proposed stream use indicated a desire to assign
multiple classifications wherever possible. Although the apparent intent of the pro-
posed State classification system (1978) is simply to identify the criteria applicable
to a given stream segment, there is considerable local concern that a single "use"
classification may be used later to restrict other uses, particularly agricultural ones.
Intermittent streams have not been classified because of provisions made for this
situation in the proposed classification system.
The four combinations of multiple use classifications that are proposed for Col-
orado include:
Class 1: Aquatic Life, Water Supply, Recreation, and Agriculture
Class 2: Water Supply, Recreation, and Agriculture
Class 3: Recreation and Agriculture
Class 4: Agriculture
Proposed classifications and rationale are presented in Appendix D for the Yam-
pa, White and Colorado Rivers.
The proposed water quality standards allow exceptions under certain conditions.
Using the guidelines in the proposed criteria, the water quality data base, the pro-
posed water quality criteria, the existing water quality problems, and a subjective
analysis of potential effectiveness of potential control measures, three types of ex-
ceptions were identified for Colorado:
Permanent exception The current criterion limit is not valid for the drainage
area because of natural environmental conditions. It is assumed that, given a
return to prehistoric conditions, this parameter would still violate the criterion
limit. The parameter should be monitored regularly, and any trend of increasing
concentration would require evaluation/investigation of possible causes beyond
natural conditions. It is further assumed that it is uneconomical to attempt con-
trolling runoff.
Temporary exception (10 Years) - This exception is requested when a criterion
violation is identified as a possible consequence of man's activities in the basin
and management strategies are available to improve water quality. Control
measures, when funded, may improve water quality, but it will take 10 years to
evaluate effectiveness.
Temporary Exception (5 Years) - This exception is requested when a limited data
base indicates a problem but more data are required to identify the cause, extent,
and correctability of the problem. The 5-year exception should allow sufficient
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time for necessary additional data collection and analysis.
Since the Colorado Water Quality Standards and Stream Classification will not
be completed until after the CWACOG is approved, the 208 plan will be in effect
for a transition period. The plan will subsequently be revised pursuant to the State
standards.
Groundwater Quality Standards—
Colorado—Water quality standards for groundwaters in the State of Colorado
are not well defined at present. However, groundwaters do fall into the category of
"State waters " and therefore should meet the basic standards applicable to all
State waters. No specific water quality standards for groundwaters have yet been
established. With regard to wastewater disposed of in pits, ponds, and lagoons, no
permit is required. However, if upon review it is determined that toxic substances
may enter the groundwater system, the State may require sealing of the waste water
retention area with an impermeable layer. The State does require a permit for
wastewater injection wells.
It should be noted that the State is currently revising water quality regulations
with respect to groundwater. Specifically, a limited number of water quality con-
stituents (e.g., radioactivity) will be limited in discharges to groundwaters so that
background concentrations are not exceeded. In addition, permits will be required
for wastewater disposed of in pits, ponds, and lagoons if there is any possibility of
discharges to the groundwater systems.
Utah—The State of Utah also has no specific quality standards for groundwater.
However, as in the State of Colorado, groundwaters are part of the State Waters,
and therefore general pollution control standards do apply.
The State Department of Health has regulatory and statutory approval authority
for all wastewater control facilities. Hence the Department of Health reviews the
engineering adequacy and pollution control capabilities of facilities that include
wastewater injections wells, pits, ponds, and lagoons. Upon approval of such
facilities, a construction permit is issued.
Expected discharges from such facilities to aquifers that serve as potable water
sources must not degrade aquifer quality below applicable drinking water stan-
dards.
Federal—Federal regulations that may pertain to groundwaters are addressed in
the Safe Drinking Water Act. This act has most recently been interpreted as apply-
ing to well injection of waste into aquifers that do or that might serve as sources for
public drinking water. Such underground drinking water sources, while specified to
include aquifers with less than 10,000 mg/1 (8.34xlQ-2 Ibs/gal) total dissolved
solids, must have the potential to be sources of public water supply. Underground
injection control (UIC) regulations were promulgated at 40 CFR 126 on May 19,
1980. In situ operations will fall into the category of "Class III wells." Drinking
water standards are listed in Appendix D. Note that pits, ponds, and lagoons are
not identified as underground injection sources at this time. They are covered
under the RCRA.
Solid and Hazardous Wastes
The RCRA requires that solid and hazardous waste generators and transporters
receive permits and that wastes be disposed of only by safe practices. Regulations
have been promulgated at 40 CFR 261 for (1) the criteria to identify solid and
hazardous wastes (Section 3001); (2) disposal standards (Section 3004); and (3) per-
mit programs (Section 3005). If a waste is not defined as hazardous (i.e., it is de-
fined only as a solid waste), disposal will be governed by the Section 4004 regula-
tions as promulgated at 40 CFR 257 on September 13, 1979. The promulgated
regulations define a waste as hazardous if it is ignitable (flash point F60°C or
140°F), corrosive (extract PH F2 or f!2.5), reactive (explosive or oxidizing), or
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toxic (extract concentration 10 times greater than drinking water standards). Over-
burden mine wastes that are returned to the mine are exempt from these regula-
tions. Also, materials ready for further processing are exempt.
RCRA regulations, as promulgated, do affect oil shale facilities due to the
following:
1. Tank bottoms, cooling tower sludges, API separator sludges, scrubber sludge
are hazardous.
2. Spent catalysts are probably hazardous.
3. Processed shale will probably be treated as a solid waste. Under this classifica-
tion processed shale shall not be disposed of in environmentally sensitive
areas. These include wetlands, floodplains (100-year flood), critical habitats,
and the recharge zone of a sole-source aquifer.
Miscellaneous
Hazardous pollutant standards for air may have an impact on oil shale process-
ing facilities but radiation and noise limitations probably have none.
REFERENCES
1. Culbertson, W. C., and J. K. Pitman. Oil Shale, U.S. Mineral Resources. Prof. Paper
No. 820, U.S. Geological Survey, Denver, Colo., 1973.
2. Duncan, D. C., and V. E. Swanson. Organic Rich Shales of the U.S. and World Land
Areas. USGS Circular 523, U.S. Geological Survey, Denver, Colo., 1965.
3. Ash, H. O. Guidebook to the Energy Resources of the Piceance Creek Basin, Colorado.
Federal Oil Shale Leasing and Administration, U.S. Department of the Interior, Denver,
Colo., 1974.
4. Final Environmental Statement for the Prototype Oil Shale Leasing Program. U.S.
Department of the Interior, Washington, D.C., 1973.
5. Smith, J. W. Ultimate Composition of Organic Material in Green River Oil Shale. RI
5725, U.S. Bureau of Mines, Denver, Colo., 1961.
6. Smith, J. W., W. A. Robb, and N. B. Young. High Temperature Reactions of Oil Shale
Minerals and Their Benefit to Oil Shale Processing In Place. In Proceedings of the 11th
Oil Shale Symposium sponsored by the Colorado School of Mines and the Laramie
Energy Research Center. Colorado School of Mines Press, Golden, Colo., 1978.
7. Tarman, P. B., H. L. Feldkircher, and S. A. Weil. Hydroretorting Process for Eastern
Shale. Presented at the Society of Petroleum Engineers, Eastern Regional Meeting, Oc-
tober 1977. Paper No. SPE6628. IGT, Chicago, 111., 1977.
8. Humphrey, J. P., and R. L. Wise. Eastern Oil Shale. In Proceedings of the American
Nuclear Society Topical Meeting on Energy and Mineral Recovery Research, Golden,
Colorado, April 12-14, 1977. U.S. Department of Energy, Washington, D.C., 1977.
9. Utah Code of Waste Disposal Regulations, Part II. Standards of Quality for Waters of
the State. UCA-26-15-4 and UCA-73-14-1 et seq. (1953) amended. Utah Department of
Social Services, Division of Environmental Health, Salt Lake City, Utah, 1978.
10. 40 CFR 120.104 (b), 1979.
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SECTION 2
RECOMMENDATIONS
One of the purposes of this document is to present a first approximation of
EPA's regulatory expectations regarding oil shale development. This section pro-
vides a summary of recommendations on regulatory philosophy, pollutants of con-
cern, monitoring programs, and areas which need further research. It should be
recognized that both government and industry have certain monitoring and
research responsibilities. The Environmental Protection Agency defines various
regulatory requirements, but it also is responsible for environmental advocacy. The
recommendations in this section attempt to distinguish between requirements and
advocacy positions.
An approach to regulating oil shale facilities to minimize environmental impacts
from oil shale development is proposed. Emphasis is placed on source characteriza-
tion and impact assessment. A comprehensive monitoring program for regulated
and nonregulated pollutants is recommended. The monitoring program would in-
clude baseline studies and operational monitoring. Surface water, groundwater, air
and meteorology, solid waste disposal piles, and oil shale residual streams would
constitute the ambient and source monitoring coverage.
This section also reviews research needed to improve monitoring and control
technology. It recognizes the potential paniculate pollution resulting from the min-
ing, transport, and disposal of raw and spent shale on a mass scale never before at-
tempted, and the subsequent possible impact of runoff and infiltration from the
above-ground disposal of millions of tonnes of spent shale and other solid wastes.
Though much proven technology is available, the need to demonstrate
technology in the combinations and on the scale involved in a commercial oil shale
industry is recognized. Much of the concern about the impact of shale disposal
results from lack of experience with large quantities of spent shale and disposal
piles of the size that would result from a commercial operation.
A known shortcoming is the unreliability of standard sampling and analytical
techniques when applied to effluent streams from shale oil recovery processes.
Among the research recommendations, therefore, is the development and valida-
tion of sampling and analytical methods. These methods must produce reliable
measurements and be applicable to monitoring programs with predictive capa-
bility.
PROPOSED PRECOMMERCIAL APPROACH TO REGULATIONS
The approach regulating the first oil shale facilities must ensure compliance with
existing standards, but more importantly, should emphasize characterization of
residuals from an oil shale facility. Both the State of Colorado and EPA Region
VIII have expressed their desire to see an oil shale industry develop in a phased
orderly manner. Rigorous testing programs and data analyses which would be ap-
plicable to a commercial-sized operation should be performed on the first facilities.
Comprehensive monitoring of emissions, effluents, and waste materials should be
performed. Research programs designed to define the optimum control technology
for a given pollutant resulting from an oil shale facility should be conducted.
Trade-offs among air pollution, water pollution, and solid waste must be defined.
The energy penalty, water consumption, and cost of control must be defined. The
31
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comprehensive monitoring efforts should not be limited to the regulated pollutants
only, but should characterize nonregulated pollutants.
Following the characterization of residuals from modules and from a couple of
commercial facilities, an assessment could be made as to how large an industry
Western Colorado, Northeastern Utah, and Southwestern Wyoming could sup-
port. Additional Federal leasing could then be considered.
As previously stated, emphasis should be placed on source characterization. A
moderate degree of ambient impact monitoring should be performed to validate
predicted impacts and to document trends and changes from baseline. Programs to
evaluate effects on receptors should be performed to provide feedback on source
and ambient monitoring programs.
The BACT for air pollutants must be employed for any proposed oil shale facil-
ity with the potential for emitting 91 tonnes (100 tons) or more per year of any
regulated air pollutant. Those facilities which have smaller potential emissions do
not need BACT but should perform comprehensive monitoring in order to develop
emissions data for potential permit applications. Two primary mechanisms exist to
define the BACT. First, several oil shale facilities have received Prevention of
Significant Deterioration (PSD) permits. The BACT has been defined on a case-by-
case basis for these facilities. Second, air pollution control technology that has
been defined as the BACT for oil-shale-related facilities may be considered as
transferable to the oil shale industry. It is highly likely that air quality requirements
may prove to be the governing constraint to the size of an oil shale industry.
Therefore, in order to maximize the amount of oil production capability of oil
shale country, it is important to maximize the air emissions control for each oil
shale facility.
A no-discharge-of-pollutant concept is being considered by several oil shale
developers as a means of handling their wastewater streams. Three types of water
should be considered—mine, process, and in situ water. A no-discharge-of-
process-water concept has been written into water permits. If any water is dis-
charged to surface streams or reinjected into the groundwater system, it would con-
sist of mine inflow (but not process or in situ water) or uncontaminated surface
runoff. Treatment may or may not be necessary. Effluent limitations will be de-
fined for certain pollutants including toxics for certain oil shale process streams in
the NPDES permit. Major concepts to be addressed by regulatory agencies and the
oil shale developer are summarized as follows. First, because of the semiarid,
water-short condition of oil shale country, it may be environmentally best to en-
courage treatment if necessary and discharge to a surface stream of mine water.
Second, because of salinity considerations, treatment of mine water and/or
minimization of water consumption is a desirable policy. Third, disposal of process
water onto processed shale piles without treatment may not be desirable, since high
organic and salt concentrations in process water may represent too great a risk to
groundwater and surface water quality because of potential catastrophic events or
unexpected permeabilities or leaching. High organic and salt concentrations also
would be a deterrent to successful revegetation. Fourth, maximum recycling and
reuse of process and npnprocess water will be encouraged; cost effectiveness must
be considered. Finally, land application of untreated mine water may be desirable
only for a short period of time because of the potential nonpoint source runoff
problems.
Solid and hazardous wastes should be disposed of in a manner that avoids con-
tact with water and subsequent toxic concentrations. Disposal practices should also
be designed to preclude (or at least minimize) the potential for the solid material
from becoming air-borne as a fugitive dust. Safe disposal practices as defined at 40
CFR 250 apply to oil shale facility hazardous wastes such as spent catalyst, API
separator sludge, tank bottoms, cooling tower sludge, and water treatment plant
sludge. The principal solid waste from an oil shale industry will, of course, be the
processed or raw shale. Surface disposal at a minimum should conform to those
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practices found in 40 CFR 257. Special disposal practices for high-volume
semihazardous waste materials such as processed shale may need to be defined in
individual permit determinations.
REGULATED AND NONREGULATED POLLUTANTS
Terry L. Thoem
Source and ambient monitoring programs will enable developers to characterize
oil shale facility residuals and their impacts on the environment. The Environ-
mental Protection Agency has regulatory authority to require inclusion of certain
pollutants in an oil shale developer's monitoring program. This regulatory author-
ity is found in Sections 114 and 165 of the Clean Air Act, in Section 308 of the
Clean Water Act, and in Section 3005 of the Resource Conservation and Recovery
Act. Source monitoring requirements would be covered in NPDES and PSD per-
mits, the discussion of which are in Section 6 and Appendix D. In its environmental
advocacy role, EPA has an interest in characterizing quantities of other pollutants
released and their resulting impacts. Future standards may result from such
characterizations. Responsibility for these characterizations clearly lies with the
government.
Summarized below are monitoring program pollutant components categorized
according to regulatory requirements, regulatory requirements of primary interest,
and advocated characterization. These components are categorized to provide
guidance for oil shale developers. Further guidance on monitoring programs,
sampling methods, and sampling frequency may be found in Sections 2 and 5 and
in Appendices B, C, and E.
Air
Regulatory requirements:
Total suspended particulates (TSP) Total residual sulfur
(including H2S)
SO2 Asbestos
NOX Be
CO Hg
NMHC F
Oj Vinyl chloride
Pb H2SO4 mist
Regulatory requirements of primary interest:
TSP Pb
S02 H2S
NOX Hg
03 F
Advocated characterization:
Inhalable particulate (F15 micron) SO4
Fine particulate (F2.5 micron) NO3
COS Cd
CS2 Radioactivity
RSH Polycyclic Organic Matter
NH3 (POM)
AsH3
Se
33
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Water
Regulatory requirements:
"Section 307 " toxic pollutants (65 toxic pollutants listed in January 31, 1978
Federal Register. See also the list of 129 Consent decree pollutants in Appendix
D.
"Section 304" conventional pollutants, biochemical oxygen demand (BOD),
suspended solids, fecal coliform, and pH).
Regulatory requirements of primary interest:
TSS Cu
phenols Cr
pH Hg
Pb Se
As Ag
Cd
Advocated characterization:
Total dissolved solids (TDS) Al
SO4 Fe
F Mo
B oil and grease
NH3 Acid organics (as a class)
Cl Neutral organics (as a class)
COD Base organics (as a class)
Temperature Dissolved oxygen (DO)
Ba POM
Solid Waste—
Primary authority relates to composition of the hazardous waste and
characteristics which may affect water quality. Since Resource Conservation and
Recovery Act (RCRA) implementing regulations have not yet been promulgated,
the following characteristics and compounds should be considered to be within the
regulatory authority of EPA.
Toxicity POM
Ignitability MO
Corrosivity B
Reactivity F
Permeability As
Leachability
PROPOSED MONITORING PROCEDURES
Mike Pearson
Guidelines for an Ambient Air Monitoring Network in Oil Shale Development
Areas
A comprehensive air quality monitoring program is required to establish baseline
air quality before development and to identify oil shale development impacts. To
achieve these goals, a network of air sampling stations capable of repeated
simultaneous measurements of the physical and chemical parameters of air quality
at very low concentrations is required. The sites selected should be representative of
the airshed being sampled. The number and location of sampling sites must be
determined on a site-by-site basis after considering local and regional factors
related to air pollutant dispersion (climatology, topography, proposed plant
characteristics, etc.). Although most stations should be permanent sites, temporary
or mobile stations may be used to locate points of maximum impact. Some criteria
for selecting monitoring sites can be found in EPA reports 450/2-77-015 and
450/2-78-019 (1,2).
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The network of permanent stations should be operated uniformly to permit
quantitative comparisons of data from various stations. Sampling should include
the air quality parameters listed in Section 2 (Regulated and Nonregulated
Pollutants), as well as meteorological parameters. Parameters subject to diurnal or
seasonal cyclic behavior should be measured throughout that cycle. Every effort
should be made to ensure the measurement of extreme and severe-impact condi-
tions.
Determination of the low baseline concentrations generally found in oil shale
regions has proven difficult. Most continuous instruments commonly in use do not
have sufficient sensitivity to measure these background levels. To measure these
levels, skilled personnel and new methods may be required. Some of the potentially
applicable methods for monitoring ambient air are presented in Section 5 of this
volume and in Appendix B.
Since permitting and control strategy decisions will ultimately be based on diffu-
sion models, measurement of local and regional meteorological parameters are ex-
tremely important. In the rough terrain associated with oil shale areas, local
topography and the resulting enhanced turbulence significantly influence air pollu-
tant dispersion. These influences of complex terrain will generally require site-
specific model validation. The development of an air quality diffusion model
capable of accurately predicting air quality concentrations at distances up to 200
km (124 mi) expected from cumulative emissions of oil shale facilities and urban
population centers is critically needed.
Surface and Groundwater Ambient Monitoring—Wesley L. Kinney and
Leslie McMillion
Surface Water—
Surface water monitoring programs should be keyed primarily to (a) instream
monitoring for purposes of detecting and characterizing pollutants of point and
nonpoint origin, (b) the detection of spills and stressed or faulty containment struc-
tures or practices that could result in accidental discharges, (c) measurement of
flows in streams, seeps and springs for purposes of assessing flow reductions
resulting from dewatering operations and consumptive uses, and, (d)
measurements of the aquatic biota to determine community changes or
biocumulative effects associated with developmental activities.
Monitoring sites should be established on major streams upstream and
downstream from anticipated sources of pollution, including impacted tributaries.
In addition, stations should be located on the tributaries themselves, including
washes and gulches that are designated as disposal sites or are otherwise potentially
affected by accidental discharges.
Sampling frequencies for particular parameters should be uniform among sta-
tions on mainstream waterways, but all parameters need not be sampled at the
same intensities. Sampling on temporary tributaries need only be conducted during
periods of runoff when potential for transport of dissolved and suspended
materials is greatest. Initially, sampling of perennial streams should be conducted
on a fixed schedule to simplify logistics until sufficient data are available to permit
the development of a time-stratified sampling schedule that permits maximum
sampling intensity during periods of greatest variability in water quality. A
schedule designed to yield 25 to 50 samples/station per year for analyses of
chemical and physical parameters should provide an adequate data base to permit
development of a time-stratified schedule to be implemented as developmental ac-
tivities intensify. The EPA publication entitled Surface Water Quality Parameters
for Monitoring Oil Shale Development (3) should provide additional guidance.
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Surface water monitoring programs should incorporate biological, chemical,
and physical components on an integrated basis to assure maximum program effi-
ciency. Physical and chemical parameters should be selected and assigned priorities
on the basis of ambient levels in receiving waters, potential for mobilization and
release to surface waters, level of hazard or potential for impairment of beneficial
water uses (including aquatic biota and human health), and value of indicator
parameters in interpretation of water quality data. Biological parameters should be
selected and assigned priorities on the basis of the responsiveness of communities
or components to changing conditions, and measurement techniques most ap-
propriate for directly or indirectly measuring such response.
Groundwater—
We recommend that groundwater monitoring systems be related to: (a) potential
sources of pollution, (b) geology and hydrology of the site to be monitored, (c)
probable movement and dispersion of pollutants in the subsurface, and (d)
hydraulic effects of events such as pumping of dewatering wells on the rates and
direction of groundwater movement. The EPA report Monitoring Groundwater
Quality: Monitoring Methodology (4) is suggested as a general guide. Further
specific guidance may be obtained in the EPA report entitled Groundwater Quality
Monitoring of Western Oil Shale Development (5). Monitoring wells should be in-
stalled and sampled to provide verification data; even so, their placement and
sampling frequency should allow for early detection of pollution so that measures
to alleviate the pollution problem can be applied in a timely manner. Parameters to
be analyzed should be discreetly selected to reflect the water quality changes that
are likely to occur in each situation.
Any recommendations concerning the monitoring of injection wells must take
into account that this is a special monitoring situation. The guidance of the EPA
report Monitoring Disposal- Well Systems (6) is suggested. Important considera-
tions are well design, careful construction measures, inventory of fluids being in-
jected, and continuous monitoring of the well itself.
Modified in situ developments pose unique monitoring problems, since little is
known about the organic and inorganic pollutants that will be leached from aban-
doned in situ chambers or how the pollutants will behave in the subsurface. It is
recommended that close attention be given to the monitoring of groundwater
quality in these instances until a reliable body of knowledge can be developed.
Solid Waste—Leslie McMillion
The monitoring of solid wastes is recommended to identify environmental prob-
lems in time for corrective measures to be taken. Proposals for such predictive
monitoring include: (a) inventory and characterization of wastes that are disposed
and the manner of disposal, (b) performance of infiltration tests fo gage the prob-
ability of leaching from waste disposal piles, (c) performance of regular tests to
track the buildup of moisture in disposal piles, (d) the regular monitoring of
groundwater quality in near-surface aquifers at points downgradient and close to
potential pollution sources, (e) performance of routine determination of sediment
and other pollutant loading in surface runoff from facilities, and (f) maintenance
of an early warning system with respect to surface runoff.
Programs should be established to regularly inspect the conditions of disposal
pile slopes and the integrity of retaining structures associated with solid wastes as a
step toward preventing mass movements of disposal piles or catastrophic failure of
structures. Instrumentation such as inclinometers could be used in this monitoring
effort.
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RECOMMENDED RESEARCH
In the course of preparing this document it became apparent to many authors
that additional research was needed to better define and resolve environmental
issues related to oil shale development. At the request of the editors, each author
submitted a list of areas requiring additional research. The following list is intended
to exemplify environmental research needs in oil shale. It is not meant to be a com-
plete listing of research needs. Some areas may be suitable for research by either
government or industry alone but many will require joint government-industry ef-
fort. Active oil shale operations of either pilot or commercial module size are essen-
tial for conducting research in many of the subject areas listed.
Air Pollution Control
Complete characterization of emission streams and fugitive emissions resulting
from each of the various surface and in situ retorting processes.
Regional characterization of baseline air quality (visibility, fine particulates,
SCX, NO3, trace elements, and precipitation chemistry) prior to development,
followed by continued monitoring to determine impacts of development.
Demonstration of the applicability of new and conventional air pollution control
technology to emission streams and fugitive emissions from oil shale processing.
Development of predictive techniques for air quality modeling in complex terrain
including development of a basin-wide air quality model for the Piceance Basin.
Determination of the cause of high ambient ozone concentrations in the western
oil shale regions.
Research to further assess the fugitive dust problem from mining, crushing,
transporting, and stockpiling of raw oil shale.
Determination of the quantity of CO2 generated per unit of fuel product pro-
duced.
Complete characterization of atmospheric fugitive emissions from the refining of
-crude shale oil.
Determination of the effectiveness of monitoring and maintenance in controlling
fugitive emissions from the refining of crude shale oil.
Water Foliation Control
Complete characterization of wastewater streams produced by each of the
various surface and in situ retorting processes.
Demonstration of the applicability and efficiency of conventional water pollu-
tion control technology in the treatment of wastewater streams from oil shale
processing.
Research and development to ensure that control technology is adequate for
boron and fluoride removal from wastewater.
Development of technology for removal of trace organics such as POM,
polycyclic aromatic hydrocarbons (PAH), and benzo(a)pyrene (BaP) from oil
shale effluents and wastewaters.
Case-by-case analysis for trace metals in process wastewaters to define potential
problems and abatement measures.
Research to determine egress routes of groundwater during in situ retorting and
backflood water following retorting operations.
Determination of detailed mineralogy of major aquifers to permit prediction of
groundwater quality variations during and after in situ retorting operations.
Determination of groundwater quality and quantity changes associated with
mine dewatering operations.
Development of monitoring systems to provide early detection of changes in sur-
face or groundwater quality.
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Solid Waste Control
Development and demonstration of technology to control leachate generation
from surface spent shale disposal by minimizing generation of leachates and col-
lecting, treating, and recycling leachates that are produced.
Assessment and development of technology to control leachate generation and
movement from abandoned in situ and modified in situ retorts.
Laboratory and field study on the dispersion of spent shale leachate in ground-
water systems.
Development and demonstratation of technology to construct impermeable bar-
riers out of spent oil shale.
Demonstration of revegetation of spent oil shale disposal sites and assessment of
the uptake of trace elements and other toxic substances by vegetation in com-
parison to vegetation on native soils.
Determination of the physiological requirements and tolerances of plant species
likely to be used for revegetation of spent oil shale.
Investigation of the permeability of various types of spent shale under various
compactive efforts and establishment of the relationship between time or quan-
tity of water leached through spent shale and the change in water quality of the
leachate, with special attention to organic compounds.
Development of technology for control of erosion on large spent shale piles.
Research to determine the nature of leachates from surface stored raw mined
shale and potential impacts on surface and groundwaters.
Demonstration of overburden handling procedures to minimize environmental
impact.
Definition of the nature and leachability of solids other than raw and spent shale
that will be disposed of in surface piles.
Assessment and development of technology for control of subsidence impact
resulting from underground mining and retorting.
Development of technology to monitor the groundwater impacts of true or
modified in situ retorted shale.
Assessment and development of technology for disposal of solid wastes
generated during the refining of crude shale oil (e.g., bottom sludges from shale
oil storage tanks; spent guard bed catalysts).
Sampling and Analysis Technology
Standardization of methodology for analysis of water, air, solids, and leachates.
Interlaboratory validation studies of different types of environmental samples to
validate methods best suited for oil shale pollutant analyses.
Standardization of sampling techniques and equipment for collection of
leachates from solid wastes.
Validation of sample preservation techniques for shipping environmental
samples.
Standardization of tests for leachate parameters.
Validation of methods for biological testing of oil shale waters and other en-
vironmental samples from oil shale retorting operations.
Development and application of rigorous quality assurance and standardization
techniques to analytical methods.
Development of sampling and analysis methods for ambient BaP, PAH, POM
and other trace organics.
Development of methodology to characterize stream sediments in oil shale areas.
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General Research Needs
Health effects testing of oil shale residuals.
Economic assessment of control technology.
Optimization of control technology recognizing intermedia (air, water, and land)
tradeoffs.
Determination of probable social and economic effects associated with develop-
ment of an oil shale industry.
REFERENCES
1. Air Monitoring Strategy for State Implementation Plans. Final Report,
EPA-450/2-77-015, U.S. Environmental Protection Agency, Research Triangle Park,
N.C., June 1977.
2. Ambient Monitoring Guidelines for Prevention of Significant Deterioration (PSD).
EPA-450/2-78-019, U.S. Environmental Protection Agency, Research Triangle Park,
N.C., May 1978.
3. Kinney, W. L., A. N. Brecheisen, and V. W. Lambou. Surface Water Quality
Parameters for Monitoring Oil Shale Development. EPA-600/4-79-018, U.S. En-
vironmental Protection Agency, Las Vegas, Nev., 1979.
4. Todd, D. K., R. M. Tinlin, K. D. Schmidt, and L. G. Everett. Monitoring Groundwater
Quality: Monitoring Methodology. EPA-600/4-76-026, U.S. Environmental Protection
Agency, Las Vegas, Nev., June 1976.
5. Slawson, G. C., Jr., ed. Groundwater Quality Monitoring of Western Oil Shale
Development: Identification and Priority Ranking of Potential Pollution Sources.
EPA-600/7-79-023, U.S. Environmental Protection Agency, Las Vegas, Nev., January
1979.
6. Warner, D. L. Monitoring Disposal-Well Systems. EPA 680/4-75-008, U.S. En-
vironmental Protection Agency, Las Vegas, Nev., July 1975.
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SECTION 3
ENVIRONMENTAL IMPACTS
This section reviews the potential impacts of shale processing activities on the at-
mosphere, surface water and groundwater, and the health and welfare of workers
in the industry and the general population.
Process emissions resulting from mining, processing, retorting, and disposal
operations are projected for a 50,000-bbl/day plant. The impacts on the at-
mosphere of residual emissions from processing are also estimated. Fugitive dusts
from mining, blasting, transportation, and disposal and trace metals in raw shale,
process gas, process water, spent shale, and shale oil are discussed separately in
some detail.
The source and nature of waters from oil shale processing are reviewed, followed
by an evaluation of the effects of wastewater disposal on surface and ground-
waters. The potential long-term effects of wastewaters on regional water supplies
are reviewed.
A commercial oil shale industry will produce tremendous quantities of spent
shale and smaller quantities of other solid wastes that will have to be disposed. An
inventory of solid wastes indicates the magnitude of handling and disposal of raw
and spent shale. In addition to fugitive emissions during handling and disposal,
solid wastes present the problems of wind erosion, runoff and leaching, revegeta-
tion, and instability after disposal. In some cases, these problems may be partially
alleviated by disposal of spent shale underground, though the potential for produc-
ing groundwater pollution must be carefully assessed.
The health effects problems posed by a commercial shale oil industry are little
known, but some information is drawn from foreign experience in use of shale oil.
This information indicates that careful attention will have to be given to industrial
hygiene practices.
This section also reviews additional impacts such as those resulting from the use
of shale oil, possible release of radiation and noise, and social and economic im-
pacts on communities in the shale oil region.
ATMOSPHERIC IMPACTS
Robert Thuraau
Process Emissions: Mining, Processing, Retorting and Disposal
Mining—
The mining activities associated with oil shale operations are going to be among
the largest in the world. To sustain an oil production level of 200,000 barrels per
day (bbl/day), a mining effort of about 136,360 tonnes/day (150,000 tons/day) will
be required. The potential for atmospheric air pollution exists in all phases of min-
ing and includes: excavation, blasting, crushing, transport, and equipment opera-
tion phases.
Surface mining—The magnitude of air pollution emissions from mining is direct-
ly related to the type of mining practices. Open pit mining has been suggested as a
surface mining technique applicable to oil shale extraction. Table 3-1 shows the
estimate of four general open pit mining operations and one from an oil shale
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development plan. With the exception of sulfur oxides, it looks as if particulates,
oxides of nitrogen, hydrocarbons and carbon monoxide could be problem areas.
The estimates of the emissions vary considerably, due to the nature of the problem
and the fact that two of the sites claimed 80 percent control of the fugitive dusts.
The information was taken from a detailed development plan and is now out of
date.
Underground mining, particulates—Underground mining is the method selected
by many developers because the paniculate emissions are lower and easier to con-
trol with this method. Table 3-2 summarizes data reported for particulate emissions
resulting from underground mining, blasting, and ground vehicles. Information is
included on both modified in situ underground mining operations and conven-
tional underground mining operations. At first the assumption was made that the
reduced mining activity associated with the modified in situ retort would result in a
lower rate of particulate emissions; however, the data for the particulate emissions
from both operations were similar. The literature supports this conclusion (1).
The mining operations of true in situ retorts have received very little attention to
date but particulate emissions from this source have been estimated by one
investigator at 0.01 tonnes/day (.011 tons/day) (1). The bulk of the particulates
included in this figure is derived from surface activities rather than from actual
mining.
The usual method of breaking up the oil shale rock formations for use in the
retorts is by blasting with explosives. Table 3-2 indicates that fraction of the total
particulate emission that is attributable to the explosives. As shown, a wide range
of values is presented, making this subject area a candidate for additional study.
Table 3-2 also indicates the percentage of total particulate loading associated
with the movement of ground vehicles, which are a third source of fugitive dust
emissions related to oil shale mining. The values are consistently low and do not
seem to be a problem.
Underground mining, other emissions—The particulates generated from mining
operations are not the only mining-related emissions that must be considered by
developers. The explosives used to loosen the shale rock can produce CO, NO*, and
hydrocarbons, and can possibly release some hazardous pollutants such as trace
metals, radon, and silica. The consumption of fuel by the mining equipment will
also liberate sizable amounts of CO, NOX, SO2, and hydrocarbons.
Estimates of the gaseous emissions for underground mining are presented in
Tables 3-3 and 3-4. Sizable amounts of NO, are estimated, with most of the pollu-
tion coming from the ground vehicles. The carbon monoxide data appear to have
more scatter and could represent an area requiring additional investigation. The
emissions of sulfur dioxide and total hydrocarbons have been reported at low levels
and do not presently seem to play a very important role in the gaseous emissions
from the underground mining of oil shale.
As was the case for particulate emissions, the gaseous pollutants from
underground mining seem to have a smaller emission rate than those from surface
mining, and if any treatment is necessary, underground emissions would be easier
to collect.
Processing—
Another important source of particulate is the fugitive dust from the processing
of raw shale before retorting. All oil shale retorting operations will require a size
reduction of some kind, and probably all surface retorts will rely on grinding to
some degree. This processing step will result in particulate emissions to the at-
mosphere.
The transportation and disposal of the processed shale makes another contribu-
tion to the particulate loading in the ambient air.
Table 3-5 summarizes the particulate emissions resulting from the processing
steps of crushing, transportation, and disposal. Limited data exist on surface-
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TABLE 3-1. ESTIMATED ATMOSPHERIC EMISSIONS FROM 50,000-BBL/DAY OIL SHALE SURFACE MINING OPERATIONS
(6,750 tonnes/day)
Mining Ref
operation 2a
Excavation
and
blasting
crushing 2.8
Transportation
and
mining
equipment 5.4
Sum 8.2
Particulates
Ref Ref Ref
3b 4c ,d
22 31.7 0.8
6.7 NRf Nil
28.7 31.7 0.8
Ref Ref Ref
5e 2a 3b
42.3 NR NR
0.9 0.1 2.4
43.20 0.1 2.4
sox
Ref Ref Ref
4c ,d 5e
2.6 NR Nil
NR NR Nil
2.6 NR Nil
NOX HC
Ref Ref Ref Ref Ref Ref Ref Ref
2a 3b 4C 1d 5e 2a 3b 4C
NR NR 36.0 NR 1.6 NR NR 4.2
1.1 33.3 NR NR 8.2 0.1 3.9 NR
1.1 33.3 36.0 NR 9.8 0.1 3.9 4.2
CO
Ref Ref Ref Ref Ref Ref Ref
1d 5e 2a 3b 4° 1d 5e
NR NR NR NR 21.6 NR 1.5
NR 0.50 0.7 20.0 NR NR 1.6
NR 0.50 0.7 20.0 21.6 NR 3.1
Generalized Mining Conditions —does not refer to specific mining operation —Allows for 80 percent control of fugitive dust.
Generalized Mining Conditions —does not refer to specific mining operation —No fugitive dust control given.
Generalized Mining Conditions —does not refer to specific mining operation —No fugitive dust control given.
Generalized Mining Conditions-does not refer to specific mining operation —Allow for 80 percent control of fugitive dust.
Emissions based on mining operations presented in Tract CA DDP utilizing Tosco/Paraho Technology
Not reported.
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TABLE 3-2. ESTIMATED PARTICULATE EMISSIONS FROM 50,000-BBL/DAY UNDERGROUND MINING OPERATIONS
(6,750 tonnes/day)
Mining
operation
Excavation
(mining)
Blasting
Ground
vehicles
Sum
Ref
5a
0.07
NR"
0.01
0.08
Ref
5b
0.01
0.03
0.14
0.18
Ref
0.08
NR
NR
0.08
Ref
0.01
1.32
0.14
1.47
Ref
0.43
1.32
0.07
1.82
Ref
8f
0.16
NR
NR
0.16
Ref
99
0.02
NR
0.06
0.08
Ref
0.70
0.12
0.01
0.83
Ref
0.10
0.16
Nil
0.26
Ref
4'
0.67
NR
NR
0.67
Ref
5k
0.73
15.26
0.12
16.11
Ref
5'
0.43
8.98
0.08
9.49
Ref
5m
0.92
19.15
0.15
20.22
Potential Fugitive Dust Emissions |p 75) General Room and Pillar Mining
Ua, Ub estimates-Adapted from DDP
Fugitive dust study —scale done by EPA
Paraho Process —Adopted from White River Shale Project DDP
Controlled emissions from Ocy MIS (p 3-51
Oxy Construction Permit
Rio Blanco Construction Permit
General Room & Pilar Mining (Table 2.1-5)
0.10 Tonees/day is the fugitive dust estimation from mining. General
General Room &• Pilar Mining, p 230
TOSCO II mining estimation, p 12, Colony EIA
Does not include estimate for rubbling retort, p 12
Paraho mining estimation, p 12
Not reported
-------
TABLE 3-3. SUMMARY OF SULFUR DIOXIDE AND OXIDES OF NITROGEN EMISSIONS REPORTED
FROM 50,000-BBL/DAY UNDERGROUND MINING OPERATIONS
(6,750 tonnes/day)
Mining
operation
Mining
Blasting
Ground
vehicles
Sum
a Ua-Ub White River Oil
D General Room 8 Pillar
c General Room ft Pillar
Ref Ref
1a 3b
NR1 NR
NR NR
0.004 NR
0.004 NR
Shale Project DDP
Mining Technique given
Sulfur dioxide
Ref Ref Ref
2° 8d 4e
NR 0.08 NR
NR NR NR
0.005 NR NR
0.005 0.08 NR
by Radian Corp.
Oxides of nitrogen
Ref Ref Ref Ref Ref Ref Ref Ref Ref Ref
5f 59 5h 1a 3b 2° 4e 5f 59 5h
NR NR NR NR NR NR 2.95 NR NR NR
NR NR NR NR NR NR NR 0.61 0.36 0.77
NR NR NR 0.018 0.55 0.007 NR 2.39 1.70 2.99
NR NR NR 0.018 0.55 0.007 2.95 3.00 2.06 3.76
Mining Technique (p 130)
Oxy — Construction Permit
e General Room & Pillar
Mining Ip 2-30)
' TOSCO estimate based on Colony EIA
9 Oxy estimate based on
Paraho estimate based
1 Not reported
Cb revised DDP
on design for commerci;
al plant
-------
TABLE 3-4. SUMMARY OF HYDROCARBON AND CARBON MONOXIDE EMISSIONS
FROM 50,000-BBL/DAY UNDERGROUND MINING OPERATIONS
(6,750 tonnes/day)
Hydrocarbons
Mining
operation
Mining
Blasting
Ground
vehicles
Sum
Ref
1a
NR!
NR
0.018
0.018
Ref
3b
NR
NR
0.55
0.55
Ref
2c
NR
NR
0.007
0.007
Ref
4e
NR
NR
0.59
0.59
Ref
5f
NR
NR
0.16
0.16
Ref
5g
NR
NR
0.01
0.01
Ref
5h
NR
NR
0.19
0.19
Ref
NR
0.727
0.055
0.782
Ref
NR
NR
4.79
4.79
Ref
NR
NR
0.039
0.039
Carbon monoxide
Ref
4e
NR
NR
5.18
5.18
Ref
NR
0.608
0.459
1.067
Ref
NR
0.359
0.03
0.389
Ref
5h
NR
0.768
0.579
1.347
Ua-Ub White River Oil Shale Project DDP
General Room & Pillar Mining estimate given by Radian Corp.
General Room & Pillar Mining estimate given by TRW, p 130
General Room & Pillar Mining estimate given by Cameron Eng., p 2-30
TOSCO estimate based on Colony EIA
Oxy estimate based on Cb revised DDP
Paraho estimate based on design for commercial plant
Not reported
-------
TABLE 3-5. CONTROLLED PARTICULATE EMISSIONS FROM SURFACE AND UNDERGROUND MINING
RESULTING FROM CRUSHING, TRANSPORTATION, AND STORAGE OF RAW SHALE
{tonnes/day)
Mining
operation
Primary and
secondary
crushing
Storage and
transportation
Sum
a Open pit mine — crushing onsite, p
Surface
Ref
2a
2.07
5.42
7.49
133
Underground
Ref Ref Ref Ref Ref Ref Ref Ref Ref
1b 1C 11d 12e 13f 89 9h 4' 14'
0.292 0.777 1.03 0.485 0.687 NR NR 0.731 0.44
0.043 0.125 0.145 0.192 NRk 0.099 0.420 NR 0.17
0.335 0.902 1.175 0.677 0.687 0.099 0.420 0.731 0.61
b Ua-Ub estimated adapted from DDP, p 71
c CA- Detailed Development Plan
d SRJ estimate of TOSCO Process,
e Oil Shale Leasing Program
* Project Independence
9 Oxy Construction Permit
n Rio Blanco Construction Permit
1 General Crushing
J Colony Permit
^ Not reported
p93
-------
generated paniculate emissions, but the underground processing data clearly show
lower emission rates.
Retorting—
A third major source of air pollution from oil shale production is the actual
retorting process of the shale. Various amounts of sulfur dioxide, particulars, ox-
ides of nitrogen, hydrocarbons, carbon monoxide, and trace metals are emitted to
the atmosphere as a result of the retorting. The data contained in this section show
a wide range of emission estimates for most pollutants. These estimates evolved as
the industry began to develop their estimates and generally reflected a more ac-
curate level as more was known about the different processes. The data displayed
in the latter entries on Tables 3-6 to 3-10 are indicative of the latest estimates. This
can also be seen in Figure 3-1 in which the latest estimate of sulfur emissions con-
verge below 5 tonnes/day (5.5 tons/day). The information viewed in Table 3-6 to
3-10 should also be viewed in this manner.
TABLE 3-6. PROJECTED CONTROLLED SULFUR DIOXIDE EMISSIONS
FROM THE RETORTING OF OIL SHALE (50,000 bbl/day)
Process
or
location
TOSCO II estimation*
TOSCO II, Colony
TOSCO II, Stanford Research
Institute estimation
TOSCO II, Engineering Science, Inc.
estimation
Union Oil retort
C-a, TOSCO II for 2/3 and
Paraho (GCR) for 1/3
Colony PSD
C-b, TOSCO II, Colony
Paraho oil shale module
Union Oil B
Rio Blanco oil shale project PSD
U-a, U-b, Paraho technology
TOSCO II retorting
Union Oil retorting
Paraho Oil retorting
Union B PSD
C-b Occidental, modified in situ PSD
Reference
number
2
1
11
13
3
1
14
1
3
1
8
1
4
4
4
15
9
Projected
emission rate
(tonnes/day)
57.9 (29.0)
18.9
17.0
14.3
5.73
3.43
3.43
3.07
2.73
2.08
2.00
1.60
1.59
1.53
1.49
1.11
0.20
' Data given for retorting and upgrading emissions for retorting estimated by dividing in half.
48
-------
The release of sulfur to the atmosphere by the retorting of oil shale can occur in
several ways. Raw shale contains sulfur concentrations that range up to 3 percent.
A more typical shale in the Green River Formation will contain about 0.7 percent
sulfur. The sulfur is distributed between the organic and inorganic fraction in a
ratio of one-third and two-thirds, respectively (10). During pyrolysis and/or partial
oxidation, the organic fraction is the only sulfur-containing part that undergoes
reaction, and about 40 percent is released in the form of hydrogen sulfide. The re-
maining 60 percent of the organic sulfur resides in the shale oil product as heavier
sulfur-containing compounds. The amount of sulfur available for reaction is about
1 kg/tonne (2 Ibs/ton), and assuming a Fischer assay of 104 I/tonne (25 gal/ton)
and a 50,000-bbl/day operation, if uncontrolled, about 70 tonnes/day (77 tons/-
day) could be emitted. The sulfur can be converted to gaseous sulfur compounds
such as sulfur dioxide, hydrogen sulfide, carbon disulfide, carbonyl sulfide, and
possibly even some thiocyanates. These compounds are of interest because of the
health effects associated with them.
One of the sulfur compounds of particular interest to oil shale developers, State
and Federal regulatory agencies, and environmentalists is sulfur dioxide. Sulfur
dioxide is regulated by State and Federal emission standards as well as by the am-
bient air regulations. Table 3-6 summarizes the projected sulfur dioxide emissions
from several retorting operations by several different investigators.
TABLE 3-7. PROJECTED CONTROLLED PARTICULATE EMISSIONS
FROM THE RETORTING OF OIL SHALE (50,000 bbl/day)"
Process or Reference Emission rate
location number (tonnes/day)
C-b, Colony, TOSCO II 2 7.81
TOSCO II, retorting 4 7.65
TOSCO II, Engineering Science, Inc.
estimation 13 7.34
TOSCO II, Colony 1 7.14
TOSCO II, Ca-2/3 and Paraho (GCR)
for 1 /3 1 6.32
TOSCO II estimation 2 4.94
TOSCO II, Stanford Research
Institute estimation
Colony
U-a, U-b Paraho technology
Union Oil retorting
Paraho oil shale module
Paraho retorting
Union Oil retorting
C-a Rio Blanco, modified in situ
C-b Occidental modified in situ
11
14
1
3
3
4
4
10
9
3.36
2.78
2.11
1.95
1.16
0.99
0.68
0.13
0.26
a Source: Reference 15
49
-------
The retorting of oil shale offers another opportunity for participate emissions to
escape into the atmosphere. Table 3-7 illustrates the estimated particulate emissions
from several oil shale retorting operations. The estimates vary for surface retorting
units from 0.68 to 7.81 tonnes/day (.75 to 8.59 tons/day), and 0.13 to 0.26 (.14 to
.29) for modified in situ operations.
Oxides of nitrogen can result from burning or pyrolyzing a fuel containing
nitrogen and can also form from the elemental nitrogen present in the oxidizing
medium (usually air). The rate of formation is a function of flame temperature,
residence time, and the fuel-to-air ratio. Without upgrading, the raw shale oil is
rich in nitrogen, and if used as a heat source in retorting, it could be a significant
source of additional oxides of nitrogen. Table 3-8 summarizes the oxides of
nitrogen emission rates that have been reported from several sources.
Hydrocarbons are present in the gas stream of any incomplete combustion pro-
cess. The retorting of oil shale is such a process in that the pyrolyzing atmosphere is
inherently low in oxygen. Significant concentrations of hydrocarbons are expected
from retorting, and estimates of their projected emission rates are summarized in
Table 3-9.
Like the hydrocarbons, carbon monoxide emissions are generated from the in-
complete combustion of the oil shale. A summary of the emissions for carbon
monoxide is shown in Table 3-10.
Another potential problem area associated with the retorting of oil shale, and
which as yet is not covered by any regulations, is that of trace metal emissions.
TABLE 3-8. PROJECTED CONTROLLED OXIDE OF NITROGEN EMISSIONS
FROM THE RETORTING OF OIL SHALE (50,000 bbl/day)
Process or Reference Emission rate
location number (tonnes/day)
TOSCO II, Colony 1 64.16
TOSCO II, Stanford Research Institute
estimation 11 22.23
TOSCO II estimation 2 21.45
Union Oil retorting 3 21.42
TOSCO II, Colony C-b 2 16.87
Colony 14 16.72
TOSCO II, Engineering Science, Inc.
estimation 13 15.98
TOSCO II retorting 4 15.56
Paraho retorting module 3 13.79
Paraho retorting 4 12.40
TOSCO II for 2/3 and Paraho (GCR)
for1/3C-a 1 10.83
U-a, U-b, Paraho technology 1 9.76
Union Oil retorting 4 6.79
Union Oil B 1 6.20
50
-------
TABLE 3-9. PROJECTED CONTROLLED HYDROCARBON EMISSIONS
FROM THE RETORTING OF OIL SHALE (50.000 bbl/day)
Process or
location
TOSCO II Estimation
Union Oil retorting
Paraho retorting module
TOSCO II for 2/3 and Paraho
GCRfor 1/3 C-a
TOSCO II, Colony
TOSCO II, Engineering Science, Inc.
estimation
TOSCO II, Stanford Research
Institute estimation
TOSCO II, Colony C-b
Colony
TOSCO II retorting
U-a, U-b Paraho technology
Union Oil retorting
Paraho retorting
Reference
number
2
3
3
1
1
13
11
1
14
4
1
4
4
TABLE 3-10. PROJECTED CONTROLLED CARBON
EMISSIONS FROM THE RETORTING
(50,000 bbl/day)
Process or
location'
TOSCO II estimation
TOSCO II, Colony
U-a, U-b Paraho technology
TOSCO II, Colony C-b
Union Oil retorting
Colony
Paraho retorting module
Union Oil retorting
TOSCO II retorting
Paraho retorting
Reference
number
2
1
1
1
3
14
3
4
4
4
Emission rate
(tonnes/day)
28.25
8.28
7.94
3.79
3.72
3.45
3.27
3.08
2.97
2.95
0.49
0.33
0.27
MONOXIDE
OF OIL SHALE
Emission rate
(tonnes/day)
1.91
1.60
0.90
0.74
0.72
0.68
0.59
0.58
0.51
0.43
51
-------
30
25
20
15
10
1973
1974
1975
1976 1977
Time (years)
1978
1979
Figure 3-1. Estimated sulfur emissions as function of time.
Direct volatilization and carry-over on particulates are the two ways that trace
metals can be released into the environment by retorting oil shale. Work done at
the 9 tonne (10-ton) retort at the DOE Laramie Energy Technology Center iden-
tified arsenic, mercury, iron, chromium and zinc as being present in both fractions
of the off-gas (the gaseous fraction and the particulate fraction) (15). Another in-
vestigator reports that up to 70 percent of the mercury present in raw oil shale is
released in the off-gas (16). The Environmental Protection Agency sponsored a
series of tests at the Paraho oil shale retort and found that small quantities of
arsenic were present in the stack gas (17). There seems to be enough evidence to in-
dicate that the trace metal emissions from oil shale retorting operations could be a
problem and may need to be controlled.
Disposal—
Except for the operators of the true in situ retorts (see Inventory of Solid Wastes
later in this section), the problems of disposing of large quantities of spent shale are
being confronted by the oil shale industry. Several approaches are being con-
sidered, with backfilling in the mine and landfills being popular options.
52
-------
Regardless of the method chosen, the transfer, handling, and disposal of the spent
shale could cause some problems of particulate entrainment and/or hydrocarbon
vaporization from the hot shale. The amount of information on the impact of these
pollutants on the environment is quite small. One source lists 0.50 tonnes/day (.55
tons/day) as the contribution of dust that is due to disposal of the spent shale (1).
Another investigator showed that the concentration of particulate matter in the
ambient air was increased by about 500 mg/m3 (2.18x10"" grains/ft3) near the spent
shale transfer zone relative to another sampler stationed 305 m (1,000 ft) away (18).
Table 3-11 shows some of the data collected at the retorted shale transfer station
during the operation of the Paraho retort. The highest concentration of dust was
found near the transfer site and seemed to level off at a distance of 20 and 35 m (65
and 115 ft). If the emission rate at 5 m (16 ft) is representative of the emission rate
for spent shale disposal, and if a volume of 50 x 50 x 10 m (164 x 164 x 33 ft) is
selected as equal to the point source, and if the process is scaled up to full size
(50,000 bbl/day), an emission rate of about 1.5 tonnes/day (1.65 tons/day) would
result.
Very little work has been done on identifying the hydrocarbon emissions derived
from spent shale disposal sites. The hydrocarbons emitted would depend on the
retorting conditions. One study by Schmidt-Collerus (19) identified some
polynuclear aromatic hydrocarbons in the air at a shale disposal site, but they were
associated with the airborne particulate emitted from the disposal operation. This,
however, is not unusual because polynuclear aromatic hydrocarbons have been
found on other rural and urban particulate samples.
Residual Atmospheric Emissions of Sulfur Dioxide, Particulate Matter,
Oxides of Nitrogen, Hydrocarbons, and Carbon Monoxide
The concern for summarizing the emissions from oil shale operations (Section 3,
Process Emissions) is important because of their impact on the surrounding area.
The modeling of those emissions is the next logical step in studying environmental
impacts. However, the application of any diffusion model in oil shale country must
be done with care because of the complex geographical terrain. A regional disper-
sion model for rough terrain is not available at this time. Therefore, the individual
sites were modeled separately using the EPA Valley Model to predict the ambient
air concentrations resulting from the data that were summarized in Tables 3-6 to
3-10. Each site was treated as a point source, and the boundaries of the site were
assumed to be representative of ambient air. Again in Section 3 the emissions have
a historical flavor and latest estimates are the lowest.
Sulfur Dioxide—
The projected ambient concentrations of sulfur dioxide are summarized in Table
3-12. Assuming the later estimates are more accurate than the earlier estimates and
that the air dispersion model is accurate, it appears that sulfur dioxide concentra-
tions will be below the ambient levels specified by legislation. As stated earlier a
regional model is not available to study the cumulative effects of sulfur dioxide
emissions. However, if the concentrations are additive, the point would come
quickly where additional development of oil shale reserves could be hindered by
violations in the ambient air regulations for sulfur dioxide.
Particulates—
Under the same conditions as described for sulfur dioxide emissions, the pro-
jected ambient concentrations of particulates are shown in Table 3-13. Except for
two surface mining estimates, significant emissions are associated with the retorting
operations.
53
-------
TABLE 3-11. FUGITIVE EMISSIONS AT THE PARAHO SHALE TRANSFER AREA8
(mg/m3 per hour)
5 m (16 ft) north of station
Date Emission rate background net
9/03 7.01 - 7.01
9/04 8.44 0.25 8.19
9/05 - -
9/06 - -
9/08 - - -
Average — — 7.60
20 m (65
Emission rate
—
3.75
7.04
5.16
5.77
6.23
7.05
1.45
3.75
-
ft) north of station
background
_
0.25
0.33
0.32
0.45
0.45
0.45
0.45
0.45
-
net
—
3.50
6.71
4.84
5.32
5.78
6.60
1.00
3.30
4.63
35m (112
Emission rate
—
—
7.35
6.85
8.11
1.22
1.80
7.42
4.33
3.95
-
ft) north of station
background
—
-
0.33
0.33
0.45
0.45
0.45
0.45
0.45
0.45
-
net
—
-
7.02
6.52
7.66
0.77
1.35
6.97
3.88
3.50
4.71
a Source: Reference 6.
b Not reported.
-------
TABLE 3-12. DISPERSION OF SULFUR DIOXIDE AND ITS RESIDUAL
TIME-AVERAGED ANNUAL CONCENTRATIONS8 FOR
50,000 BBL/DAY OPERATIONS," EPA VALLEY MODEL
Oil shale
operation
Surface
mining
Underground
mining
Retorting
Emission rate
tonnes/day
2.64
2.44
0.10
0.08
0.08
0.005
0.004
29.
18.9
17.0
14.3
5.73
3.43
3.07
2.73
2.08
2.00
1.60
1.59
1.53
1.49
0.8
0.20
Ambient air
concentration
M g/m3
10
9
< 1
< 1
< 1
< 1
< 1
111
72
65
55
22
13
12
10
8
8
6
6
6
6
3
1
a Standards for time-averaged concentrations are as follows:
Federal-80 /j g/m3; Colorado—20 /j g/m3; Utah—60 H g/m3; Wyoming —71 ^ g/m3
(the Wyoming standard is H2S for one-half hour maximum).
0 Reference Table 3-6.
Oxides of Nitrogen—
Table 3-14 summarizes emission rates for oxides of nitrogen that have been
reported and indicate their possible impact on the ambient air. Again,the same
model conditions were used for NOX as were used for sulfur dioxide and par-
ticulates. The latest estimates of NO, emissions are in the bottom half of the table
and seem to be well within the ambient air regulations. Again, however, these
estimations are for individual sources and the combination of numerous oil shale
operations could violate the statutes.
Hydrocarbons and Carbon Monoxide—
Table 3-15 summarizes the possible impact on the environment that could be due
to hydrocarbons. As seen in the table, the impact seems quite high. The informa-
tion available in the literature was for a three-hour averaged sample and not for an
annual sample, and it is usually the case that the three-hour sample is an order of
magnitude higher than the annual sample. Therefore, the hydrocarbon ambient
concentrations fall within the same limits as the other pollutants and will not
violate the ambient air regulations. The carbon monoxide results are summarized
in Table 3-16 and do not appear to represent a problem. .
55
-------
TABLE 3-13. DISPERSION OF PARTICULATES AND THEIR RESIDUAL
TIME-AVERAGED ANNUAL CONCENTRATIONS" FOR
50.000-BBL/DAY OPERATIONS"
Oil shale
operation
Surface
mining
Underground
mining
Surface
processing
Underground
processing
Retorting
Emission rate
tonnes/day
43.20
31.01
28.66
6.08
3.55
20.22
16.11
9.49
1.82
1.47
0.83
0.18
0.17
0.08
0.08
0.08
0.08
2.07
1.18
0.90
0.73
0.69
0.68
0.42
0.34
0.10
7.81
7.65
7.34
7.14
6.32
4.94
3.36
2.11
1.95
1.16
0.99
0.68
0.26
0.13
Valley concentration
(/jg/m3)
152
109
101
21
13
71
57
33
6
5
3
1
< 1
< 1
< 1
< 1
< 1
7
4
3
3
2
2
< 1
< 1
< 1
28
27
26
25
22
17
12
7
7
4
3
2
1
< 1
3 Standards for time-averaged annual concentrations are as follows:
Federal-75 ^ g/m3 (19 it g/m1 for Class II), Colorado-45 (j g/m», Utah—90 jj g/m'; Wyoming-75 n g/m'.
b Reference Table 3-7.
56
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TABLE 3-14. DISPERSION OF OXIDES OF NITROGEN8 AND THEIR
RESIDUAL TIME-AVERAGED ANNUAL
CONCENTRATIONS" FOR 50,000-BBL/DAY
OPERATIONS0
Oil shale
operation
Surface
mining
Underground
mining
Retorting
Emission r.ate
tonnes/day
35.99
33.26
1.60
1.11
3.76
3.00
2.95
2.06
0.55
0.018
0.007
64.16
22.23
21.45
21.42
16.87
15.98
15.56
13.79
12.40
10.83
9.76
6.79
6.20
Valley concentration
(^g/m3)
33
31
1
1
3
3
3
2
< 1
< 1
< 1
59
21
20
20
16
15
14
13
11
10
9
6
6
a Assumed complete conversion of NOX to NO2
Federal standard for time-averaged annual concentration is 100 M g/nrA
c Reference Table 3-8.
Two important points effect the impact of the emissions modeled in Tables 3-12
to 3-17. The first factor is the size of the oil shale operations. The discussed emis-
sions are relative to only 8,000-mVday or 26,246-ftVday (50,000 bbls/day) shale oil
production. As production capacity is increased the emissions are increased and so
is the impact on the atmosphere. It is conceivable that the dispersion characteriza-
tions of the Piceance Valley could be the limiting factor in the development of a
commercial sized oil shale industry. Second, the air pollution standards against
which the emission rates were compared were the most lenient, and this probably
will not be the case for a commercial-sized facility. Stricter ambient air standards,
if imposed, would probably affect the sulfur dioxide and oxides of nitrogen control
strategies and could well cause a change in the process or require tighter control.
Fugitive dusts consist of any dust that escapes to the atmosphere from a source
other than a stack or duct. Fugitive emissions are expected from mining, blasting,
crushing, transportation, and disposal of the shale. Most of the emissions discussed
as particulate air pollution in an earlier section were, in fact, fugitive dusts. They
are summarized in Table 3-17. Using the same regional air pollution dispersion
model as before, it appears that fugitive dusts may not be a serious regional prob-
57
-------
lem for most oil shale operations, although they may present serious localized pro-
blems.
Trace Element Emissions
Another area of concern in the development of the oil shale industry is the
release of trace elements. It has been suggested that trace elements will be found in
all fractions of oil shale effluents and could have substantial impact on the environ-
ment. Presently, the only air pollution standards that might be applied to oil shale
processing are the National Emission Standards for Hazardous Air Pollutants
(NESHAP) for beryllium and mercury. There is some evidence in the literature that
indicates mercury may be released from oil shale retorts in sufficiently high concen-
tration to merit some control, but more information is necessary before a decision
on potential hazards can be made (16). The trace metals that get into water
discharges could be governed by either the drinking water regulations or the ef-
fluent guidelines. The trace element problem in the oil shale industry is at a stage
where additional work must be done to determine the extent of the problem and to
evaluate accurately its impact on the environment.
TABLE 3-15. DISPERSION OF HYDROCARBONS AND THEIR RESIDUAL
TIME-AVERAGED 3-HOUR CONCENTRATIONS3 FOR
50,000-BBL/DAY OPERATIONS"
Oil shale
operation
Surface
mining
Underground
mining
Retorting
Emission rate
tonnes/day
4.17
3.86
0.50
0.13
0.59
0.55
0.19
0.16
0.018
0.01
0.007
28.85
8.28
7.94
3.79
3.72
3.45
3.27
3.08
2.95
0.49
0.33
0.27
Valley concentration
(^ig/m3)
267
247
32
8
38
35
12
10
1
< 1
< 1
1,846
530
508
243
238
221
209
197
189
31
21
17
a Federal guideline for time-averaged 3-hour concentration is 160 M g/m^.
b Reference Table 3-9.
58
-------
TABLE 3-16. DISPERSION OF CARBON MONOXIDE AND ITS RESIDUAL
TIME-AVERAGED ANNUAL CONCENTRATIONS8 FOR
50.000-BBL/DAY OPERATIONS"
Oil shale
operation
Surface
mining
Underground
mining
Retorting
Emission rate
tonnes/day
21.59
19.96
3.10
0.67
5.18
4.79
1.35
1.07
0.78
0.39
0.04
1.91
1.60
0.90
0.74
0.72
0.59
0.58
0.51
0.43
Valley concentration
(/jg/m3)
1,108
1,024
159
34
266
246
69
55
40
20
2
98
82
46
38
37
30
30
26
22
a Federal standard for time-averaged 8-hour concentration is 10,000 ^ g/m .
b Reference Table 3-10.
Raw Shale—
The trace element composition of raw shale is quite variable. Differences have
been attributed to natural geologic and geographic variations as well as to dif-
ferences in sampling and analysis techniques. The nonuniformity of the trace
elements in oil shale was illustrated by the Thompson-Raymo-Woolridge Corpora-
tion (TRW) in a report to EPA (18) (Table 3-18).
Process Gas—
Retorting of oil shale in surface modules is usually accomplished by heating the
rock to 430° to 540°C (806° to 1004 °F). It is generally accepted that most of the
trace elements are not volatilized at these temperatures, with the possible exception
of antimony, arsenic, boron, cadmium, fluoride, lead, mercury, selenium, and
zinc. Trace element studies conducted by TOSCO Corporation confirmed the fact
that the low retorting temperatures prevented the volatilization of the low vapor
pressure elements and insured their remaining in the spent shale. The higher vapor
pressure elements found their way into the shale oil retort water and off-gas (20).
The TRW Corporation suggests that minor elements in oil shale such as mercury
and arsenic constitute potential emission problems (18).
In situ retorting of oil shale has the disadvantage of poorer control over the
retort temperature, and excursions beyond the 540 °C (1004°F) level can be quite
common. Under these conditions, the possibility of volatilizing some of the trace
elements into the gaseous phase increases. It has been reported that arsenic and
mercury concentrations for both volatilized and particulate-associated trace metals
from a simulated in situ retort were 3,900xlO-'g/m3 and 1,900x10-' g/m3
59
-------
TABLE 3-17. FUGITIVE DUSTS AND THEIR RESIDUAL TIME-AVERAGED
ANNUAL DUST CONCENTRATIONS' FOR 50,000-BBL/DAY
OPERATIONS'"
Oil shale
operation
Surface
mining
Emission rate
tonnes/ day
43.20
31.01
28.66
6.08
3.55
Valley concentration
(M9/m3)
152
109
101
21
13
Underground
mining
Surface
processing
Underground
processing
Disposal
20.22
16.11
9.49
1.82
1.47
0.83
0.18
0.17
0.08
0.08
0.08
0.08
2.07
1.18
0.90
0.73
0.69
0.68
0.42
0.34
0.10
1.5
71
57
33
6
5
3
4
3
3
2
2
< 1
< 1
< 1
3 Standards for time-averaged annual concentrations are as follows:
Federal —75 fj g/m3, Colorado—45 ^ g/m3, Utah—90 jj g/m3; Wyoming —75 jj g/m3.
b Reference Tables 3-1, 3-2. and 3-5.
(2.44x 10-10 lb/ft3 and 1.19x 10-' ° lb/ft3), respectively (15). Preliminary investigation
of pilot-scale, in situ oil shale processing plants indicates that approximately 88 per-
cent of the mercury present in the raw shale is released in off-gas (16,21).
Fugitive Dust—
Trace elements emitted to the atmosphere via fugitive dusts as a result of raw
shale handling and spent shale disposal could be significant. Fugitive dust data
were taken at Paraho, and one of the areas of emission was the spent shale transfer
area (6). The collected dusts were examined for trace metals, and the results are
summarized in Table 3-19. In about half of the cases, the concentration of trace
element on dust remained about the same as the background concentration.
However, the other elements fluctuated, with Pb, As, Hg, Ni, Cr, S, V, and Se
changing significantly. The meaning of the data is not yet clear. Additional testing
is required before any conclusions about trace elements and their relationship with
fugitive dust can be drawn.
60
-------
TABLE 3-18. MEAN LEVELS OF SELECTED TRACE ELEMENTS IN RAW OIL SHALE
FOR CLASS 1 ELEMENTS" "
(ppm)
COMPARISON OF REPORTED DATA
LETC
Element
BE
Hg
Cd
Sb
Se
Mo
Co
Ni
Pb
As
Cr
Cu
Zr
B
Zn
V
Mn
F
uses
0.4
1.0
1.0
1.5
10.0
10.0
25.0
20.0
35.0
34.0
37.0
44.0
65.0
70.0
100.0
250.0
1,000.0
Mahogany
Zone
2.0
0.5
0.1
0.4
3.0
15.0
9.0
300.0
3.0
30.0
400.0
45.0
30.0
80.0
15.0
100.0
250.0
2,000.0
Saline
Zone
1.0
0.4
3.0
1.5
30.0
4.0
85.0
15.0
20.0
100.0
30.0
50.0
50.0
30.0
80.0
250.0
1,000.0
Tract C-a
0.6
2.4
0.5
0.32
—
—
—
—
6.5
—
—
—
129.0
—
—
—
550.0
Tract C-b
0.22
0.5
1.2
2.2
—
—
—
—
38.0
—
—
—
41.0
—
—
—
1,300.0
Battelle
0.2
0.35
5.0
—
11.0
30.0
40.0
80.0
25.0
64.0
—
—
115.0
—
—
—
Berkeley TRW
0.13
1.0
1.5 1
— —
14.0 -
9.0
16.0 20
30.0
88.0 44
— —
37.0
— —
— —
— —
— —
— —
— —
Representative
mean value
1.3
0.4
1.0
1.0
1.5
10.0
10.0
25.0
20.0
35.0
34.0
37.0
40.0
65.0
70.0
100.0
250.0
1,000.0
a Class I Elements are those that potentially pose environmental hazards and/or tend to be relatively abundant in fossil fuels.
b Source: Reference 18.
-------
TABLE 3-19. TRACE METAL ANALYSES OF RAW AND SPENT SHALE FUGITIVE DUSTS FROM ANVIL POINTS, COLORADO3
(ppm)
Element
Al
As
Ca
Cd
Cr
Cu
F
Fe
Hg
Mg
Mn
Na
Ni
Pb
S
Se
Si
V
Zn
Background*1
(upwind)
3.1X104
4.5
10x10*
72
231
6.9X103
2.0x1 0*
No Data
3.4X104
2.7x10*
1.6X104
3.2X102
1.9x10*
4.5X103
15
1.0x105
38
4.2x10*
Crusher0
1.3X104
3.8
2.9x10*
No Data
15
40
7.4X102
1.9x10*
1.2X101
2.0x10*
1.4X102
1.3x10*
12
17
2.4X102
1'1
1.2x105
24
1.6x10*
Mine adits
1.3x10*
7.8
2.9x10*
2
13
145
1.9X103
1.3x10*
0.1
5.1x10*
3.2X102
3.2x10*
19
68
1.3x10*
4.4
8.3x10*
43
1.5x10*
Haul road
2.7x10*
16
8.2x10*
2
29
133
11x103
2.3x10*
0.9
3.9x10*
5.0x10*
2.0x10*
43
96
S.OxlO3
3.5x101
3.0x1 0s
57
2x10*
Screening room
baghouse
4.2x10*
17
6.3x10*
6
54
53
9.8x10*
2.3x10*
0.3
3.9x10*
No Data
2.9x10
39
64
6.4x1 03
35
5.0x10*
2.3x10*
1.6x10*
Retortedd
shale transfer
1.6x10*
15
11x10*
5
31
71
1.3X103
1.8x10*
0.2
2.9x10*
3.0x10*
2.3x10*
30
55
5.3x1 03
12
4.1x10*
1.3x10*
1.8x10*
a Source: Reference 6.
° Haul road was upwind of sampler.
c Crusher is not considered typical of those that might be used by industry.
^ Paraho retort was operated in direct mode.
-------
WATER QUALITY IMPACTS
The Pace Company Consultants & Engineers, Inc.,
a Division of Jacobs Engineering Group, Inc.
Sources and Nature of Waters from Oil Shale Processing
Any commercial facility designed to produce liquid and gaseous fuels from oil
shale will both produce and consume water. Under current planning, most of the
oil shale developers envision zero discharge of wastewater from their commercial
facility. To achieve zero discharge of wastewater, the water effluent streams from
each unit operation must be treated to render them usable by other consumptive
use operations. One concept for a water management plan is shown in Figure 3-2.
PROCESSED
| SHALE PLUS
SLUDGES AND
WASTEWATER
PROCESS AREA
STORM RUNOFF
LEGEND:
FRESHWATER
WASTEWATER
__ TREATED WASTEWATER
SLUDGE
Figure 3-2. Overview of a possible water management plan.
63
-------
Water supplies will probably be available from a number of sources, and the
quantity and quality of water from each source will vary widely. Sources of
relatively good quality water may include:
Stream flow (water rights)
Purchased water from existing U.S. Bureau of Reclamation or Colorado River
Water Conservation District storage facilities
Groundwater
Runoff from undisturbed areas
Water from these relatively good quality raw water sources will generally be
stored in an impoundment located onsite in quantities designed to assure adequate
supplies during periods of low streamflow or drought. Before use in applications
that require high quality water, these stored waters will require specific treatment,
which may include sedimentation, filtration, and, if potable water is required,
chlorination.
Sources of relatively poor quality water may include:
Wastewater from retorting operation
Wastewater from shale oil upgrading
Mine drainage and wastewater from mine dewatering and dust scrubbing opera-
tions
Raw water treatment plant effluent
Sanitary and sewerage system effluents
Leachate from spent shale or raw shale piles
Runoff from disturbed areas
Wastewater streams from power plant cooling and boiler facilities
Characteristics of water derived from the first six sources listed are described in
the following paragraphs.
Wastewater from Retort Operations—
Sources of the wastewater released by retorting operations include moisture con-
tained in the shale fed to the retort, water released as a product of pyrolysis of the
kerogen, and, in some retorting processes, water obtained as a product of the com-
bustion of organic matter. Water leaves the retort with the off-gas stream and
appears as condensate when the gas stream is cooled. Some water accompanies the
liquid shale oil, and some accompanies the uncondensed gas streams. Water may
separate from shale oil during storage or may be recovered during subsequent shale
oil upgrading operations. Water may be condensed from the retort gas product
during subsequent gas cleaning operations, or it may exit with the flue gas product
when the gas is burned as fuel. Section 7 contains more detailed data concerning
water effluent streams from specific retorting processes.
Water separated from shale oil usually contains ammonia, carbonate, bicar-
bonate, sodium, sulfate and chloride ions, and certain dissolved or suspended
organic compounds such as amines, phenolics, and mercaptans. Water condensed
from retort gases contains ammonia and carbonates as the principal impurities.
Wastewater from Shale Oil Upgrading—
The characteristics of effluent water from shale oil upgrading depend on the ex-
tent of refining conducted at the site. Generally, these streams include cooling
water, wash water, and sometimes, oil-contaminated wash water resulting from
vessel cleaning and spills. A blending of all water effluent streams from oil refining
would provide a water product displaying high biochemical oxygen demand and
chemical oxygen demand (COD). This blended product would contain ammonia,
carbonates and bicarbonates, sulfides, phenols, numerous trace elements, probably
64
-------
some grease and oils, and potentially toxic materials. It would probably require
treatment procedures similar to those currently employed in the petroleum refining
industry.
Effluent from Mine Drainage, Mine Dewatering, and Dust Scrubbing
Operations—
Mine waters range in quality from 300 to 900 ppm (above the Mahogany Ledge)
to well over 5,000 ppm dissolved solids for deeper zone sources. Hydrogen sulfide
and methane have been encountered emanating from coreholes and from shafts in
the Piceance Creek Basin. Dust scrubbers will produce particulate-laden
wastewaters from both the mining and rock crushing operations.
Raw Water Treatment Plant Effluent—
Raw water must be treated before use as potable water or for other uses requiring
high quality water, such as steam generation. Water treatment system effluents
contain lime sludge, sediment, blowdown of zeolite or other water softening com-
pounds, and miscellaneous dissolved salts.
Sanitary and Sewerage System Effluent—
These streams include domestic sewage and kitchen, washroom, laundry, toilet,
and equipment wash products. Such effluents would likely be kept separate for
conventional treatment to destroy unstable organic matter and enteric
microorganisms.
Leachate from Spent Shale or Raw Shale Piles—
Should water percolate through and emanate from spent oil shale piles, the
several soluble salts present in the spent shale will be present in the leachate prod-
uct. Ions expected in leachate in significant quantity include sulfate, sodium, bicar-
bonate and calcium. Present in smaller concentrations will be ions of magnesium,
nitrate, chloride, and potassium. A more comprehensive discussion of the leachate
problem appears later in this section under Leaching of Solid Wastes.
Considerable amounts of water may be added to spent shale during compacting
operations, and additional quantities will be added by rainfall, snowmelt, and
sprinkling during establishment of plant growth, leading to the possibility of
leachate from spent shale piles. Some leachate is expected, but high evaporation
rates and the chemical, physical, and cementitious properties of spent shale may
tend to inhibit the percolation of water through the piles.
Effects of Wastewater Disposal on Surface Waters—Leonard Mueller
Present oil shale processing technologies are varied, as are the water resources
associated with each. Oil shale retorting can generate chemically complex aqueous
waste effluents containing many common organic and inorganic components.
Potential release of such waste effluents to the aquatic environment may create
harmful effects. To ascertain the degree to which these effects exist, the chemical
characteristics of the compounds—solubility, degradability, toxicity, and bio-
accumulation—must be reviewed.
At present, all major oil shale developers plan a zero discharge of wastewaters to
surface waters. All process waters will be contained in holding ponds, and any
discharge will be accidental. Wastewater treatment technologies can be employed
to meet effluent guidelines listed in NPDES permits which are based on aquatic life
criteria. Because of the complex nature of organic and inorganic components in
process water, the effects of an accidental discharge need to be determined. It is
essential that an assessment of the potential effects on the aquatic environment be
included as a fundamental part of the receiving water quality criteria. Effects of
wastewater on the aquatic ecosystem in surface waters can be determined in ex-
posure tests with aquatic organisms. Methods for the measurement of the acute
toxicity of effluents to macroinvertebrates and fish are described by several groups
65
-------
(22,23,24). Chronic effects from prolonged exposure to sublethal effects can be
observed by life cycle tests, embryo-larvae studies, or bioaccumulation studies.
A 96-hr (acute) flow-through bioassay with fish or invertebrates with an aqueous
effluent will provide toxicity data. These data can then be used to evaluate the im-
mediate effects of wastewater on receiving surface waters, but they do not identify
the specific compound responsible for the toxicity. Most toxicity data available in
the literature deal with single compounds in water; a compilation is given in
Reference 25. Wastewater from oil shale processing includes many compounds, as
shown in Table 3-20 and later in this section and in Section 4.
Bergman (26) reported flow-through acute bioassays conducted with Omega-9
and Geokinetics oil shale process waters according to standard toxicity testing pro-
cedures (23). Test organisms were exposed to seven concentrations of the test solu-
tion plus well water controls. Fish were tested for 96 hrs, while Daphniapulex were
exposed for 48 hr. The results of acute flow-through bioassays are presented in
Table 3-21. The 96-hr (fathead minnow and rainbow trout) and 48-hr (Daphnia
pulex) TL50 dilutions for both process waters tested were at dilutions of less than 1
percent process water for all test animals. The Omega-9 retort water TLio ranged
from 0.42 to 0.57 percent, and the Geokinetics retort water TLSO ranged from 0.46
to 0.88 percent for the three species tested. Acute toxicities of Omega-9 and
Geokinetics oil shale retort waters were remarkably similar for the three aquatic
species tested. Bergman recommended an estimated safe concentration for this par-
ticular Geokinetics oil shale retort water to be 0.09 percent based on flow-through,
96-hr bioassays and application factors estimated from similar process waters.
The chemical characteristics of Omega-9 retort water (28) suggest that inorganic
constituents may contribute substantially to its acute toxicity. Bergman (26) found
that an artificial mixture of inorganic constituents in Omega-9 retort water was
only slightly less toxic in acute tests than Omega-9 retort water alone. His studies
indicate that inorganics, primarily ammonia, are responsible for the toxicity of
Omega-9 retort water.
Bergman (26) conducted a 69-day embryo-larval test following procedures
published by McKim (29). Rainbow trout eggs were exposed to five concentrations
of Omega-9 oil shale retort water through hatching and an initial period of fry
growth. Egg survival, hatchability, fry survival, and growth were monitored. The
lowest dilution or concentration which had any significant effect on egg hatchabil-
ity, or fry survival or growth was 0.16 percent, and the highest concentration which
had no effect on fry survival or growth was 0.08 percent.
The 96-hr TL50 values for rainbow trout and fathead minnows exposed to
Paraho oil shale retort water (1977-78 composite) in flow-through bioassays were
0.068 and 0.071 percent, respectively, whereas the 48-hr TL50 for Daphnia pulex
was 0.15 percent (26). To protect aquatic species in the event of an accidental
release of untreated Paraho Tank-500 process water to natural waters, a dilution
factor of 10,000:1 would be required.
TABLE 3-20. WATER QUALITY CHARACTERISTICS OF GEOKINETICS
OIL SHALE RETORT WATER" b
Water quality parameter mg/lc
Alkalinity, Total (CaC03) 9,500
Biological Chemical Demand (5 day) d
Carbon:
Bicarbonate (HC03~) 8,000
Carbonate (CO3~~) 1,800
Dissolved Organic Carbon d
Total Organic Carbon d
66
-------
Water quality parameter
Chemical Oxygen Demand
Chloride
Conductance (mmno/cm)
Cyanide
Fluoride
Hardness (CaC03)
Metals:
Arsenic
Aluminum
Barium
Boron
Cadmium
Calcium
Chromium
Copper
Lead
Iron
Manganese
Magnesium
Mercury
Nickel
Potassium
Selenium
Silver
Zinc
Nitrogen:
Ammonia (NH3)
Ammonium (NH4+)
Nitrate (N
-------
TABLE 3-21. SUMMARY OF ACUTE, FLOW-THROUGH BIOASSAY RESULTS FOR RAINBOW TROUT (Salmo gairdneri),
FATHEAD MINNOWS (Pimephales Promelas), AND Daphnia pulex EXPOSED TO PROCESS WATERS"b
Process water
Omega-9 oil
shale retort
water
Geokinetics
oil shale
retort
water
Species0
Fathead minnows
Rainbow trout
Rainbow troutd
Daphnia pulex
Fathead minnows
Rainbow trout
Daphnia pulex
Number of
organisms per
concentration
20
20
—
10
20
20
10
Highest test
concentration
0.8%
0.8%
-
0.8%
1.25%
1.25%
1 .25%
TLa,
0.57%
0.42%
0.51 %
0.54%
0.88%
0.46%
0.56%
Observations
Lethargic at 0.4%
Lethargic and loss of equilibrium
at 0.4%
cDechlorinated tap water for dilution
Test duration was 48 hr
Hyperactive and sensitive to
disturbance at 0.625%
Sensitive to disturbance at 0.31%
Test duration was 48 hr
a Source: Reference 26.
^ All acute tests were conducted at 14°C for 96 hr and well water dilution, unless otherwise specified.
c Rainbow trout mean weight was 15.6 g and mean length was 105.4 mm; fathead minnow mean weight was 0.93 g and mean length was 41.2 mm.
^ Omega-9 JLM dilution of 0.51% was obtained using dechlorinated tap water as dilution water in a separate test; a value of 0.38% to 0.39% was reported earlier (1977 Annual Report) for the TL^, dilution in
this test, but the TLM dilution was recalculated at 0.51% after all tests with low dissolved oxygen levels were discounted.
-------
The research reported here is limited to three specific retort process waters. More
extensive and longer studies are needed to evaluate the biological and ecological ef-
fects of an oil shale industry on surface water. Monitoring devices are available to
detect leaks from holding ponds and waste treatment facilities and they can be used
as an early warning of faulty containment systems. Section 2 lists pollutants which
should be part of a monitoring program. Other tests may be developed as early in-
dicators of toxicity. Lebsack (30) developed a rapid aquatic toxicity screening
technique using luminescent bacteria. (Algae are also quite sensitive to toxic
materials.) Aquatic organisms serve as continuous monitors of their environment
and are sometimes quite sensitive to very low (ppb) concentrations of organic
pollutants. Disappearance or relocation of aquatic organisms may be an effect of a
change in water quality parameters.
Possibly no acute or chronic effects will result from a wastewater discharge
because of the low concentrations of compounds. However, compounds of low
water solubility may be bioaccumulated by aquatic organisms and become toxic to
the consumer, other fishes, birds, or man. Oil shale process water contains single-
ring aromatics and polynuclear aromatics that contain suspected carcinogens. If
there is a discharge of process water into the aquatic environment, sediments may
accumulate these compounds and later release them slowly. Research is needed on
the degradation of these compounds and their potential for bioaccumulation in the
aquatic environment.
Effects of Wastewater Disposal on Groundwaters—Backflood
Waters—Bob Newport
Although the following discussion focuses on modified in situ retort operations
of the Piceance Basin, general information contained here will be applicable to
other oil shale regions and surface retorting.
Numerous hydrological investigations by government agencies and mining in-
terests have attempted to define local and regional groundwater systems and their
relationship to oil recovery from vast oil shale deposits of the Piceance Basin.
These efforts have contributed significantly to the understanding of this quantity
relationship, but they have failed to define groundwater quality variations likely to
occur during oil recovery. In the Piceance Basin, the groundwater system is com-
plex. Predictive movements of groundwater and multiple aquifer relationships
have defied quantification. Using available hydrogeological information and the
current state of knowledge about oil shale operations, this section addresses poten-
tial problems and operational and treatment scenarios as they relate to ground-
water quality. In this effort, it will be necessary to summarize regional hydrology,
wastewater types, and waste disposal options.
Hydrology of the Piceance Basin
In addition to a significant alluvial aquifer, the Piceance Basin has two major
aquifers separated by the Mahogany Zone, which acts as an aquitard. The
Mahogany Zone also is the richest oil shale formation scheduled for exploration.
This zone, varying in permeability because of ill-defined fractures, restricts full
communication between the two major water systems. These two aquifers are fed
by percolating surface water that generally passes from the upper aquifer through
the Mahogany Zone to the lower aquifer. In the northern part of the basin, heads
of the aquifers are reversed, resulting in reverse flow—from the lower to the upper
aquifer.
Base flows of area springs and streams are fed by the alluvial and both major
aquifers. Attempts to determine what percent of stream flow could be attributed to
each aquifer have been unsuccessful.
Included in both major aquifers are less defined minor aquifers separated by
aquitards considerably thinner and exhibiting higher transmissibilities than the
69
-------
Mahogany Zone. Communications between minor aquifers result in uniform water
quality throughout the major zone. In the lower major aquifer, water quality
decreases with depth.
Detailed quality of surface and groundwaters will be considered in other sections
of this report. For the purpose of this section, total dissolved solids concentration
(averaged from various sources) will be used as an indication of water quality
throughout the system.
The following figures represent the gross differences between various water types
of the Piceance Basin:
Water Type TDS
Springs 925
Alluvial aquifer 1,000
Piceance Creek 800
Upper aquifer 1,100
Lower aquifer 6,200
As indicated by the foregoing discussion, surface water, shallow alluvial
aquifers, and the upper and lower major aquifers are intimately related. Physical or
chemical changes in part of the system will ultimately affect the rest of the system.
Without intensive research investigations, effects of these changes on area water
resources will await several years of commercial oil shale operations. The purpose
of this section is to indicate probable areas of primary concern and suggest control
and disposal options.
Wastewater Types
Water from mine dewatering operations, process water, boiler blow down,
domestic waste and cooling tower water are major wastewater types considered as
potential contaminants to groundwater. Wastewater from various other sources
will possibly be combined with major wastewater volumes, simplifying treatment
and disposal options. Because of their quality and volume, process water and water
from mine dewatering are of prime concern.
Mine Dewatering—
At the various sites under serious consideration for surface retorting, mine
dewatering will be insignificant. Locations of these operations are in areas where
major groundwater aquifers are not intercepted by shale removal activities.
Active in situ operations in the Piceance Basin are currently conducting or an-
ticipating extensive dewatering programs that will permit shaft sinking, mining,
and eventual retorting. Two approaches to this major problem are being con-
sidered by mining operators. One is to drill peripheral wells around the area to be
mined and to conduct the recovery activities in the cone of depression formed by
continuous groundwater evacuation. The second approach is to dewater the mine
directly as mining operations progress and water enters the mine. Regardless of the
method used, mine dewatering will significantly affect groundwater quantity. In
addition, adverse groundwater quality variations may result.
Estimated quantities of groundwater production resulting from dewatering one
mine range from 1,893 1pm (500 gpm) at the initiation of the mining operation to
more than 37,8501pm (10,000 gpm) when full scale production is reached. Annual
groundwater demands during full-scale production amount to 246 ha m/year (2000
acre ft/year) and will eventually create a radius of influence 9.6 to 16 km (6 to 10
mi) from the mine.
Following formation fracturing and mining, but before retorting, groundwater
evacuated may decrease in quality because of new mineral surface exposure. This
quality change, if anticipated, could be controlled by one of various treatment op-
tions discussed later. Increased water consumption during operational expansion
should reduce the volume of evacuated water requiring treatment.
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Process Heater—Process water (water produced with the oil) is estimated to ap-
proximate oil production volumes. Thus, in the case of full-scale production of one
mine at 100,000 bbl/day, large volumes of low quality water will require extensive
treatment before disposal.
During full-scale retorting operations, both process water and water from
dewatering operations will be produced. Treatment and disposal options and their
potential effect on groundwater must be a consideration throughout the opera-
tional phase.
Wastewater treatment is covered at length in Section 4 of this document. Specific
treatment options likely to be used during commercial operations will be mentioned
here as they relate to groundwater quality. Each treatment or disposal method will
be discussed in terms of its short-term, long-term, or intermittent application and
potential impact on area groundwater resources.
The nature of developing oil shale operation dictates that water supplies and
demands will be extremely variable. In the initial stages of mining development,
disposal of essentially all water evacuated from the mine will be necessary. When
commercial retorting begins and water demands increase, it is conceivable that sup-
plemental off-site supplies will be required. Even during full-scale operations,
variations of production-consumption ratios will occur, necessitating standby
treatment, disposal, or supply systems. Considering extremely variable production
and consumption estimates, one or more of the following treatment or disposal
systems will be utilized.
Waste Disposal Options
Reinfection—From the beginning of shaft construction until commercial-scale
retorting begins, essentially all water from dewatering operations will require
disposal. Selective reinjection of this water is one method currently in use and ap-
pears to be an acceptable disposal method. Groundwater quality variations
associated with this practice are unknown. The general assumption is that ground-
water extracted could be reinjected into the same groundwater system causing
negligible changes. While in fact this may be true, consideration must be given to
possible water quality changes caused by mining, dewatering, and reinjection that
will necessitate operational adjustments in treatment and disposal systems.
During injection, increased mineralization of groundwater may occur as a result
of increased groundwater flow, exposure of new mineral surfaces following frac-
turing, changes in microbial populations as a result of environmental alterations,
and increased mineral availability resulting from varying water types moving
through foreign mineral strata. The effect of these complex and interrelated factors
on groundwater has not been determined. Research addressing groundwater qual-
ity variations associated with oil shale development has begun, but accelerated ef-
forts are necessary to assess the magnitude of the problem. If significant ground-
water quality changes do occur, existing technology and hydrogeological informa-
tion cannot be expected to foretell its long-term effects on regional water resources.
Many of the potential problems associated with wastewater injection can be ef-
fectively controlled by pretreatment. For this reason, injection of wastewater
should be considered as a viable disposal method.
It should be mentioned that well integrity is basic to development of an accept-
able injection system. Injection wells should be constructed and maintained to in-
sure that wastewater flows are confined to preselected formations.
Spray Irrigation/Soil Treatment—Soil treatment of industrial and municipal
wastewater is well documented and is recognized as an environmentally acceptable
treatment method. Considering anticipated oil shale waste quality, this treatment
method, with slight variation, could be extended to include oil shale wastewater.
Application of wastewater to semiarid areas of oil shale country appears feasible
and possibly beneficial. This system could be used full- or part-time or in series
with other treatment methods.
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Successful adaptation of a soil treatment system to industrial waste in Wyoming
indicates that regional climatic restraints of the Piceance Basin would not adversely
affect waste treatment.
Groundwaters associated with soil treatment systems have been and continue to
be investigated. Current indications are that groundwater is not adversely affected
by this method of treatment.
Ponds or Lagoons—Collection of large volumes of water in holding ponds or
lagoons for the sole purpose of treatment by evaporation or percolation is not
recommended. However, ponds constructed for the purpose of temporary contain-
ment of wastewater awaiting treatment before disposal seem necessary. These
ponds would be available as emergency storage reservoirs in the event of treatment
system failures or modifications, and they would serve as surge tanks if operational
variations resulted in wastewater volumes exceeding design limitations of treatment
systems.
Ponds should be constructed to eliminate percolation effectively; otherwise,
adverse effects on groundwater will result. The active life of an in situ oil shale
operation is estimated to be 30 years. Small percolation volumes of wastewater over
several years could be significant. If wastewaters are to be confined in ponds, liners
or other acceptable materials are recommended. Groundwater quality monitoring
(addressed in a later section of this document) is recommended.
Spoil Stabilization and Revegetation—Various figures, depending on the in-
vestigator, have been used to indicate the amount of wastewater that can or must
be used for stabilization and revegetation of spoil piles. The two basic recovery
methods, in situ and surface retorting, add additional variables. Surface retorting
spoils are composed of spent shale residues, whereas in situ spoils consist of raw
shale. Water requirements for stabilization, revegetation, or saturation will vary
considerably, depending on spoil type. Groundwater is the ultimate recipient of
leachate from either spoil type.
Leachate quantities are a function of porosity and application rates. Leachate
quality is a product of spoil mineralogy, organic residues, and quality of water used
for stabilization and revegetation. Minor changes in wastewater quality used for
stabilization may result in major changes in leachate quality. It is anticipated that
wastewater will be used for spoil stabilization. If wastewater is to be applied to
spoil piles, the nature and quality of leachate should be carefully considered.
Groundwater monitoring associated with spoils wastewater disposal is covered in a
later section.
Backflood Waters—Following the retorting operations, groundwater will be
allowed to fill the rubblized retorts. Groundwater chemical changes associated with
backflood waters during advance oil recovery operation and following eventual
mine abandonment are unknown. Estimates of potential problems associated with
this post operational phase vary considerably. One theory is that abandoned retorts
will act as carbon filters, improving groundwater quality. Another theory indicates
that numerous organic and inorganic contaminants will be placed in solution and
released to groundwater.
Current oil shale operators seem prepared to continue dewatering operations
associated with abandoned retorts until backflood water quality stabilizes at an ac-
ceptable level. Time required for stabilization will depend on absorption capacity
or deabsorption persistence of retorted mineral surfaces. Conceivably, this could
require years of dewatering, treatment, and subsequent disposal.
It is recommended that backflood waters of low quality be confined to local
groundwater systems, regardless of time or funding demands.
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Long-term Effects of the Oil Shale Industry on Surface Water Resources
of the Colorado River Basin—Wesley Kinney
The total impact of a mature oil shale industry on surface water resources cannot
be quantitatively assessed until long after production on a commercial scale has
begun. Accurate prediction requires a thorough knowledge of the hydrological
regimes of the area and an understanding of the nature, transport routes, and fates
of pollutants subject to release to surface waters. Recent investigations have greatly
advanced the knowledge of subsurface and surface water regimes throughout the
oil shale area, to the point where water resources are fairly well described with
respect to both quality and quantity. But knowledge about the pollutants
themselves is still lacking, i.e., their mobilization potential, chemical nature,
transport pathways, fates, and consequences of exposure to receptors. This is par-
ticularly true of the numerous complex trace organic constituents associated with
raw and retorted shale and wastewaters. A great number of constituents have been
identified as potential pollutants with carcinogenic, mutagenic, teratogenic or
other toxic properties based on laboratory studies. However, little information is
available on the potential hazards of these constituents at levels likely to be en-
countered in surface waters.
In the following section, potential water-related problems are addressed in the
context of the probable cumulative regional impact of a maturing, commercial oil
shale industry, assuming utilization of a mix of extraction and processing
technologies. The possible effects of potential pollutants on surface water quality
and quantity and the resulting impact on aquatic life, public water supplies,
livestock, irrigation agriculture, and selected industries are evaluated. Where suffi-
cient data are available, attempts are made to relate historical, current, and pro-
jected water quality data to water quality criteria for the various water use
categories.
Salinity—
A mature oil shale industry and related industrial and urban development could,
over the long term, increase the salinity at Hoover Dam through both salt-
concentrating and salt-loading processes. Salt-concentrating effects would occur as
relatively high quality surface waters are withdrawn for consumptive uses and as a
result of evaporation and transpiration. Assuming that substantial amounts of
groundwater and process water are available for use, it is not anticipated that salt
concentrating effects will add to the salinity detriment of the Colorado River until
many years after development is instituted (12). Salt loading could result from
leaching of spent shale disposal piles or byproduct storage piles, release of saline
mine or process waters, groundwater disturbances caused by reinjection of excess
waters, and municipal and industrial waste discharges. Construction of roadways
and utility corridors, removal of overburden, and the actual mining operations
would enhance weathering and erosion of exposed materials, thereby increasing the
potential for mineral release to surface waters directly and via subsurface waters.
With the practice of surface retorting, leachates from spent shale constitute a
potential source of salt loading to surface water owing to the proposed disposal
methods and the physical and chemical characteristics of spent shale (12). The
mineral composition of spent shale varies somewhat, depending on the retorting
process used and the differences in peak temperatures reached in the various
retorts. But regardless of the process used, spent shale materials are represented
primarily as oxides of the various minerals present in raw shales, many of which are
highly water soluble (12). Ward et al. (31) investigated the water pollution potential
of spent shale residues from various retorts. Analyses of water after intimate con-
tact with spent shale from the TOSCO and Union Oil Company retorts revealed
high concentrations of sodium, calcium, magnesium and sulfates. Leaching tests
demonstrated that soluble salts are readily leached from spent shale columns; con-
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sequently, a definite potential exists for high concentration of the major ions (Na*,
Ca++, Mg++, and SOi) in the runoff from spent oil shale residues (31).
Weathering and leaching of spent shale piles will occur over long periods of time.
Even though attempts will be made to stabilize the piles through compaction and
with natural soil and vegetative cover, erosion and leaching of dissolved solids will
undoubtedly occur, particularly during the periods of active disposal and shale-pile
buildup.
Raw wastewater produced by retorting oil shale contains a variety of constit-
uents, thus presenting a wastewater disposal or treatment problem. If the untreated
water is used to moisten shale piles, the mineral components may be physically or
chemically trapped within the shale pile temporarily, but the potential for leachates
eventually moving through the pile would seemingly be increased.
In the Piceance Basin, disposal of excess mine waters poses a potential problem
that may be intensifed as the oil shale industry matures. During the early stages of
development, relatively high quality excess water will be released directly to local
drainages; but through time, the excess water will increase in salinity, and discharge
of untreated water to local streams may not be permitted. It may be necessary dur-
ing initial development to store excess or poor quality groundwater in impound-
ments, and during later stages of development to reinject the excess water into
aquifers (12). Both methods of disposal could potentially result in release of saline
waters into streams. The first would be through failure of a dike impounding saline
waters, and the second through upward movement of poor quality groundwater
and eventual discharge to surface waterways (12).
Municipal and industrial developments could cause additional salinity problems.
As the population of the area expands, increased amounts of salts may enter sur-
face waters by means of municipal and industrial discharges, thereby increasing the
total mineral burden in localized areas. Since the nature and extent of urban and
associated industrial growth cannot be predicted with certainty, the extent to which
such growth will compound the salinity problem is unknown.
As water becomes highly mineralized, its utility for industrial and agricultural
purposes, public water supply, and as a medium for freshwater organisms is im-
paired. Present salinity concentrations in the lower Colorado River have reached
the level at which some impairment for industrial purposes, irrigated agricultural
uses, and municipal uses is occurring (32). As TDS levels increase above 500 mg/1
(4.17xlO~3 Ibs/gal), treatment costs soar for industrial and municipal water users,
and irrigated agricultural crops characteristically undergo reductions in yield (33).
Highly mineralized water causes scaling and corroding of water pipes, boilers, and
heaters, adding to increased maintenance and treatment costs for industrial and
household users. As salt concentrations in irrigation waters increase, soils become
more saline, thereby restricting the variety of crops that can be grown successfully
(33).
Levels of TDS, hardness, and specific constituents that normally represent max-
imum acceptable limits for particular industrial purposes were summarized by the
National Academy of Sciences (NAS) (33). Alhough ambient surface water quality
throughout the Colorado River system is acceptable for a wide range of industrial
uses, concentrations of specific constituents that exceed the recommended limits
for cooling purposes and certain industrial process uses have been reported.
In terms of EPA guidelines, the surface waters of the Colorado River system are
acceptable for livestock watering purposes, but most of the mainstem waters have
for years exceeded the guideline level for sensitive irrigated crops (33). Conductivity
and TDS values for these waters typically fall into the 750- to 1,500-mmhos/cm
(295- to 590-mmhos/in.) and 500- to 1,000-mg/l (4.17xlQ-3- to 8.24xlQ-3-lbs/gal)
ranges, respectively, the levels of possible detrimental effects for sensitive crops.
Although drinking water criteria before 1973 recommended against using waters
with a TDS limit exceeding 500 mg/1 (4.17xlQ-3 Ibs/gal) (34), this recommendation
was not adopted by EPA (33,35). Many public drinking water supplies with TDS
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levels exceeding 500 mg/1 are in current use with no ill effects to the consumers.
The EPA does, however, recommend limits of 250 mg/1 (2.09x10-' Ibs/gal) for
both chlorides and sulfates in public drinking water supplies (33,35).
The effects of highly mineralized or saline water on aquatic life vary tremen-
dously with the concentrations of specific ionic constituents. Salinity in fresh water
is defined as the total concentration of the ionic components (36,37). The most
conspicuous anionic substances that contribute to salinity in the Colorado River
system are bicarbonates, sulfates, and chlorides. These substances combine with
the metallic cations calcium, magnesium, sodium, and potassium to form ionizable
salts. Silica, which contributes to the total mineral burden, may be present in
several forms, including complex ions such as colloidal silica or as sestonic mineral
particles; but most silicates in inland waters are probably present as undissociated
silicic acid (36). The absolute and relative abundances of these materials are impor-
tant factors regulating productivity of waters and influencing the structure of com-
munities.
Water hardness is governed chiefly by the presence of calcium and magnesium
cations in waters. In general, the biological productivity of a water body is directly
correlated with its hardness. However, hardness per se has no biological
significance because biological effects are functions of specific ions and combina-
tions of elements (33). Many minor dissolved substances contribute to the total
hardness and salinity of waters, but since they are usually present only in trace
quantities, their total contribution from the standpoint of hardness is rather in-
significant.
It is estimated that the salt concentrating effects alone of a 1-million-bbl/day in-
dustry would increase the salinity at Hoover Dam by 10 to 27 mg/1 (8.34x10"' to
2.25xl04 Ibs/gal), depending on the sources and quantities of water required (12).
The impact on the river would not be immediate, but as high quality groundwater
supplies decreased and the rate of surface water withdrawal increased, the effects
would become more pronounced (12).
Toxic Substances
Many activities associated with the development and operation of an oil shale in-
dustry that could potentially increase the total salt burden of surface waters could
similarly increase the potential for contamination with a variety of toxic
substances, including trace elements and numerous organic substances.
Raw and retorted shale contain a number of potentially toxic substances in vary-
ing concentrations, as discussed in Section 3 (Solid Waste Impacts). Leaching
studies by Culbertson et al. (38) and Ward et al. (31) have shown that soluble salts
are readily leached from spent shale piles; but the mobilization potential of many
inorganic and organic trace constituents is virtually unknown (38,39). Conse-
quently, knowledge of elements and compounds associated with oil shale and sub-
ject to release to surface water as a result of industrial development is incomplete.
The extreme difficulty in conducting organic analyses has discouraged most re-
searchers and has largely limited monitoring efforts to the measurement of organic
carbon, phenols, oils and grease, and a few similar analyses. Thomas (40) sum-
marized the results of a study by Pellizzari (41), which reported organic substances
found in process water from oil shale based on analyses of six samples. Thomas
listed maximum levels of those compounds that occurred at an arbitrary level of
100 ppb or greater (Table 3-22).
Other possible sources of trace elements and other toxic substances include stack
emissions from processing operations, catalysts and chemicals used in oil
upgrading and gas processing, contact of high quality water with highly mineral-
ized groundwater, municipal and industrial wastes from expanding communities,
and development of ancillary extractive industries.
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TABLE 3-22. VOLATILE AND SEMIVOLATILE ORGANIC COMPOUNDS
PRESENT AT CONCENTRATIONS OF 100 ppb OR GREATER
IN AQUEOUS SAMPLES FROM 136-TONNE LETC OIL
SHALE RETORT.
Volatile compounds
Acetone0
Benzene0
Cyanobenzene
t-butanol
2-heptanone
Methyl ethyl ketone
2-octanone
Methylcyclopentane
2-pentanone
n-methylpyrazole
Pyridine
C2-alkylpyridine isomer
Toluene0
ppbb
200
134
235
130
244
152
126
680
123
177
185
240
300
Semivolatile compounds
Benzylamine
Benzole acid
C8HnN isomer
C9H13N isomer
C9H140 isomer
Cresole isomers0
n-heptanol
Dimethylnaphthalene isomers
n-octanoic acid
Phenol0
C2-alkyl phenol isomer
Ethylphenol isomer
Dimethylphenol isomer0
Alkylpyridine isomer
Trimethylpyridine isomer
ppb
377
493
621
422
175
779
165
199
155
461
337
321
1011
176
762
a Source: Modified from Thomas I40) after Pellizzari (41).
b Values represent maximum concentrations reported based on analyses of six samples.
c Listed as suspected carcinogens by Christensen and Fairchild I42).
A total population increase of 66,000 to 115,000 is estimated to be required to
support a mature oil shale industry—representing nearly a twofold increase over
the 1970 population of the area (12). Potential toxicants that may be introduced to
waters as a result of industrial and urban growth include chlorine, cyanide,
detergent builders, phenolic compounds, phthalate esters, polychlorinated
biphenyls (PCB), and toxic forms of nitrogen, including ammonia, nitrites, and
nitrates.
Increased levels of pesticides and their residues in waterways can be expected as
pesticide usage increases. The creation of new lawns, parks, and recreational
facilities will likely result in greater domestic use of pesticides by homeowners and
communities. Expanded industrial growth also characteristically results in in-
creased usage of various pesticides, as does maintenance of utility corridors and
roadside rights-of-way.
The types and extent of ancillary industrial growth that may be stimulated by oil
shale development cannot be predicted with any certainty. The extensive deposits
of nahcolite and dawsonite found in association with oil shale may lead to the
recovery of soda ash, aluminum, or compounds thereof. Technology for the
recovery of sodium materials from these deposits has been demonstrated on a pilot
scale, but commercial extraction has not been attempted. Aluminum and
aluminum compounds contained in dawsonite have been recovered from retorted
shale on a small scale. Trona and halite occur to some extent in the Green River
Basin in Wyoming, and sodium materials, petroleum, natural gas, asphalt, tar
sands, and coal are scattered throughout the Green River Formation of the oil shale
area. It is not presently known if all of these materials are present in commercially
significant quantities.
Concentrations of trace elements and other toxic substances vary widely
throughout the Colorado River system with time and location. Trace element data
presented by Kopp and Kroner (43) reveal few conclusive trends with respect to
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trace metal concentrations relative to location, but a few observations are notewor-
thy. Arsenic, beryllium, and cadmium were not detected at all and cobalt and
vanadium were each reported at only one site—the former in the upper Green
River, and the latter in the upper Colorado. Barium, boron, copper, iron,
manganese, strontium, and zinc were reported at all locations, but only boron ex-
hibited conspicuously increasing concentrations in a downstream progression.
Silver and molybdenum were detected at all but the lower Colorado mainstem sta-
tions. The distribution of lead, nickel, and aluminum was sporadic, each being
detected in only one or two samples at various locations.
Data on concentrations of trace metals in the mainstream of the Colorado at
Yuma, Arizona, during 1958-59, as compiled by A. D. Little (44), revealed max-
imum concentrations of aluminum, barium, chromium, copper, iron, and
manganese in the range of those reported by Kopp and Kroner (43) at the same
location, but the latter reported much higher concentrations of boron and stron-
tium. Conversely, nickel concentrations were reported to be an order of magnitude
higher during the 1958-59 study than were reported by Kopp and Kroner (43).
Rubidium and titanium were present at Yuma in concentrations of less than 0.01
mg/1 (8.34xlO-8 Ibs/gal) during 1958-59 (44).
Maximum concentrations of boron, fluoride, and iron at selected sites on the
Colorado, Green, and White Rivers during 1964-65 and 1968-70 were summarized
from USGS documents (45,46) by Kinney et al (47). The boron data for the upper
watershed are in line with those reported by Kopp and Kroner (43), but the USGS
data do not show the increase in concentrations in the lower watershed that was so
apparent in the Kopp and Kroner data.
Iron concentrations reported by USGS were typically lower than those reported
by Kopp and Kroner and A. D. Little for the same general area of watershed.
Fluoride concentrations were not reported by Kopp and Kroner or A. D. Little, but
USGS data show relatively uniform concentrations ranging from 0.30 to 1.0 mg/1
(2.50x10-' to 8.34x10-' Ibs/gal) throughout the watershed.
Data on ambient levels of such toxic substances such as chlorine, detergent
builders, phenolic compounds, phthalate esters, and PCB in the Colorado River
system are scarce or nonexistent. A single analysis for methylene blue active
substances (MBAS) on the White River near Watson, Utah, yielded concentrations
of 0.02 mg/1 or 1.67x10-' Ibs/gal (USGS data from EPA's water quality com-
puterized storage and retrieval system (STORET)). Water analysis for PCB on
filtered, unfiltered, and suspended samples yielded no positive results, but a single
mud analysis revealed a concentration of 2.0 mg/kg (2xlO"6 Ibs/ton) on the Col-
orado River near Cisco, Utah (USGS data from STORET).
Cyanide and phenol data were collected by Voorheis-Trindle-Nelson (48) on the
White River stations adjacent to Tracts U-a and U-b and on Evacuation Creek,
which transects the sites. Eighty-six analyses of White River water for phenols and
50 analyses for cyanide revealed maximum concentrations of 0.014 and 0.01 mg/1
(1.17x10"' and 8.34xlQ-8 Ibs/gal), respectively. Maximum concentrations in
Evacuation Creek were 0.024 mg/1 or 2.00x10"' Ibs/gal for phenols (30 analyses)
and 0.02 mg/1 or 1.67xlQ-' Ibs/gal for cyanide (18 analyses).
Low levels of chlorinated hydrocarbon pesticide residues have been detected in
the Colorado River system by a number of investigators. A. D. Little (49) sum-
marized levels of organochlorine pesticides that have been reported at various loca-
tions in the Colorado River system during 1964-68. Sufficient data are not available
to discern trends with respect to time or location.
Toxic substances in surface waters are primarily of concern because of their
potential impact on the aquatic biota, agriculture, and man. Since the impacts of
toxic materials on freshwater biota, livestock, irrigation crops, and man are
discussed in great detail by McKee and Wolf (50), the National Technical Advisory
Committee (50), and NAS (33), they are only superficially addressed in this report.
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Many naturally occurring dissolved substances in water, although vital to life
functions in trace amounts, can prove harmful or fatal to plants and animals, in-
cluding man, when present in high concentrations. The toxic properties of trace
metals such as arsenic, copper, and zinc, all essential to human nutrition, are well
known, and various compounds of these metals have been used for years in the
manufacture of pesticides.
The toxicity of metals in water varies considerably with the chemical and physical
characteristics of the waters. For example, the pH of water influences the solubility
and therefore the toxicity of many metals, including aluminum, copper, and zinc.
The presence of certain metals in water can enhance the toxicity of other metals by
synergistic reactions. For example, the toxicity of zinc, cadmium, and mercury is
increased by the synergistic action of copper. On the other hand, the toxic effects
of many metals, including zinc, copper, lead, cadmium, chromium, and nickel, are
much less pronounced in highly mineralized (hard) waters than in soft waters owing
to the antagonistic action of calcium, carbonates, and other common hard water
constituents.
Cadmium, lead, chromium, and mercury are examples of nonessential,
nonbeneficial elements in the diet that are highly toxic to aquatic life, humans, and
livestock in low concentrations. Boron, cobalt, and molybdenum are known to be
essential to higher plants in trace quantities, but may be deleterious to crops if
highly concentrated in irrigation waters.
Ambient surface water data for waters within the Colorado River system reveal
that maximum concentrations of boron, molybdenum, and nickel exceeded the ac-
ceptable limits for continuous irrigation at several locations. Maximum concentra-
tions of iron and lead at some stations in the lower Colorado exceeded the recom-
mended limits for drinking water. Lead concentrations in one sample in the lower
Colorado near Boulder City, Nevada, also exceeded the maximum acceptable limit
for aquatic life.
These comparisons of water quality criteria with ambient water quality data
clearly illustrate that concentrations of certain trace minerals in Colorado River
Basin surface waters at times exceed the maximum acceptable limits for specified
water uses. The utility of these waters can only be further impaired by activities
that disturb large areas of the landscape, create large volumes of waste material for
disposal, alter surface water and groundwater regimens, and lead to increased
usage of chemicals in the area—unless such developmental activities are carefully
planned and closely regulated.
Although concentrations of trace minerals in the surface of the Colorado River
Basin are not exceptionally high when compared with river basins in heavily in-
dustrialized areas of the country, the extent to which the surface water
characteristics will be altered by industrialization and urbanization of the area is
unknown. For example, arsenic and cadmium, both highly toxic metals, are com-
mon constituents of rocks and could be released to the aquatic ecosystem through
weathering of the exposed bedrock. In addition, cadmium could be released as a
leachate from spent shale, and arsenic, which is expected to volatilize during retort-
ing, may become an air emission. Numerous additional heavy metals could be
released to waterways in quantities sufficient to impair seriously the utility of these
waterways for specific beneficial uses.
In the Colorado River Basin, pesticides may constitute the greatest potential
hazard of all toxic substances of nonpoint source origin. Pesticides include a
myriad of natural and synthetic chemicals used to control or destroy plant and
animal species under a variety of situations. Depending on the intended use or
target organisms, pesticides are frequently categorized as insecticides, herbicides,
fungicides, rodenticides, nematocides, etc.
The major threat of pesticide contamination of waterways arises from insec-
ticides and herbicides because they are the most widely used categories of pesticides
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and many are resistant to degradation, persisting in the environment in forms that
are toxic to aquatic and terrestrial life, including humans. The entry of pesticides
into waterways in large doses, as frequently occurs with spills or accidental
discharges, may have an immediate and dramatic impact resulting in annihilation
of the biota and poisoning of public water supplies. More frequently, however,
pesticide pollution of waterways has a more subtle effect as residue levels slowly
build up over time.
Most pesticides undergo rapid degradation in the environment and, though they
are highly toxic for a short while, they soon are degraded, metabolically or other-
wise, to relatively innocuous materials. On the other hand, some pesticides, par-
ticularly the organochlorine insecticides are extremely resistant to degradation and
are subject to biological accumulation directly from the water and through the
food web. This results in insecticide concentrations in higher trophic-level
organisms several thousand times higher than ambient water levels.
Ambient water quality data for the Colorado River System reveals that concen-
trations of aldrin, DDT, dieldrin, and endrin approached or exceeded the recom-
mended maximum levels for the protection of aquatic life, humans, and livestock
at various locations. In recent years fish and bird mortalities attributable to
organochlorine pesticides have occurred in and downstream from irrigation ditches
in the Lower Colorado Basin. Few ambient data on levels of other categories of
pesticides in the Colorado River system are available. Consequently, it is not
known whether they constitute a potential hazard.
Of the organic compounds identified in process waters, phenols, dimethyl
phenol isomer, cresole isomers, acetone, benzene, and toluene are of specific con-
cern. All are suspected carcinogens that have been identified as high priority EPA
effluent pollutants. The cresoles and phenols are of particular concern since they
have toxic as well as carcinogenic properties and may occur in high concentrations.
Concentrations of phenols in the White River and Evacuation Creek, as reported
by Voorheis-Trindle-Nelson (48) exceed the EPA guideline levels for drinking
water (33).
Certain toxic substances (e.g., phthalate esters, polychlorinated biphenyls,
cyanide, and chlorine) generally occur in water at hazardous levels only in heavily
industrialized metropolitan areas. Consequently, it is unlikely that they pose a
serious hazard in the Colorado River Basin at the present time. Accelerated in-
dustrial and urban expansion, however, could significantly increase ambient levels
of these substances in the aquatic ecosystem.
Microorganisms
Possibilities exist for the microbial contamination of surface waters as a conse-
quence of rapid population increases. This can result in overloaded sewage treat-
ment facilities and the subsequent discharge of improperly treated sewage.
Bacteria, viruses, protozoa, and fungi are all potential waterborne transmitters or
causative agents of diseases. The extent to which public health might be affected by
expanded population cannot be projected at this time (48). The common and well
documented precautionary sanitation measures and construction or expansion of
sewage treatment facilities would minimize risks of microbial contamination of
waterways and subsequent potential public health hazards.
Oil and Grease
The possibilities for oil losses exist wherever oil is produced, processed, or
transported. A mature 1-million-bbl/day industry is estimated to require about 280
km (150 mi) of new pipeline to transport shale oil to major existing pipelines (12).
Predicted loss through spillage resulting from pipeline transport ranges from 1 to
100 bbl/year (12). The potential for much larger volume spills exists, however.
79
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In the event that a large-volume spill reaches a waterway and the oil cannot be
contained or removed, very severe damage to the aquatic biota and waterfowl
would result. Smaller volume spills such as those resulting from smaller pipeline
leaks could cause local damage to the biota, and if undetected for a long period of
time, the damage could be substantial.
Oil and grease in public water supplies can also cause objectionable taste, odor,
and appearance problems, and it can be hazardous to human health (33). To avoid
such problems, the NAS recommends that public water supply sources be essen-
tially free from oil and grease.
Hydrographic Modification
Hydrographic modification refers to procedures that change the movement,
flow, or circulation of any navigable waters or groundwaters.
Anticipated disturbances can be categorized by the manner in which they alter
water systems as follows: (1) creation of new impoundments, (2) drainage of ex-
isting impoundments, (3) diversion of natural drainage, (4) flow depletions, and (5)
disturbances to streambeds.
Historically, mining operations have been equated with landscape destruction
and water quality degradation. Typically, mining operations involve the movement
and relocation of large volumes of extracted material, resulting in drastic changes
in the topography and drainage characteristics of exploited areas. The oil shale in-
dustry will be similar to most other extractive mining and processing industries in
that large expanses of the landscape are disturbed by the development and opera-
tion of a commercial industry, resulting in permanent alteration of the water
storage and drainage system.
Development of the oil shale industry will differ from that of most mining in-
dustries in that it occurs under rigid governmental controls and regulations in-
stituted to minimize environmental impacts. However, in spite of strict adherence
to environmental guidelines, deleterious consequences unavoidably and inevitably
result. Many disturbances are localized and temporary and ultimately reparable
and do not permanently alter the regional hydrological regimes.
Other disturbances which potentially alter the water budget of entire river
systems could, however, seal the fate of the industry during the early developmen-
tal stages.
Activities such as road building, pipeline installation, shale disposal, mine
dewatering, etc. could permanently alter the hydraulics of streams in the area.
Groundwater withdrawals probably have the greatest impact, as continuous pump-
ing over a period of years could dry up a number of springs in the Piceance Basin
and eliminate much of the seepage to surface waters. Mine dewatering at the rate of
0.85 m'/s (30 ftVs) for a 30-year period in the C-a tract would lower the entire
water table within a 13.5 km (8-mile) radius of the site (12). Estimates show that as
many as 37 springs within this area may experience adverse effects, ranging from
reduction of flow to complete.cessation of flow (28). Reduction in total flows from
springs will ultimately reduce the amount of water reaching Yellow Creek. If excess
groundwater of suitable quality is available to replenish flows, changes in stream
hydraulics will be minimal. In the event that high quality groundwater is not
available to replenish surface flow, however, groundwater withdrawal could have a
substantial impact on the hydrological regimes of the area.
pH
The pH of water receiving industrial wastes and mine drainage may be drastically
altered by the addition of acids or alkalies. Such additions, particularly in poorly
buffered systems, not only result in acidic or alkaline conditions, but may increase
the toxicity of various components in the water (33). In well buffered systems, the
addition of small quantities of acids has little effect on the pH of the system. Since
80
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the Colorado River system waters contain sufficient CO2 to maintain equilibrium in
the bicarbonate system, it is doubtful that oil shale developmental activities will
substantially alter the buffering capacity of the system unless considerable quan-
tities of acids are discharged to waterways. Significant changes in pH or alkalinity
(bicarbonate) levels would serve as an immediate alarm that the buffering system
was disturbed and the equilibrium upset, thereby signaling the need for intensive
investigation to determine the cause of the disturbance.
Nutrients
The term "nutrient" can. legitimately be applied to any element, vitamin, hor-
mone or other substance that is utilized metabolically for growth or maintenance
by living organisms. From the standpoint of water quality, the nutrients of major
concern are nitrogen and phosphorus, owing to their contributions to the
eutrophication problems. It is these macronutrients that are addressed in this sec-
tion.
Both nitrogen and phosphorus enter surface waters by natural and man-induced
processes. Nitrogen enters waters naturally through fixation from the atmosphere
and through geologic and biogenic processes. Leaching of phosphorus from
calcium-phosphate rocks and soils and importation of allochthonous organic
materials are among the most important natural sources of phosphorus in waters.
Potential sources of nitrogen and phosphorus loading to surface waters as a
result of the development of an oil shale industry include municipal wastes,
groundwater discharge, stack emissions, runoff from raw and spent shales, and
commercial fertilizers.
The primary effect of urban growth on water quality would result from increased
nutrient loading via domestic sewage. An influx of people to the oil shale area will
place an added burden on existing sewage treatment plants, requiring expansion of
existing plants or construction of new facilities if the State's water quality stan-
dards are to be met. Increasing the capacity of municipal treatment plants should
partially alleviate the problems of additional nutrient release to surface waters as a
result of population growth, but additional loading over the present level is to be
expected. Municipal wastes receiving secondary treatment are very high in plant
available nutrients; consequently, the increased volume of treated wastes will result
in increased nutrient loading to waterways.
Groundwaters in the oil shale area are rich in nitrogen, with concentrations of
nitrates as high as 55 mg/1 (4.59xlO"4lbs/gal) reported from a spring in the Piceance
Basin (51). Data available on phosphorus concentrations in groundwater indicate
levels are not unacceptably high. Release of groundwater to surface waters,
regardless of the mechanism, represents a potential source of nitrogen loading but
probably does not represent a significant source of phosphorus.
Stack emissions from industrial operations are a potential source of nitrogen en-
try to waterways via atmospheric rainout. Nitrogen oxides will be emitted from
retorting operations and power generation, but the quantity of nitrogen that will
reach waterways via this route is unknown.
Nutrients in various forms as well as the excessive productivity they induce in
aquatic systems can interfere with beneficial water uses. The Environmental Pro-
tection Agency has no numerical water quality nutrient criteria for purposes of
limiting productivity of aquatic life. It is necessary to know the productivity
responses of various water types to ambient nutrient concentrations of loading
rates. Such relationships are presently being developed and tested at the EPA En-
vironmental Monitoring and Support Laboratory in Las Vegas, utilizing data ob-
tained from lakes sampled in the National Eutrophication Survey. This study may
provide a basis for the development of numerical criteria.
The NAS has recommended criteria for particular nutrient forms for beneficial
water uses (33). Included are criteria for waters used for industrial purposes, public
81
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water supplies, and livestock watering. In addition, criteria were established for the
protection of aquatic life from toxic ammonia.
Available water quality data suggest that Colorado River waters are acceptable
for most beneficial uses as regards nutrient levels. Additional nutrient loading in
the Colorado River system resulting from an oil shale industry and associated ur-
ban development would undoubtedly adversely affect localized reaches of streams,
but the cumulative impact on the Colorado River system cannot be predicted with
certainty. The rate of loading will depend in part on the distribution and the density
of the human population, as well as the degree of treatment that the wastes receive.
Temperature
Temperature differences between the upper and lower reaches of the Colorado
River system are pronounced during all seasons, primarily because of climatic,
geographic, and topographic factors. Natural temperature regimes of the river
system are disrupted by large reservoirs such as Flaming Gorge Reservoir on the
Green River and Lakes Powell and Mead on the Colorado River. The effects of the
reservoirs are to lower summer temperatures and, in some .cases to increase winter
temperatures for considerable distances downstream from the discharge.
Thermal springs, wastes discharges, and irrigation return flows may increase
temperatures of receiving waters locally, but heat added from such sources is usual-
ly quickly dissipated.
As the oil shale industry matures, stream temperatures may be altered somewhat
by municipal and industrial waste discharges, consumptive uses of surface waters,
lowering of the groundwater table, landscape modifications, and construction of
new reservoirs. A potential source of temperature increases is the discharge of
heated water (used in cooling processes) from power generating plants, although
none of the major developers has indicated any intention of discharging directly to
surface waters.
Considering the vastness of the Colorado River system and the inherently wide
natural variability in temperatures, thermal effects resulting from oil shale develop-
ment are expected to be of little significance in terms of the natural temperature
regime of the river system (12).
Temperature is not a critical factor for water used for industrial, agricultural, or
public water supply purposes, but aquatic biota could be adversely affected by
localized thermal effects since aquatic invertebrates and fish are very sensitive to
temperature changes. Temperature extremes and variations, (and particularly sud-
den changes in temperature) affect all components of the aquatic ecosystem. Not
only are the biota affected directly, but their susceptibility to disease and toxic
compounds is also influenced. Temperature extremes and changes also affect
solubility of oxygen and other gases, decomposition rates of organic materials, and
the community structure and stability of aquatic ecosystems.
Dissolved Oxygen
Since waters of the Colorado River system differ dramatically in the types of
fisheries they support, seasonal temperature maxima, and major uses, it would be
beyond the scope of this report to review ambient dissolved oxygen levels in terms
of EPA water quality criteria. Anaerobic conditions have been reported in the
Green River (USGS data through STORET), and minimum values below the 4.0
mg/1 (3.34x10"' Ibs/gal) recommended minimum have been recorded at two of the
White River stations near the leased tracts (USGS data through water data storage
and retrieval system [WATSTORE]). Therefore, it is obvious that stress conditions
for a balanced fishery presently exist at times in the lower reaches of both streams.
Further depression of oxygen levels could be induced by oil shale developmental ac-
tivities and related industrial and urban development, thereby further jeopardizing
the aquatic biota in these areas.
82
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Any introduction of oxidizable materials, whether organic or inorganic, creates
an additional oxygen demand through increased biological or chemical activity, or
both. The primary potential sources of such materials would undoubtedly be
municipal wastewater discharges, but industrial discharges and diffuse sources in-
cluding groundwater seepage also constitute potential threats. Increased oxygen
consumption through respiration and decomposition of aquatic biota may follow a
general enrichment of localized stream reaches resulting from increased nutrient
impact.
Sediments
Erosion, transport, and deposition of particulate matter are natural geologic
sedimentation processes that have been in continuous operation for millions of
years. Much of the oil shale area is highly susceptible to both wind- and water-
induced natural sedimentation processes, owing to the semiarid climatic condition
and the rugged topography characterizing much of the area. The rather scant
vegetation affords little protection against solids loss in an area that receives much
of its precipitation as snowfall and torrential thunderstorms and is frequently ex-
posed to high velocity, turbulent winds.
Development of an oil shale industry and associated activities will exacerbate
sedimentation problems by disturbing large expanses of the landscape and thereby
increasing the susceptibility of the area to erosion. Three basic processes are known
to be the most significant in affecting erosion: (1) the scouring and transport of
sediment by intermittent and ephemeral streams, (2) slope erosion (sheet erosion,
channel erosion, and gullying of slopes), and (3) downslope mass movement of
consolidated materials (52). However, the potential contribution of each process to
the total sediment load of perennial streams in the area has not been quantified.
These problems will have to be solved, at least in part, before sedimentation
sources can be identified and the relative contribution of each to the stream sedi-
ment loads determined.
The composition and concentration of suspended sediments in surface waters are
important because of their effects on light penetration, temperature, solubility
products, and aquatic life. Sediments in industrial waters also erode power turbines
and pumping equipment.
Suspended sediment levels have been measured by the USGS at several sites
throughout the Colorado River Basin since the early 1930's. Suspended sediment
data for the 1964-65 and 1968-69 water years were examined for three stations on
the Colorado River and on the Green River. Based on these data, maximum daily
values exceeded the least restrictive NAS criteria for the protection of aquatic life
(400 mg/1 or 3.34xlO"3 Ibs/gal) and criteria for many industrial uses (1000 mg/1 or
8.34xlO"3 Ibs/gal) during nearly every month (33).
A 1-million-bbl/day industry is estimated to affect an aggregate area of approx-
imately 32,376 ha (80,000 acres) over a 30-year period, of which 20,235 ha (50,000
acres) would be required for actual production (disposal, etc.), while the remainder
would be required for utility corridors, roads, and urban expansion (12). Ac-
celerated sedimentation would necessarily result from such industrial disturbances
to the landscape as removal and deposition of overburden from open pit mining,
the construction of roads and pipelines, and the disposal of spent shales in high
canyons, etc. The questions that emerge, however, are: To what degree will erosion
and sedimentation be increased? What material will be most susceptible to move-
ment? And what will be the impact on waterways? At present, these questions can-
not be answered given the current state of knowledge of the sedimentation poten-
tial and processes in the area.
83
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SOLID WASTE IMPACTS
Inventory of Solid Wastes
One of the major environmental problems to be solved before development of a
commercial oil shale industry is that of providing environmentally safe handling
and disposal procedures for the vast amounts of solid waste that would be pro-
duced. Wastes would include raw mined oil shale, spent oil shale, overburden in the
case of stripping, raw and spent shale fines from dust control devices and other
process wastes such as spent catalysts, water treatment sludges, oil sludges and
shale coke. Disposal would require dealing with handling, stabilization, and
revegetation operations. The potential environmental impact on air and water
quality that may be caused by fugitive dusts and leachates from these solid wastes
must be addressed. Further, locating suitable disposal sites for the large quantity of
solid waste may be difficult in some areas.
A feel for the magnitude of the solid waste handling and disposal problem can be
obtained from Table 3-23, which provides an estimate of spent shale quantities and
size of disposal areas for several levels of shale oil production. As shown in the
table, a commercial oil shale industry producing 159,000 mVday (5,615,033 ft3/
day) of shale oil (1 million bbl/day) would process 490 to 540 million tonnes (540 to
600 million tons) of raw oil shale each year, requiring disposal of 250 to 300 million
m3 (9 to 10 billion ft3) of compacted spent shale each year. If continued at this level
for 30 years, the spent shale would cover an area of 170 to 190 km2 (65-75 mi2) to a
depth of 45.7 m (150 ft). True or modified in situ retorting could substantially
reduce the quantity of spent shale for surface disposal but would increase the total
quantity of spent shale (surface and underground) produced for a given level of oil
production since the recovery rate is lower, and leaner shales would be included in
the retorting. The huge quantity of spent shale produced could create a serious
potential for air pollution from fugitive dusts as well as for surface and ground-
water pollution from spent shale leachates unless appropriate control technology
were developed and applied.
Also, the huge quantity of raw shale that must be mined (Table 3-23) would
create a risk of fugitive dust from the mining, crushing, and transport operations
(Reference, "Atmospheric Impacts") as well as a potential risk of surface water
and groundwater impacts from raw shale storage piles and disposal of collected
fugitive dusts. Other process solid wastes such as spent catalysts from
hydrotreating, sulfur recovery and arsenic removal, water treatment sludges, oil
sludges, and shale coke are produced in retorting and upgrading operations. These
wastes, though far smaller in quantity, may contain toxic substances that could af-
fect surface water and groundwater quality. Estimates of quantities of these wastes
have been made by some developers.
Overburden removal, storage, disposal, and revegetation operations would reach
large dimensions only for a surface mining operation. The quantity of overburden
handled would vary greatly, depending on location. However, a feel for the
magnitude of the effort can be obtained from the DDP submitted for Federal lease
Tract C-a (53). (This DDP was later revised to provide for modified in situ develop-
ment rather than open pit mining.) The mine production schedule in the original
DDP estimated that production of sub ore, overburden, and waste would be ap-
proximately equal to the quantity of ore to be mined and returned (53). En-
vironmental impacts associated with such overburden removal and restoration in-
clude impacts on the land surface, resulting impacts on vegetation and wildlife, air
pollution from fugitive dusts, disruption of the water table, and possible impacts
on surface and groundwater quality as a result of leachates from overburden
storage and disposal areas.
84
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TABLE 3-23. ESTIMATED SPENT SHALE QUANTITIES AND DISPOSAL AREAS REQUIRED
Production level
Item
Raw shale processed:6
106 tons/year
106 tonnes/year
Compacted spent shale:
109 ft3/yearc
106m3/year
106tonnes/yeard
Required annual
disposal area:6
Acres
Hectares
Disposal area required
for 30 years:6
mi2
km2
50,000
7,949
26.9
24.4
0.45
12.7
20.4
69.8
28.2
3.27
8.47
bbl/day
mVday
-29.9
-27.2
- 0.52
- 14.7
-23.6
-79.6
-32.2
- 3.73
- 9.66
50,000
7,949
26.9
24.4
0.45
12.7
20.4
27.9
11.3
1.31
3.39
bbl/day
m3daya
-29.
-27.
- 0.
- 14.
-23,
-31.
- 12.
- 1.
- 3.
9
2
52
7
,6
,8
,9
49
86
100,000 bbl/day
15,898 mVday
53.8
48.9
0.90
25.5
40.8
-59.8
-54.4
- 1.04
-29.4
-47.2
138-159
55.8
6.47
16.7
-64.3
- 7.45
- 19.3
250,000 bbl/day
39,745 mVday
134.5 -
122.3 -
2.25-
63.7 -
149.5
135.9
2.60
73.6
102-118
344-398
139-161
16.1 -
41.7 -
18.7
48.4
1,000,000 bbl/day
158,980 m3/day
538-598
489-544
9.00 - 10
255-294
408-472
.4
1378-1592
558-644
64.6 -74.
167-193
6
a Assumes 60 percent disposal in underground mine workings.
b Source: Reference 53, Section 1. Based on 103 1/tonne (30 gal/ton) shale, yield 86 to 95 percent by volume.
c Source: Reference 53, Section 1. Based on 1,441 to 1,602 kg/m3 ISO to 100 Ib/ft3).
d Assumes 1,602 kg/ms 1100 Ib/ft3!.
e Assumes disposal pile 45.7 m (150 ft) deep.
-------
Raw Shale Handling and Disposal
A commercial oil shale operation must mine, temporarily store, or dispose of
huge quantities of raw mined oil shale. A modified in situ operation would bring
substantially less mined shale to the surface but would still produce large volumes.
As indicated in Table 3-23, a surface retorting oil shale industry producing 15,900
mVday (100,000 bbl/day) would mine approximately 49 to 54 million tonnes (54 to
60 million tons) of oil shale per year. The mining, crushing, transporting, transfer
and temporary storage of this raw shale would impact both air and water quality.
Temporary or permanent surface storage of raw mined oil shale presents an
unknown potential for surface water and groundwater pollution. The greatest con-
cern is that precipitation and possibly water sprays applied to control dust may pro-
duce surface runoff or leachates with trace elements and organic compounds that
could affect surface water or groundwater quality. The potential impact from sur-
face storage of raw mined oil shale must be addressed before a commercial oil shale
industry is developed. One position states that raw shale fines disposed of on pro-
cess shale piles or surface storage of raw mined oil shale will present no more risk of
environmental impact than shale eroding along natural outcrops. This opinion
needs to be evaluated by field tests. Leachates of raw oil shale are discussed in more
depth later in this section under Leaching of Solid Wastes.
As discussed earlier in this section, fugitive dusts from the substantial quantities
of raw shale dust will be produced by mining, crushing, and transfer operations
may be expected to affect air quality unless carefully controlled. Raw shale fines
collected during dust control operations must be carefully disposed of to prevent
erosion by wind and water and to assure that they do not generate leachates that af-
fect surface water or groundwater quality. Disposal of these raw shale fines along
with retorted shale waste may be desirable if proper precautions are taken to pre-
vent fine particles from contaminating air or water resources and if leachates are
controlled to prevent impacts on surface water and groundwater quality.
Underground disposal in conventional mines or modified in situ retorts would
likewise present some risk of affecting groundwater and perhaps surface water
quality.
Spent Shale Handling and Disposal
Spent oil shale weighs about 80 to 85 percent the weight of raw mined oil shale.
Even with maximum compaction, it occupies a volume approximately 12 percent
greater than the volume of the original in-place shale (52). As discussed under In-
ventory of Solid Wastes, spent shale handling and disposal presents one of the ma-
jor environmental problems to be solved before proceeding with commercial oil
shale development. As shown in Table 3-23, a commercial oil shale industry pro-
ducing 159,000 mVday (5,615,033 ftVday) shale oil by surface retorting would pro-
duce 250 to 300 million m3 (9 to 10 billion ft3) of compacted spent shale each year.
In situ or modified in situ retorting would leave the spent shale underground, but
the volume of spent shale would likely be even greater, and it would be of a dif-
ferent chemical nature. The environmentally safe handling and permanent disposal
of such a huge quantity of solid waste poses a challenge for both industry and
government.
Surface retorting processes and the chemical nature of the spent shale produced
from each are discussed in Section 7. Table 3-24 summarizes the major components
of spent shale from the leading retorting processes, and Table 3-25 summarizes the
trace elements in selected spent shales. Volatile and semivolatile organic com-
pounds reported in oil shale wastes were previously listed in Table 3-22. Potential
environmental impacts and problems which should be considered in surface
disposal of spent shale include:
86
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Location of disposal sites large enough to accommodate the large amounts of
spent shale and yet permit the disposal site to blend into the natural topography.
The generation of fugitive dust until the disposal site has been revegetated. Table
3-19 included an analysis of dust from the Paraho direct mode process. In a com-
mercial process, spent shale dust is likely to be incorporated into the spent shale
disposal pile, requiring careful control to prevent a significant impact on air
quality.
Residual heat of freshly retorted shale. Unless cooled properly the temperature
of retorted shale could be a serious impediment to revegetation.
Deterioration of surface water and possibly groundwater quality by runoff from
the disposal piles. Table 3-26 presents surface runoff water quality for several
types of spent shales. Runoff is considered to pose a salinity hazard for irrigation
use. In addition, the concentrations of some metals and ions are substantially
higher in runoff from spent shale than in runoff from native soils.
Deterioration of groundwater and possibly surface water quality by leachates
permeating through the disposal pile. This problem is discussed at greater length
in this section under Leaching of Solid Wastes.
Difficulty in revegetating some spent shale piles without soil cover, since some
spent shales are highly alkaline and contain few nutrients.
Instability of spent shale piles, resulting from improper pile design, which may
produce erosion, soil creep, and possibly land slides. Fine-textured spent shales
may be more prone to slippage. Some proposed disposal sites are located in
gulches susceptible to flash flooding.
Change in type of vegetative cover. Existing soil and vegetation would be re-
moved and replaced by a different mix of vegetation.
Possible reduced ability of the land to support wildlife or domestic stock,
depending on the type of vegetation planted, success in revegetating spent shale,
and the presence or absence of significantly greater quantities of bioac-
cumulative toxic elements and organics concentrated in plants grown on spent
shale as compared to plants grown on native soil.
Because of the very large areas required for surface disposal of spent oil shale
(Table 3-23), the quality of surface runoff water is of great concern. The following
observations can be made from the data in Table 3-26, which presents analyses of
runoff water quality for spent oil shale test plots:
At least initially, runoff from spent shale is of lower quality than runoff from
native soil.
Storm runoff from spent shale is generally of lower quality than snowmelt
runoff. This relationship also applies to native soil test plots. Because snowmelt
runoff is usually much greater in quantity, it is very possible that its apparent
better quality is due to dilution.
Storm runoff may present a high salinity hazard for irrigation.
Quantity of runoff and sediment eroded was much higher for the fine-textured
TOSCO II shale plots than for the course-textured USBM or native soil plots.
Union B shale also exhibited higher erosion rates than native soil.
Quantity of snowmelt runoff was greater for the high elevation (Piceance Basin)
sites than for the low ones.
Use of underground disposal of spent oil shales in conventional underground oil
shale mines could avoid many of the potential environmental impacts of surface
disposal. However, since the volume of spent shale exceeds the in-place volume of
the original mined shale, not all spent shale can be disposed of underground.
Underground disposal could possibly increase the potential for groundwater con-
tamination unless great care is taken to prevent contact with groundwater.
87
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TABLE 3-24. CHARACTERISTICS OF SPENT OIL SHALES FROM THE LEADING RETORTING PROCESSES
Retorting process
Shale
characteristic
Component (wt. %)
Si02
CaO
MgO
AI203
Fe203
Na20
K20
S03
P206
Mineral C02
Organic C
Inorganic C
Texture
PH
Paraho
Indirect3
23.1
15.3
6.5
8.0
2.7
2.3
2.4
0.7d
—
18.1d
1.84
4.95
silty
gravel
10.9
Paraho
direct3
28.0
18.3
6.5
6.9
2.7
2.6
6.6
0.2d
—
13.3d
2.18
4.15
silty
gravel
11.1
TOSCO llb
33.0
15.8
5.31
6.80
2.52
8.68
3.28
—
—
5.71
4.49
5.71
silt
7.5-9.0
Union Ac
35.3
27.2
9
8.5
7.3
5.5
2.8
0.1
2.2
1.6
0.5
—
graded
gravel to
silty
gravel
12.5-13.0
Union Bc
31.5
19.6
5.7
6.9
2.8
2.2
1.6
1.9
0.4
22.9
4.3
—
silty
gravel
8.7
Union SGR°
39.2
27.3
8.2
8.9
3.8
3.7
2.7
1.4
0.5
3.1
0.3
—
silty
gravel
12.5
a Source: Reference 55.
b Source: Reference 56.
c Source: Reference 57.
d Paraho data are for SO« and CO3.
-------
TABLE 3-25. MEAN LEVELS OF TRACE ELEMENTS IN PROCESSED OIL SHALE" b
Retorted shale
Element
Ash,
Mahogany
Paraho
Zone
Utah Colorado
Be
Hg
Cd
Sb
Se
Mo
Co
Ni
Pb
As
Cr
Cu
Zr
B
Zn
V
Mn
F
—
—
—
—
—
—
—
70
100
—
170
—
33
136
35
78
420
- 1
35.0
0.1
0.14
0.39
0.08
4.9
39.0
11.0
10.0
7.2
49.0
15.0
9.3
140.0
13.0
29.0
34.0
,700.0
Direct
mode
2.0
0.07
—
0.7
0.3
12.0
13.0
38.0
18.0
21.0
136.0
44.0
43.0
52.0
16.0
116.0
600.0
1,000.0
Indirect
mode
0.7
0.03
—
0.8
0.2
10.0
16.0
14.0
11.0
18.0
66.0
26.0
62.0
18.0
21.0
88.0
272.0
450.0
Fischer
assay
—
0.38
2.1
0.3
0.4
—
—
—
—
4.1
—
—
—
87.0
—
—
—
380.0
TOSCO II
—
—
—
—
4.9
38.0
—
38.0
42.0
105.0
—
62.0
—
—
108.0
—
—
—
Gas combustion
—
0.002
—
2.7
2.9
—
17.0
56.0
80.0
73.0
42.0
—
106.0
—
100.0
—
—
—
—
0.04
0.56
—
—
7.0
8.0
19.0
34.0
58.0
244.0
_
_
—
—
—
270.0
-
3 Source: Reference 5.
k Calculated as ppm of raw shale. Where ash equivalent of raw shale is not known, a value of 0.8 is assumed for calculations in this table.
-------
TABLE 3-26. SURFACE RUNOFF WATER QUALITY FOR SPENT OIL SHALE TEST PLOTS
Test
plot3
Soil Control
Soil Control
Soil Control
Soil Control
Soil Control
TOSCO II
TOSCO II
TOSCO II
TOSCO II
TOSCO II
USBM
USBM
USBM
USBM
USBM
Paraho
Union SGR
Union B
Union B
Elevation
m Event
1,700
1,700
1,700
2,200
2,200
1,700
1,700
1,700
2,200
2,200
1,700
1,700
1,700
2,200
2,200
1,700
1,770
1,770
1,770
Storm"
Storm0
Snowmeltd
Storm6
Snowmelt
Stormb
Stormc
Snowmeltd
Storm8
Snowmelt'
Stormb
Storm0
Snowmeltd
Storm6
Snowmelt'
Snowmelt9
h
Snowmelt'
Snowmelt'
Sediment
(Kg/ha)
52.8
172
11.8
10.1
16.9
281
379
137
136.1
29.8
63.4
73.3
10.2
7.1
20.3
_
_
439P
192P
Runoff
(nWha)
0.78
5.51
10.5
0.68
83.3 +
10.1
13.2
107 +
10.2
120 +
0.55
0.92
28.4 +
1.04
117 +
16
—
903.2
760.1
pH
7.7
7.9
7.3
7.6
7.2
7.1
8.2
7.0
7.4
7.1
7.6
8.3
7.3
7.7
7.1
7.3
7.8
7.6
6.6
EC
(^mhos/cm)
1,106
1,000
255
730
185
1,294
2,900
635
2,416
772
1,563
2,300
299
1,676
457
280
460
767
227
Component (ppm)
Na
70
13.8
4.9
22
5.5
75.5
122.7
5.5
88.2
10.4
95
103.5
5.2
96.4
14.3
14
_
3.5
3.15
Ca
75
135.3
21.0
67
17.1
118.8
261.9
105.6
317.9
120.8
122.7
184.4
22.5
139.3
28.0
12
_
135
23.4
Mg
16
26.1
5.2
17
5.8
52.8
156.5
15
126.8
24.3
29.3
48.6
11.7
59.8
19.3
21
_
12.2
4.1
K
69
23.5
23.4
3
5.4
28.2
129
10
11
8.4
65.7
164.2
22.5
17K4
13.2
7
_
4.3
5.2
C03
0
0
0
0
0
0
240
0
0
0
0
0
0
0
0
0
—
0
0
HC03
451
241
88.5
238
91.1
145.8
760.6
57.2
96.7
73.1
459.3
1134.8
109.8
215.7
111.7
99
_
56.5
63.81
NO3
4
3.1
5.6
1.0
1.2
3
10.7
1.0
0.37
1.01
4.3
2.5
1.4
3.2
1.51
4
< .01
.23
SO, Cl
115 40
374.6 12.4
25.8 9.8
77 12
8.2 4.6
611.5 26.2
824.5 164.3
298.9 4.0
1352 11.7
354.7 4.0
188.7 138
76.8 159.6
49.8 22.2
588 30
93.8 4.6
64 17
311 8.7
36.7 5
SAR
0.8
0.37
0.23
0.6
0.30
0.78
1.3
0.15
1.03
0.21
1.97
1.75
0.21
1.93
0.49
0.6
0.38
.07
.15
a 25 percent slopes, except Paraho, which has 2 percent slope. Averaged values for several plots.
b Reference 59, Appendix Tables 47, 48; 19.05 mm precipitation in 30 minutes, 8-14-74.
c Reference 59, Appendix Tables 51 and 52; 10.6 mm precipitation in 30 minutes, 7-16-75.
d Reference 59, Appendix Tables 49, 50, 53, 54; averaged values, 1975 and 1976.
e Reference 59, Appendix Tables 86, 87; 12.7 mm precipitation, 8-14-74.
f Reference 59. Appendix Tables 88-95; averaged values, 1975-1976.
9 1979 Data, personal communication with Ms. Kathleen Kilkelly, Colorado State University.
n Reference 57, average values of snowmelt and storm runoff.
' Reference 60, Appendix Table 7, 3-18-76.
J Reference 60, Appendix Table 10, 4-5-78.
-------
TABLE 3-26. (continued)
Test
plot3
Union B
Union B
Union B
Union B
Soil Control
Soil Control
Soil Control
Soil Control
Soil Control
East Fork of
Elevation
m Event
1,770
1,770
1,770
1,770
1,770
1,770
1,770
1,770
1,770
Parachute Creek
Union SGR
Union SGR
Union SGR
Union SGR
Union SGR
Soil Control
Soil Control
Soil Control
Soil Control
Soil Control
2,300
2,300
2,300
2,300
2,300
2,300
2,300
2,300
2,300
2,300
Stormk
Snowmelt'
Snowmeltm
Storm"
Snowmelt1
Snowmelt'
Snowmelt1
Snowmeltm
Storm"
Streamr
Snowmelt8
Snowmelt5
Snowmelt8
Storm8
Storm3
Snowmelt5
Snowmelt5
Snowmelt8
Storm5
Storm5
Sediment
(Kg/ha)
253P
319q
533q
935q
27"
37P
175q
175q
233q
_
29
35
10
33
24
—
56
50
127
226
Runoff
(rrvVha)
11.3
710.6
599.7
35.8
_
225.2
459.2
393.6
11.5
_
164.5
164.5
119.8
4.2
5.4
259.1
208.5
174.8
20.2
40.1
pH
7.1
6.9
6.9
7.1
7.9
6.5
7.4
6.9
7.3
8.2
7.8
6.8
8.0
7.2
7.0
7.2
6.1
7.8
7.1
7.0
EC
(fjmhos/cm)
1,280
1,493
323
735
310
110
274
189
630
1,400
290
530
230
260
215
106
134
230
148
215
Component (ppm)
Na
84.4
23.2
2.87
9.5
8.9
1.88
4.8
1.45
17.4
53
10.5
15.6
6.4
.21
4.8
4.4
9.4
16.4
0.2
17.7
Ca
134.0
130.1
42.93
142
27.4
8.50
19.7
21.7
25.7
56
15
38.7
19.3
1.79
16.4
13.3
12.9
22.2
1.16
14.4
Mg K
101.6 33.9
42.9 7.1
8.1 6.4
26.5 10.3
8.7 15.3
3.15 6.23
7.9 19.1
2.93 14.5
12.7 58
—
17.6 3.9
47.3 13.6
15 19
.87 3.3
6.21 6.0
1.4 1.2
3.2 11.2
4.3 5.2
0 3.5
3.4 8.4
C03
0
0
0
0
0
0
0
0
0
1.8
0
0
3
0
0
0
0
4.8
0
0
HC03
168
65.5
89
142
134
49.37
113.1
95.1
331
329
77.5
96.1
73.4
109
98.4
44.8
66.4
116.4
56.5
89.2
N03
.59
3.65
1.6
.93
< .01
.80
< .01
.65
.41
4.2
13.1
.78
3.2
1.3
2.9
.99
1.1
1.9
.80
SO4
881
843
82.3
349
30.7
2.5
17.5
2.3
43.7
90
52.5
242
69.2
25.6
10.9
8.7
10
17.8
16.1
7.1
Cl
19.3
10
7
11.3
12.5
6.5
11.3
10
24.3
9.3
12.5
10
18.2
7.5
5.0
2.3
11.2
3.2
7.5
4.9
SAR
1.35
.40
.11
.19
.37
.14
.23
.07
.71
.41
.44
0.30
.18
.87
.26
.62
.76
.26
1.06
k Reference 60, Appendix Table 9, 8-30-77.
1 Reference 60, Appendix Table 26, 3-18-76, 50% slope
m Reference 60, Appendix Table 28. 4-5-78, 50% slope.
n Reference 60, Appendix Table 27, 8-30-77, 50% slope.
P Reference 60, Table 8.
1 Reference 60, Table 15.
r Average of data taken during Union's baseline sampling, 9-24-74 to 9-13-77, Personal communication from Allen C. Randle, Union Oil Co.
s Reference 61, Table 15.
-------
Underground disposal may also affect future recovery of the remaining oil shale
resource. Underground disposal of at least part of the produced spent shale has
been proposed by some developers, but more study on possible environmental im-
pacts needs to be done.
In situ or modified in situ retorting of oil shale leaves all or most of the spent
shale underground, avoiding some problems of surface disposal. However, the
underground retorts invariably intersect aquifers or zones of groundwater move-
ment, which creates a possibility for serious groundwater impact. The retorting
temperatures of these retorts are reportedly much higher (approximately 1,000°C
or 1,832 °F) than surface retorts. These higher temperatures permit recrystallization
of the minerals present, significantly altering their chemical nature. Research to
date has been insufficient to establish whether this recrystallization reduces the
potential for groundwater pollution. There is some concern that high retorting
temperatures may increase the risk of producing carcinogenic materials. Because of
the great technical difficulty in treating a groundwater problem, should one
develop from true or modified in situ retorting, this aspect of shale handling
deserves thorough investigation. It has been proposed by some that surface-
retorted shale could be injected as a slurry into burned-out modified in situ retorts,
where it would undergo a cementing action to block groundwater flow through the
retorts (61,62). This technology is yet to be proven as applicable for modified in
situ retorts, and the injection of surface-retorted shale may itself pose a risk of
groundwater pollution.
Other Solid Process Wastes
In addition to the spent shale, oil sludges, shale coke, and spent catalysts are pro-
cess solid wastes that also contain numerous pollutants that must be controlled to
protect the environment. The oil shale processing techniques used in a commercial
oil shale industry would determine the quantities and chemical-physical
characteristics of the spent materials to be disposed of.
Onrsite upgrading of shale oil crude planned for the first generation of commer-
cial operations consists of: (1) filtration for solids removal, (2) distillation and cok-
ing, and/or (3) catalytic hydrogenation of whole shale oil or its fractions. Filtration
of shale oil generally removes insoluble inorganic materials and the trace element
components. These heavy metals contained in the sludge extracted from the shale
crude should be contained so as to preclude their transport into surface and
groundwater streams.
In the distillation of shale oil, most minor elements tend to concentrate in the
higher boiling fractions and in shale coke. In a commercial operation, elements
such as Ni, V, and Fe would tend to concentrate along with the shale fines in the
shale coke. The shale coke could be disposed of with the other solid wastes (i.e.,
with the spent shale).
The hydrotreating of shale oil for sulfur and nitrogen removal is typically per-
formed over nickel or cobalt-molybdate catalyst supported on alumina. The
relatively high arsenic levels in shale oils have necessitated treatment steps for
arsenic removal to maintain bulk catalytic activity during hydrotreating operations.
The steps of treatment generally employ a selective absorbent for arsenic and other
trace elements, or a portion of the catalyst bed itself acts as the removal media. The
contaminated media or catalyst bed should be periodically removed for ultimate
solid waste disposal, or it will be reprocessed for material resource conservation
and recovery.
Considering the nickel or cobalt-molybdate, a value of 7 percent by weight of
arsenic in the catalyst would be the approximate cutoff point for replacement of
the catalyst. At greater than 7 percent by weight, arsenic begins to appear in the
hydrotreated product. The spent catalyst would also contain about 10 percent car-
bon, 8 percent sulfur, and small quantities of other shale-derived elements (Sb, Se,
92
-------
and transition metals). The chemical forms of arsenic in the spent catalyst are not
known, although As2S3 or elemental arsenic are likely candidates.
Spent catalysts would generally be stored with other solid wastes in a commercial
oil shale operation until sufficient quantities of such materials could justify ship-
ping to a processor. In recent years, prices for metals such as Ni, Co, and Mo have
increased to the point where reclamation firms can offer attractive terms to refiners
for spent catalysts. However, contaminants such as arsenic in spent catalysts from
shale operations may present technical, economic, or waste disposal problems for
reclaimers. Storage or direct disposal with other wastes may be the likely fate of
these materials, at least during the early stages of oil shale commercialization. The
quantities requiring disposal are very small relative to the quantities of retorted
shale. An option for disposal of the catalyst materials may be to place them in
suitable nondeteriorating containers for landfill disposal, as is a common practice
with spent petroleum catalysts. The alternative of mixing spent catalysts with
retorted shale as a disposal option should be fully researched. At this time, there is
little information to indicate the chemical stability or potential for mobility of
catalyst metals (Ni, Co, Mo) and trace element contaminants (As, Se, Hg) disposed
of in either concentrated or dispersed form with retorted shale. (An example for
As: at 14 percent total arsenic in guard catalyst, the water soluble As is 0.003 per-
cent - before "dilution" by mixing with spent shale in 1:33,000 ratio. Personal Cor-
respondence, ARCO Coal Company, August 29, 1979.)
Leaching of Solid Wastes—Edward Bates
As discussed earlier, a surface-retorting oil shale operation will produce spent
shale waste of greater volume than the original in-place oil shale. Even a modified
in situ operation will bring to the surface solid waste equal to approximately 25 per-
cent of the retort volume. In the interest of maximizing resource recovery and pro-
viding economic advantages as well, it is expected that raw shale brought to the sur-
face in modified in situ operations will be surface retorted. In addition, some
developers have also proposed disposing of other solid wastes within the spent
shale disposal area. Some or all of these wastes will be disposed of on the ground
surface in the form of disposal piles or various forms of valley fills. These wastes
will then be subject to leaching by water from several sources, including normal
precipitation, water applied to cool the spent shale, water applied for dust control,
water needed to achieve compaction of the spent shale pile, water applied to leach
the spent shale before revegetation, and irrigation water needed to establish
vegetative cover. In addition, spent shale piles have appealed to some as possible
disposal sites for wastewater not recycled in the process. The condition of large
quantities of solid waste exposed to water from varied sources may create a risk of
generating leachate that could affect surface and groundwater quality.
Many factors interact in determining how much leachate will be produced from a
given disposal site. Factors which would tend to increase the quantity of leachate
include:
Spent shale must be cooled before placement in the disposal site—Otherwise,
elevated temperatures will persist in the disposal pile for several months, in-
hibiting revegetation (63);
Spent shale may require leaching to lower its pH and move soluble salts to a suf-
ficient depth to prevent resalination of the surface, or revegetation may not be
successful (64). Indirectly retorted spent shale may require less or no leaching;
Spent shale may require irrigation to initially establish a satisfactory vegetative
growth; the use of a soil or other cover could substantially reduce or eliminate
the need for irrigation;
To maximize compaction and lower permeability, some water must be added to
the spent shale;
93
-------
Even after placing, compacting, and revegetating the shale, rainfall and
snowmelt will continue to contribute water that may leach through the spent
shale;
EPA studies show that it may not be possible to make all spent shale im-
permeable (63,65).
On the other hand factors which would tend to decrease the quantity of leachate
include:
The high evapotranspiration rates and low precipitation rates at some locations
will reduce infiltration;
Surface runoff will decrease the amount of water available for infiltration;
The moisture retention capacity of the spent oil shale will retain significant
amounts of infiltration water.
A discussion of surface water balance relationships including precipitation,
water holding capacity of soils, and evapotranspiration in the Piceance Basin is
presented by Wymore (66). Water requirements for stabilization of spent oil shale
are discussed in reports by Harbert, Berg, and McWhorter (63) and Wymore (67).
The extent of environmental impact to surface and groundwater from spent
shale leachates depends on the chemical nature and quantity of leachate produced
and the extent to which the leachate is contained and treated before its contact with
the water supply. Extensive studies on the nature of leachate produced from spent
shales of each retorting process are not available. Studies to date indicate that
leachate quality will vary with each specific retorting process and may vary for any
one process as specific retorting conditions vary. Table 3-27 provides a summary of
leachate analyses for several types of spent shale, including simulated in situ
retorts. Table 3-27 should not be used to compare leachates from one spent shale
type with those of another, since various methods were used to obtain the data
presented. This table does show that in general, spent shale leachate may be ex-
pected to contain organic carbon and such cations, anions, and trace metals as B,
Ba, Be, Ca, Cl, F, Fe, HCO3, K, Li, Mn, Mo, Mg, Na, Ni, Pb, Sn, SO,, Sr, V, and
Zn. The specific nature of potential organic compounds in spent shale leachate is
not well-defined at present. It must be emphasized that each particular spent shale
will likely produce a unique leachate that may include some or all of the above
pollutants, plus others specific to itself. The important point is that surface
disposal of spent shale may produce leachates that affect surface and groundwater
quality unless the leachate is collected and treated. Spent shale in true and modified
in situ retorts may likewise affect groundwater quality and surface water quality as
well through recharge to surface streams.
Table 3-28 presents data on spent shale leachates in an alternate form. Rather
than describing the water quality of leachate, this table describes the maximum
quantity of major leachate constituents that may result from the leaching of a given
quantity of spent oil shale. For example, from Table 3-23, a surface oil shale facil-
ity producing 15,900 m3 (100,000 bbl) of oil per day would have to dispose of ap-
proximately 45 million tonnes (49.5 million tons) of spent shale each year. If
retorted by the TOSCO II process, this spent shale has a potential for leaching ap-
proximately 51 tonnes (56 tons) of Ca. The data in Table 3-28 assume that adequate
water is available and that permeability does not seriously restrict leaching. Since
the oil shale areas of Colorado, Utah, and Wyoming are quite dry, and since spent
shale should be disposed of in a manner that minimizes permeability, the data of
Table 3-28 represent maximum potentials rather than actual quantities that would
likely be leached. However, the table clearly indicates the potential for en-
vironmental impact if spent shale disposal is not properly handled.
The question of permeability of spent shale deserves special attention. Great
variation in permeability values has been reported for various spent shales com-
pacted under different conditions. Table 3-29 indicates the variation in permeabil-
94
-------
TABLE 3-27. ANALYSIS OF SPENT SHALE LEACHATES"
Constituent
pH
EC ^mhos/cm
OC
1C
TDS
Ag
Al
As
B
Ba
Be
Ca
Cd
Cl
co;
Cr
Cu
F
Fe
HCOj
Hg
K
Li
Mn
Mo
Mg
Na
Soil
Control
7.7
5,690.0
64.8
40.2
—
0.001
0.05
0.02
1.14
0.07
< 0.005
166.4
—
428.0
—
0.01
0.02
1.31
< 0.01
—
—
0.02
—
0.05
0.44
190.3
712.0
Para ho
Ab
9.57
(ppm)
Bc
8.4
21,110.0 14,600
127.0
20.5
—
0.001
0.05
—
1.64
0.12
0.01
421.4
—
526.0
—
0.01
0.05
11.9
0.03
_
—
834.0
—
0.05
3.92
7.74
5,591.0
_
—
—
—
0.25
< 0.001
0.73
0.15
< 0.025
200.0
< 0.025
111
7.8
< 0.025
< 0.025
13.0
< 0.05
516
< 0.001
580
7.4
< 0.05
4.3
1,190.0
2,500.0
TOSCO I
Ad
8-9
10,000
402
_
42,000
—
—
—
_
_
_
_
_
—
—
_
16.6
—
—
—
77.2
—
—
—
—
—
10,700
I (ppm) USBMf
B" (ppm)
7.78
—
— —
_ _
- 970-1,091
_ —
_
0.05
4.6
— _
—
- 42
— —
13
— _
— _
— _
— —
16.0 -
38
— _
72
— —
_ —
3.0
3.5
- 225.0
Union Af
(ppm)
9.94
—
_
—
10,011
—
_
_
_
—
_
327
_
33
—
—
_
_
—
28
—
625
—
—
—
91
225
Union SGR9
(ppm)
9.7
7,170
_
_
—
—
0.41
_
—
_
11.2
_
24
695
_
—
_
_
1,716
—
358
—
—
—
7.5
1,110
Surface
retortsh
(mg/100g)
7.78-11.2
_
—
_
970-10,011
—
_
0.1
2-12
4
—
42-114
_
5-33
21
_
_
3.4-60
—
20-38
—
10-625
_
_
7-8
3.5-91
2,100
Simulated
in situ retorts^'
(mg/100g)
7-12.7
—
1.0-38
_
0-2,800-
—
0.095-2.8
_
0.075-0.14
—
3.6-210
_
5.5
30-215
0.002-1.8
_
1.2-4.2
0.0004-0.042
22-40
_
0.76-18
.020-0.42
trace
0.002-8.0
8.8-235
(continued)
-------
TABLE 3-27. (continued)
Constituent
Ni
NOj
Cll
Pb
Se
Si
Si02
Sn
SO;
Sr
V
Zn
Soil
Control
0.1
31.6
—
< 0.005
< 0.02
_
9.02
_
1,954.0
2.7
< 0.10
0.04
Para ho
Ab
0.01
0.09
—
0.01
0.03
—
8.31
—
12,354.0
10.4
0.24
0.15
(ppm) TOSCO II (ppm) USBMf
Bc Ad Be (ppm)
< 0.025 - - -
96.0 -
_ _ _ _
0.31 - - -
< 0.001 -
5.6 -
_ _ _ _
0.83 -
9,990.0 - - 600
5.4 - - -
_ _ _ _
0.05 -
Union Af Union SGR9
(ppm) (ppm)
12.4
— _
_ _
_
— —
— —
— _
6,230 1,012
_ _
— —
— —
Surface
retorts'1
(mg/100g)
5.1-5.6
—
_
0.005-0.006
—
—
_
600-6,210
_
_
—
Simulated
in situ retortsh
(mg/100g)
0.2-2.6
22-40
0.014-0.017
—
25-88
—
—
50-130
0.004-8.7
_
0.001-0.025
a Note: This table is not to be used for comparing leachates from different spent shales, since the methods of leaching and analysis varied.
b Reference 64, Tables 129, 131, and 133 (averaged values). Anvil Points, Colorado. Leached with Colorado River Water.
c Personal communication with Dr. David McWhorter, Colorado State University. Leached with snowmelt water, seven samples.
d Reference 69, Table 5-13 (averaged values).
e Reference 70, Page 1025, leached with distilled water, 12 days in pyrex.
f References 71 and 72.
9 Reference 61, averaged values, Table 32-36.
n Reference 73. Summary of data from several sources and retorting processes reported as mg of constituent per 100 grams of spent shale leached.
-------
TABLE 3-28. ESTIMATED QUANTITIES OF SOME MAJOR CONSTITUENTS LEACHABLE FROM OIL SHALE
(ASSUMING PERMEABILITY AND WATER AVAILABILITY ARE NOT LIMITING FACTORS)
Characteristic
Constituent
(kg leached/tonne
shale):
Ca"
ci-
HCOi
K+
Mg++
Na
so;
TDS (103°C)
pH
Conductance
(fjmhos at 25 °C)
Raw shale8
0.1
0.02
0.75
0.24
0.01
0.48
0.79
2.77
8.15
310
TOSCO3
1.14
0.08
0.20
0.32
0.27
1.65
7.3
12.6
8.40
1750
USBMa
0.42
0.42
0.38
0.72
0.04
2.25
6.00
10.9
7.78
1495
Union Aa
3.27
0.33
0.28
6.25
0.91
21
62
100
9.94
1 1 ,050
Simulated
in situb
0.04-2.1
0.06
0.22-0.40
0.000-0.18
0.00002-0.08
0.09-2.35
0.50-1.3
-
7.76-12.7
—
a References 71 and 72.
b Reference 73.
-------
TABLE 3-29. PERMEABILITY OF PARAHO SPENT OIL SHALE FOR VARIOUS COMPACTIVE EFFORTS AND LOADINGS8
Compactive
effort g-cm/cm3
(ft Ib/ft3)
Gravel size
after compaction Permeability, cm/yr (ft/yr) under loadings of
Dry Density (% passing 3,515 g/cm 7,030 gem 14,061 g/cm
g/cm3 Ib/ft3 No.4 screen) (50 psi) (100 psi) (200 psi) Remarks
Direct mode:
3,027
6,042
27,464
6,042
3,027
6,042
(6,200)
(12,375)
(56,250)
(12,375)
(6,200)
(12,375)
1.41
1.48
1.58
1.48
1.41
1.48
(88.0)
(92.
(98.
(92.
(88.
(92.
5)
7)
5)
,0)
5)
43
42
33
-
43
42
457
213
34
256
1,280-67
1,036-110
(15)
(7)
(1.1)
(8.4)
(42-2.2)
(34-3.6)
168
43
18
219
—
-
(5.5)
(1.4)
(0.6)
(7.2)
—
—
52
24
3
198
—
—
(1.7)
(0.8)
(0.1)
(6.5) Cured 28 days at 52°C
— Effluent recirculated.
— Effluent recirculated.
Indirect mode:
3,027
6,042
27,464
(6,200)
(12,375)
(56,250)
1.50
1.58
1.69
(93.
9)
(98.9)
(105,
,8)
47
42
38
2,164
116
61
(71)
(3.8)
(2.0)
1524
113
76
(50)
(3.7)
(2.5)
914
88
73
(30)
(2.9)
(2.4)
a Reference 55, page 127.
-------
ity values for Paraho spent shale compacted by different pressures (54). As ex-
pected, greater compaction leads to lower permeability values. However, it would
probably be very costly and difficult to achieve near maximum compaction
throughout a spent shale disposal operation. Therefore, the medium and higher
permeability values would likely apply to most of a spent shale disposal site.
Results of EPA-sponsored field studies indicate that permeability values of com-
pacted, direct-mode Paraho spent shale" are quite high. Table 3-30 indicates the
variability in reported permeability of several spent oil shales. All that can be stated
with certainty at present is that any proposed spent shale disposal providing for
compaction to make the shale impervious should first prove that the particular
spent shale and compactive effort can indeed make the spent shale impervious.
Even though an impervious layer (30 cm/yr or 12 in./yr or less permeability) is in-
stalled below a disposal pile, there is still a risk of groundwater pollution if the
groundwater flow rate below the pile is too low to provide substantial dilution for
any leachate that eventually seeps through the impervious bottom of the disposal
pile.
TABLE 3-30. RANGE OF REPORTED PERMEABILITY VALUES OF
VARIOUS COMPACTED SPENT OIL SHALES
Type of shale
Permeability value (cm/yr)
Comment
Paraho, direct mode
USBM
Paraho pilot plant
Paraho
Paraho, direct mode
TOSCO II
TOSCO II
2.2x103 to 4.7x103
1.6X101 to3.2x101
3.4x101 to 6.4X104
SxlO2 to 4.6X102
SxlO1 to 4.6X102
S.SxIOMo 1.3X103
3.0x101
EPA field study (66)
Lab-weathered shale (74)
Lab study, various
particle sizings and
compactive efforts (75)
Standard tests (76)
Rainfall permeability (77)
Colony study3
d Personal communication from M. W. Legatski, ARCO Colony Development Operations, 1979.
The period of time over which pollutants may continue to leach from disposal
piles in concentrations and quantities sufficient to present pollution hazards is not
known. Research is needed to establish such a relationship between time or quan-
tity of water leached through shale and the resulting change in water quality of the
leachate. However, it is possible that leachate of poor water quality could be pro-
duced for many years beyond the period of time that any particular oil shale facility
would be in operation. Two additional types of solid waste deserve special atten-
tion—raw mined oil shale and process-generated wastes, such as spent catalysts,
sludges, and shale oil coke. Overburden could be considered another type of solid
waste, especially if the oil shale is strip mined; but its environmental impacts and
control technologies should be essentially similar to those associated with other
types of surface mining.
Raw mined oil shale would have to be temporarily stored in significant quantities
on the surface to assure a steady supply of crushed raw shale for a continuous
retort operation. In addition, the mining, crushing, and transfer operations
themselves will produce some raw shale waste (especially in the form of dust) that
will require disposal. No exhaustive studies have been made to determine the nature
of leachates from raw shale that may be produced by precipitation or water sprays
99
-------
applied to control dust. Presently, EPA is in the process of assessing the nature of
these leachates, and preliminary results under saturated conditions are presented in
Table 3-31. Leaching results from wet/dry cycles are being studied and may be
quite different than results from saturated conditions.
In general, the data in Table 3-31 indicate that under saturated conditions
leachates from freshly mined raw shale, weathered oil shale (talus) and soil
presumably derived from oil shale all produce leachates that are similar. However,
soils produced from different original material may be quite different. Also, shale
from different hydrogeologic environments, such as the saline zone, may produce
substantially different leachate. In general, Table 3-31 shows a significant improve-
ment in leachate quality with passage of as few as three pore volumes of water
under saturated conditions. Results under wet/dry cycles may vary significantly
from those under saturated conditions and are presently being investigated. It
should be noted that at least one study comparing leachates from raw oil shale with
those from retorted oil shale reported that some pollutants, such as fluoride, may
leach more readily from raw shale than from retorted shale (70).
Process-generated solid wastes such as spent catalysts, lime sludges, coke, and
other solids from water and wastewater treatment systems may present a threat to
surface and groundwater quality if not handled and disposed of carefully. Some of
these wastes may contain highly toxic substances, as discussed in the preceding
subsection. Disposal of these wastes by burying them in the spent shale piles may
result in increased levels of toxic pollutants in the spent shale leachate and subse-
quent impacts on surface water and groundwater quality.
HEALTH EFFECTS OF REFINING
AND USE OF SHALE OIL AND OIL SHALE
Dr. David Coffin
The development of the synthetic fuels industry poses health hazards which must
be understood and solved in order to have hydrocarbon fluid fuel substitutes for
petroleum in the near future. This goal appears possible since prior experience with
the petroleum industry has demonstrated that potentially hazardous fuels may be
refined and used without obvious undue danger to human health. The problems
posed by shale oil appear more complex and will probably require extra steps in
treatment prior to refining as well as careful attention to hygienic practices.
Human Health Effects
There is little actual experience with the toxicity of the American oil shale in-
dustry because of the limited amount of time of its existence and the relatively
small number of persons exposed. A survey at the U.S. Bureau of Mines operations
was reported by Birmingham (77) with data being completed for the years 1952 (197
workers), 1953 (170 workers), and 1954 (181 workers). A large number of benign
skin lesions was observed in the workers, but when they were compared to a
matched group according to age and their length of residence in the Colorado
Plateau, no apparent increase was found from occupational contact with this par-
ticular shale oil technology.
Such an incidence of lesions would be likely from exposure to the intense solar ir-
radiation characteristic of this region. No conclusions can be made from this first
tentative epidemiological study because of insufficient time of exposure and the
limited number of persons involved.
A more recent study is being conducted by Costello (78) in which cases have been
selected from the 1,198 persons who have worked at the Anvil Point operations and
from a control sample composed of 320 cases selected from 1,000 coal miners in
eastern Utah and western Colorado. Methods used in this survey are described by
the author.
100
-------
TABLE 3-31. LEACHING CHARACTERISTICS UNDER SATURATED CONDITIONS OF RAW SURFACE STORED OIL SHALE-
PRELIMINARY RESULTS1"1
Colony soil(bl
UNITS
Al Mg/1
As
B
Ba
Be
Ca
Cl
C03
Cr
Cu
EC-Mmhos/cm@25°C
F Mg/1
Fe
HC03
Hg
K
Li
Mg
Mn
Mo
Na
Ni
N03
Pb
pH
Se Mg/1
Si
Sn
SO,
TDS
TOC
Zn
INITIAL
< 0.05
< 0.005
0.70
0.40
< 0.025
960
200
0.17
< 0.025
0.38
9000
10
0.01
233
< 0.0005
270
0.47
1450
0.10
0.84
340
0.060
1800
0.27
7.1
< 0.01
7.3
1.37
4200
19800
512
0.65
~3PV
0.07
< 0.005
0.53
0.12
< 0.025
200
1.4
1.04
< 0.025
0.075
2000
1.4
0.18
192
< 0.0005
50
0.09
140
0.38
0.18
6.2
0.040
< 0.2
0.20
8.0
< 0.01
8.0
0.25
1000
1850
44
0.02
C-b soil(cl
INITIAL
< 0.05
< 0.005
0.65
0.169
< 0.025
330
—
_
0.069
0.28
3300
—
_
_
< 0.0005
22
_
145
0.075
0.125
2050
0.075
—
0.31
8.3
< 0.0005
11.0
—
—
—
—
-
~3PV
< 0.05
< 0.005
0.87
0.038
< 0.025
6.5
_
_
< 0.025
< 0.025
750
—
—
—
< 0.0005
1.3
—
2.6
< 0.025
< 0.05
210
< 0.05
—
0.070
8.8
< 0.0005
11.7
_
—
—
—
-
Colony raw shaleldl
INITIAL
< 0.05
< 0.005
0.75
0.34
< 0.025
1110
22
0.18
< 0.025
0.16
527
7.2
< 0.03
304
< 0.0005
19
0.085
72
0.240
0.07
100
0.087
25
0.17
7.8
< 0.01
7.61
0.24
4250
6000
_
0.62
~3PV
< 0.05
< 0.005
0.43
0.16
< 0.025
200
3.0
1.2
< 0.025
< 0.025
106
5.0
< 0.03
250
< 0.0005
2.3
0.10
18
0.820
0.18
15
< 0.05
< 2.5
0.095
7.9
< 0.01
4.54
0.17
400
770
_
0.06
Colony weathered16'
INITIAL
< 0.05
< 0.005
0.365
0.495
< 0.025
500
71
0.12
< 0.025
0.31
537
5.2
< 0.03
233
< 0.0005
57
0.012
365
0.07
0.74
350
0.06
245
0.22
8.1
< 0.01
14.7
0.67
2650
4750
_
0.11
~3PV
< 0.05
< 0.005
0.170
0.088
< 0.025
25
1.5
0.63
< 0.025
0.05
48
8.7
< 0.07
189
< 0.0005
0.8
< 0.004
17
0.068
0.11
33
< 0.05
0.8
0.13
8.3
< 0.01
6.78
0.047
33
220
_
0.24
a Preliminary Results from EPA Grant R806278, initial leachate and leachate after 3 pore volumes. Personal communication from Dr. David McWhorter, Colorado State University, 10-21-79. Inquiries regarding
availability of the final report f r Grant R806278 should be addressed to E. R. Bates, IERL, US EPA, Cincinnati, Ohio, 45268.
b Colony soil-Approx. 600 yards north o.f mine portal. d colony raw shale—Mine stockpile below surface.
c C-b soil —Cottonwood Gulch SE of plant. e Colony weathered—400 yards SW of mine portal — tailus slope material.
-------
TABLE 3-31 (continued)
Horse draw saline'"
UNITS
Al Mg/1
As
B
Ba
Be
Ca
Cl
C03
Cr
Cu
EC-(jmhos/cm@25°C
F Mg/1
Fe
HC03
Hg
K
Li
Mg
Mn
Mo
Na
Ni
N03
Pb
pH
Se Mg/1
Si
Sn
SO,
TDS
TOC
Zn
f Horse draw— saline zone.
INITIAL
1.85
< 0.005
29.5
0.17
< 0.025
520
430
0.10
0.55
0.22
11000
75
0.75
243
< 0.0005
19
2.4
1050
2.9
0.44
1430
0.48
<25
0.57
6.8
< 0.01
7.5
1.1
5600
12600
228
5.2
~3PV
0.80
< 0.005
0.95
0.10
< 0.025
220
5
0.15
< 0.025
< 0.025
1100
25
0.01
122
< 0.0005
2
0.11
12.2
0.23
0.09
65
0.04
< 6.25
0.080
7.3
< 0.01
3.4
0.38
425
1300
11
0.39
Union Nat. retorted'^'
INITIAL
< 0.05
< 0.005
0.370
0.120
< 0.025
45
_
_
0.400
0.160
1100
—
—
—
< 0.0005
55
_
103
0.05
0.32
44
< 0.05
—
0.10
8.6
< 0.0005
11.0
—
—
—
—
—
9 Union naturally retorted— 90 yards SW of mine portal.
~3PV
< 0.05
< 0.005
0.210
0.037
< 0.025
13
_
—
0.031
< 0.025
385
_
_
—
< 0.0005
11
_
60
< 0.05
0.125
16
< 0.05
—
0.105
8.3
< 0.0005
12.0
—
_
—
—
—
C-a composite"1'
INITIAL
< 0.05
< 0.005
1.45
0.093
< 0.025
425
—
_
< 0.025
0.060
6500
_
—
—
< 0.0005
34
—
415
0.240
2.20
740
0.090
_
0.204
8.2
< ,0.005
10.0
—
—
—
_
—
^3PV
< 0.05
< 0.005
0.40
0.051
< 0.025
100
—
_
< 0.025
< 0.025
750
—
—
_
< 0.0005
2.0
—
48
0.062
0.475
33
< 0.05
_
0.075
8.3
< 0.005
10.9
—
_
—
_
—
C-a, R-5 & Mahogany1'1
INITIAL
< 0.70
< 0.005
0.59
0.11
< 0.025
1430
—
< 0.025
0.16
15000
_
< 0.0005
280
_
0.35
0.20
3600
0.085
—
0.150
11.4
< 0.005
5.94
_
—
—
—
~3PV
< 0.30
< 0.005
< 0.025
0.088
< 0.025
900
—
< 0.025
< 0.025
2750
_
< 0.0005
50
_
< 0.05
0.225
310
< 0.05
< 0.05
12.0
< 0.005
1.65
—
noludes some overburden that is not shale
C-a R-5 & Mahogany — Composite of materials from the R-5 and Mahogany zones.
loto-. AH dm ir, thte rable were obTained t>v lB«.oHl«S cO1um™ IDS cm in length under saturate
-------
An occupational health survey of the Paraho oil shale works has recently been
reported by Rudnick and Voelz (79) who examined 87 persons employed in various
categories of the industry. These were grouped as "highest exposed," "less ex-
posed," and "minimally exposed." The authors concluded that no disease prob-
lems were shown to be attributable to the oil shale exposure in this study. They do
point out, however, that seven lost work time episodes were attributable to ac-
cidental physical trauma in a twelve-month period.
In consideration of occupational health surveys of employees of the American
oil shale industry, a number of limitations must be kept in mind. Since the effort
thus far has been small and frequently intermittent, very few workers at risk for
any appreciable time can be found. Futhermore, since miners "tend to work in
mines" employees of the oil shale industry frequently have experience in coal,
uranium or other mining opportunities in the Rocky Mountain region. Another
factor in occupational surveys is the necessity of comparing the oil shale workers to
matched controls in some other industry where physical exertion would be similar
but with entirely different exposure possibilities. Such design is required because
physical workers tend to have health profiles which differ from more sedentary
workers or the general population. It would thus appear that occupational data
must remain quite tentative until the industry has expanded to provide continuous
employment to a larger number of persons.
Considerably more experience with human exposure is available for the Scottish
Lothian oil shale industry which existed for a period in the latter half of the past
century and for the Estonian shale industry which has been actively pursued for
about 40 years. These data have been the subject of recent detailed reviews so will
be only briefly mentioned here (80).
In brief, the Scottish industry which existed before and during the early years of
this century shows data for skin cancer among workers in the oil industry and more
particularly for scrotal cancers among workers in the British cotton spinning in-
dustry of the period. These latter, the "mule spinners cancer," have become
notorious as examples of occupationally-induced cancer and were occasioned by
heavy contaminations with rather highly carcinogenic material and very poor stan-
dards of personal cleanliness and occupational hygiene. The incidence of this
disease markedly diminished in later years as shale oil was gradually replaced by
petroleum products.
The Estonian shale differs strikingly from shale which is expected to be exploited
in the United States. Because of its high organic content it is possible to extract
energy by direct combustion of the pulverized rock for electric power generation
and the like. This mode of combustion accounts for approximately 75 percent of
current usage. Another difference is its high content of phenolics which are ex-
tracted for commercial purposes during the production of shale oil.
Data from Estonia suggests a small increase in pneumoconiosis in oil shale mine
workers presumably from exposure to rock dust and some acute and chronic
neurological disturbances among retort workers which they attribute to the ex-
posure to phenols. There appears to be no measurable increase incidence in cancer
among males occupationally exposed or in the general population of the region
although they report a slight increase of cancers in women in the area (81).
Biological Experimentation
Considerable biological data have been accumulated over a number of years in
the United States for the TOSCO II process by Coomes (82,83) who conducted skin
bioassays comparing various petroleum products—coke oven tar and whole shale
oil and whole shale oil upgraded by hydrotreating. Coomes (84) summarizes these
studies and presents new data from the Kettering Laboratory.
Biological testing of oil shale effluents and products has recently intensified,
largely due to the U.S. Navy-sponsored retorting by the Paraho technology and
103
-------
subsequent refining at Sohio which has made materials for testing available. These
testing programs consist of a comprehensive effort funded by the American
Petroleum Institute (API), specific tests conducted by the U.S. Navy and an In-
teragency Matrix Approach sponsored by EPA and DOE. Preliminary data from
the API-sponsored study were presented at the Ninth Conference on Environmen-
tal Toxicology on the 28th, 29th, and 30th of March 1979. Among these studies
Slomka et al. (85) have reported acute experiments on the skin, conjunctiva, cornea
and iris and oral LD50 rat studies to various shale oils and retorted shales as well as
systemic effect on rabbits and sensitization studies on guinea pigs. As might be ex-
pected, toxicity was noted in other tests—the LD50 for rats being reported as 8 to 10
g/kg (S.OOxlO-3 to l.OOxlO-2 Ibs/lb) while dermal LDSO for rabbits was above 10
ml/kg (1.2xlO~3 gals/lb). Systemic toxicity, noted after oral and percutaneous ad-
ministrations, was decreased locomotor activity, pilo erection and ptosis. Shale oils
showed moderate reversible irritation to the skin and eye. The liver appeared to be
the target organ for systemic and the skin and mucous membranes for per-
cutaneous applications. No sensitization was noted in guinea pigs.
Weaver and Gibson (86) have reported on acute and chronic studies of a crude
shale oil and their upgraded counterparts by various routes (oral, dermal, and con-
juctival). They also have described inhalation studies on unretorted and retorted
shale dust. They describe no significant nonreversible lesions.
Toxicity studies of shale rock and retorted shale dust have been reported by
McFarland (87) who conducted inhalation experiments in rats and cynomologous
monkeys at concentrations of 10 and 30 mg/m3 (4.37xlQ-3 and l.SlxlO'2 grains/ft3)
for five days a week for two years. According to the author, results available from
this study indicate no abnormalities attributable to the exposure regimen. Conoway
(88) reports mutagenesis and teratogenesis studies by various methods on shale
rock, retorted shale and shale oil. All shale oil samples studied were mutagenic by
microbial tests, negative by mouse lymphoma tests and negative in rat bone mar-
row cytogenetics tests. Fetal toxicity was observed at high dose levels of shale oil.
Cowan and Jenkins (89) report preliminary studies on the effect of shale derived
fuels and their petroleum analogues by inhalation exposure of vaporized material
in laboratory animals. The parameters of this study include physiological and
biochemical, and behavioral tests and pathological examination. Data suggest an
overall increase in tumors (gross evidence only) from petroleum products. No data
are yet available for shale oil products.
Barkley et al. (90) have studied various oil shale materials for carcinogenicity.
These consisted of nonretorted and retorted shale rock dust suspended in whole
mineral oil and two crude shale oils—one extracted by heat transfer process and
one by the retort combustion process. They also studied, comparatively, shale
crude versus upgraded shale crude. Chemical determinations are also reported by
these authors. In summary, this report is similar in the two shale crude
studies—namely, eight malignancies out of 12 mice and 43 weeks as average time of
appearance of papillomas. In their experiments to compare raw shale oil (direct
retort product) and the same oil upgraded by hydrotreating, striking differences
were noted. They noted 21 malignant and 18 benign tumors for the raw oil com-
pared to three malignant and two benign tumors from the upgraded oil. The
average time to the appearance of papillomas was 30 weeks and 49 weeks, respec-
tively. Their experiments with unretorted and retorted shale rock dust were
negative (Table 3-32).
These same investigators report chemical analytical data for shale oil from infor-
mation supplied by the American Petroleum Institute. They identify the following
hydrocarbons classified as follows: carcinogens—Benzo(a)pyrene and Benz(a)an-
thracene; borderline carcinogens—chrysene and nine additional polycyclic
aromatic compounds and those which are noncarcinogenic. They conclude that the
carcinogenicity of the shale oils tested does not correlate well with the carcinogenic
104
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compounds which were isolated (see Table 3-32). They also report experiments de-
signed to detect embryotoxicity and teratogenicity by oral dosing in rabbits. No
dose dependent abnormalities were noted and no differences were observed from
comparative dosing with inert carbon.
The program in the federal laboratories consists of an integrated coordinated
evaluation of the potential toxicity of shale oil development and use under the
EPA/DOE Matrix Approach as well as independent studies. In the Matrix Ap-
proach a central materials repository receives specimens from the respective
technologies, processes them and distributes aliquots to participating investigators.
More than 15 public and private laboratories are now participating in this effort.
The plan for this study was addressed at a joint EPA/DOE meeting in March 1979
(91,92). Data from these efforts will be presented at a second conference scheduled
for June 1980. The overall rationale and plan which is concentrating on the Paraho
above ground retort process and the Sohio refining program as a model is por-
trayed in Tables 3-33 and 3-34.
Considerable data are now available from the federal program from an interplay
of chemical analysis and short term mutagenesis testing. Guerin et al. (93) and
Epler et al. (94,95) have noted that the highest specific activity is contained within
the basic fraction of the crude shale oil. Subsequent analyses have shown that one
half or more of the total mutagenicity is found in the basic fraction which con-
stitutes only five percent of the mass. Further fractionation demonstrated that this
activity can be again concentrated in 10 percent or less of the total basic fraction.
This phenomenon probably explains some of the striking difference of shale crudes
(and coal fluids) from petroleum crudes where the basic fraction content is in-
significant. While the most conclusive results are from coal fluids, preliminary
results show that the activity within the basic fraction for shale oil as well is due to
its content of polycyclic aromatic amines. Experiments have shown that light
hydrotreating easily destroys the specific mutagenic activity of these alkaline con-
stituents of shale oil. Additionally, there appears to be general agreement between
the Ames test for mutagenesis and skin bioassay for carcinogenesis in both crude
shale oil and hydrotreated oil.
Pelroy et al. (96) have compared the mutagenicity of several different "crude"
shale oils and various coal fluids by short term testing after fractionation by solvent
extraction and by partition chromatography. They report the most activity in the
basic fraction or the equivalent methanol fraction. The highest mutagenic activity
was noted for coal with a much lower content for crude shale oil and very little ac-
tivity for crude petroleum. They attribute the mutagenic activity for both coal
fluids and shale oil in this fraction to the presence of aromatic amines. The data
from biological studies of the American shale oil are currently preliminary and ten-
tative. It is evident from information now available that the so called shale oil
"crudes" are more carcinogenic than petroleum crudes but that this difference is
ablated by hydrotreating. Mutagenesis studies with the Paraho shale "crude" sug-
gest that there is agreement from the summation of various fractions of the whole
oil with skin carcinogenic bioassay both from the presence of mutagenicity/car-
cinogenicity in the crude shale oil, and from its removal by hydrotreating. For
mutagenicity, shale oil ranks above petroleum but far below coal fluids. The in-
tensely mutagenic materials contained in the basic fraction (or equivalent methanol
fraction from partition chromatography), presumably polycyclic aromatic amines,
are readily altered by hydrotreating. Thus, when the shale retort fluids are
hydrotreated, the resulting refinery feed stock has little or no significant mutagenic
activity, being essentially similar to crude petroleum in this aspect. While shale oil
crude appears much less active than coal fluids, it should be recognized as being
potentially carcinogenic and handled accordingly. The differences reported in
mutagenicity of various shale retort tars may reflect the organic compounds in the
rock, but probably is a function of temperature and other variables during the
retort process. There is an indicated need for coordinated chemical and
105
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TABLE 3-32. CARCINOGENIC POTENCY OF RAW AND UPGRADED SHALE OIL"
Sample
Raw shale oil
Upgraded shale oil
Positive control
(0.05 BaP in toluene)
Negative control
(toluene only)
Strain
of
mice
C3H
C3H
C3H
C3H
Dosage
50
50
50
50
mg.
mg.
mg.
mg.
twice
twice
twice
twice
weekly
weekly
weekly
weekly
Number
of
50
50
100
100
Finalb
effective
mice
45
39
92
91
BaP
(%)
<0.00005
0.0006
0.05
0
Number of mice
developing tumors
Malignant
21
3
75
0
Benign
18
2
9
0
Average time
of appearance
of papillomas
(weeks)
30
49
46
a Source: Reference 91.
b The final effective number is the number of mice alive at the time of appearance of the median tumor plus those mice that may have died with tumors.
-------
TABLE 3-33. REPOSITORY DISTRIBUTION OF PARAHO ABOVE GROUND RETORT MATERIALS
Mineral- Infrared Chemical P&H
Shale material ogical finger fraction-
print ation
Raw shale X
Airborne raw
shale particles X X
Raw shale particles,
baghouse X
Retorted particles,
baghouse X
Product oil
Product water
Process water
Thermo-oxidizer
particles
Leachate,
retorted shale
Composite shale oil X X
Hydrotreated
shale oil X X
Organic Trace Particle Morpho- Ames Droso- Trachael Intra- Oral Organ
analysts element sizing logical Assoc. philia trans- trachea! toxicity culture
analysts plant
X X X X
X X X X XX X
X X X X XX X
X X
X
X
X
X
X
-------
TABLE 3-34. REPOSITORY DISTRIBUTION OF SOHIO-REFINED PARAHO SHALE OIL MATERIALS
AND PETROLEUM EQUIVALENTS
Sample requirements
study
Shale oil material Carcinogenesis RAM anal.
Crude shale oil X X
Hydrotreated shale oil X X
Weathered gas feedstock
JP-5 precursor
JP-6 precursor
DFM precursor X X
Hydrotreated residue X X
JP-5 product
JP-6 product
DFM product X X
Combustion effluent DFM
Acid sludge
Petroleum equivalents
JP-5 product
JP-6 product
DFM product X
Comprehen-
sive anal.
X
X
X
X
X
X
X
X
X
X
Marine eco- Diesel
sys. effect Carcinogenesis exhaust
X
X
X
X X
X
X
X
XXX
X
X
X X
Mutagenesis
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Mutagenesis El-
chemical anal.
X
X
X
X
X
X
X
X
X
(continued)
-------
TABLE 3-34. (continued)
Sample requirements
study
Mutagenesis &
Shale oil material short-term
animal
Crude shale oil X
Hydrotreated shale oil X
Weathered gas feedstock
JP-5 precursor
JP-6 precursor
DFM precursor
Hydrotreated residue
JP-5 product
JP-6 product
DFM product
Combustion effluent DFM
Acid sludge
Petroleum equivalents
JP-5 product
JP-6 product
DFM product
Pond Eco-sys. Gas
effect chroma-
tography
X
X
X
X X
X
X
X
Acute oral Drosophilia
mouse mutagenesis
toxicity
X X
X X
X
X
X
X
X X
X
X
X
X
X
X
X
Cytocicity Chemical class
fractionation
X X
X X
X
X
X
X
X X
X
X
X
X
X
X
X X
Stability
screening
X
X
X
X
X
X
X
X
X
X
X
X
X
X
-------
mutagenic/carcinogenic studies of shale crudes and various refined products to
determine the influence of retorting and refining techniques on these parameters.
While preliminary American studies suggest that no significant chronic pulmonary
changes after 2 years' exposure result from inhalation of shale rock dust or retort
particulate emission products, such data should be viewed with caution since shale
rock contains sufficient silica to render it suspect. The carcinogenicity of the raw
shale crude should be noted and ways derived to reduce the activity or otherwise
guard against it by control practices. Few data are available for emission products.
It is of paramount importance to compare combustion emissions from shale fuels
with their petroleum counterpart since the quantitative and qualitative differences
(organic compounds) in fuels may contribute to variations in levels of mutagens or
carcinogens in the exhaust emissions.
In summary, preliminary biological studies of the oil shale industry have not yet
demonstrated unmanageable problems of toxicity. Additional studies are in pro-
cess from which data will be available in the present year. These experiments will
further delineate potential toxic profiles and possibly confirm provisional data now
available. Continued research is needed for strengthening of data now in existence
and developing data as required on various refinery cuts including residual oil,
emission products from retorting and refining, and combustion of fuels for the
production of power. Data are needed on the potential health hazards which might
be associated with the contamination of stream estuaries or underground water by
various leachates from shale oil technologies. While results thus far are encourag-
ing, it would be prudent to reserve judgment on the potential toxicity of oil shale
development and shale oil production and use until the data base is extended to
other parameters and there are confirmatory results of other investigators. Such an
approach can assure the rapid development of this resource in an acceptable man-
ner from the standpoint of risk to human health.
OTHER ENVIRONMENTAL IMPACTS
Prepared for Dale Denny & Bruce Tichenor of RTF
By Radian Corporation
Shale Products Utilization
Refining—
To date, refining studies concerning shale oil have been limited in scope and size
and have primarily been concerned with demonstrating technology rather than de-
termining effluent concentrations and properties. Therefore, as stated in the
previous topic, limited information exists on the health and environmental impacts
from shale oil utilization.
In addition to the carcinogenic potential of crude shale oil, the health impact of
other toxic chemicals in crude shale oil must also be considered. Arsenic is found in
all fractions of crude shale oil at concentrations up to 1,000 times that of natural
crude levels. Nitrogen, in the form of cyanides, pyroles, pyridines, and other com-
pounds, is present in concentrations that are 6 to 10 times that of most crudes. Oxy-
gen levels of shale oils are twice those of natural crudes, resulting in larger amounts
of acids, phenols, and other oxygenated compounds (97,98,99).
As with carcinogenic potency, the toxic effects of these compounds decrease
with upgrading, since further processing eliminates these contaminants from prod-
uct streams. Therefore, any significant increase in health problems will occur dur-
ing upgrading, when the physical and chemical properties of shale oils differ the
most from those of natural crude oils. The upgrading steps to which crude shales
will initially be exposed include dearsenation, coking, and hydrotreatment. These
initial processing steps are sufficient to remove the high heteroatom and arsenic
concentrations that are the refiners' major processing, environmental, and health
and safety concern when dealing with raw shale oil. In addition, another important
110
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source of potential health risk is exposure to fugitive emissions, especially when
they originate from crude shale oil leaks and spills.
Caustic washing and guard beds have been proposed for arsenic removal from
shale oils. However, in comparing economics, process operability, and en-
vironmental effects, the guard bed process has been found to be superior to caustic
washing in all three respects (100). Chevron found that the guard beds removed
essentially all the arsenic and 70 percent of the iron in raw Paraho shale oils, based
on material balances in a recent refining study (101). The guard bed adsorbent
catalyst was also effective in removing zinc and selenium from the shale oil. Since
the catalyst involved is a relatively inexpensive commodity, disposal is the most
likely fate of spent guard bed catalysts. Special handling and disposal precautions
should be employed to avoid any health, environmental, or safety problems that
may be associated with high arsenic and other trace metals.
The greatest concern for employee health in regard to coking processes is ex-
posure to air emissions. These emissions include coke dust from decoking, combus-
tion gases from coking process heaters, and fugitive emissions. Particulate emis-
sions from delayed coking are associated with removing the coke from the coke
drum, and subsequent handling and storage operations. Hydrocarbon emissions
from cooling and venting the coke drum before coke removal are also present.
Particulate emissions and hydrocarbon emissions from delayed coking of syn-
thetic liquids will not be greater than that for natural crude oil coking, but they are
potentially more toxic because of chemical dissimilarities. Wetting down the coke
during the decoking operation should alleviate any additional impact from the cok-
ing particulates of synthetic liquids. Also, hydrocarbon emissions from coke drums
can be collected and routed to a refinery flare in order to reduce their impact.
These practices are routine in modern refinery operations.
Fluid coking is a continuous process that uses the fluidized solids technique to
convert residues to lighter products. This process entails high operating tempera-
tures and short residence times, thus eliminating the need for coke drums and
avoiding the environmental and health problems associated with decoking.
However, flue gases from the burner beds are passed through cyclones and
discharged to refinery stacks. If refinery schemes include fluid cokers for process-
ing large quantities of synthetic liquids, the potential exists for higher nitrogen ox-
ide levels in combustion gases.
Hydrotreating is a catalytic process that uses hydrogen to stabilize and/or to
remove objectionable elements such as sulfur, nitrogen, oxygen and trace metals
from feedstocks or products. The heteroatoms removed, primarily in the form of
hydrogen sulfide, ammonia, and water, will be accompanied by traces of light
hydrocarbons. This gas stream can be routed to ammonia recovery and acid-gas
removal units because of the extremely high nitrogen content of shale oils. Addi-
tional ammonia recovery facilities may be necessary if substantial shale oil refining
is undertaken. Hydrocarbons emitted from shale oil hydrotreating should be
similar in quantity and composition to those resulting from natural crude oil
hydrotreating and can be handled using existing refinery equipment.
Of the trace elements found in shale oils, only arsenic is found to be higher in
concentration than in normal crude oils, and essentially all of it can be removed
before treatment with adsorbent guard bed catalysts. Therefore, effluents from the
regeneration of spent shale oil hydrotreating catalysts that have been contaminated
with trace metals or nitrogen compounds should not cause any additional health or
environmental problems.
Fugitive emission sources are the second largest source of hydrocarbon emissions
in petroleum refineries (102). All chemical species present in shale oils may possibly
be present in fugitive emissions; therefore, the exact composition and magnitude of
fugitive emissions depend primarily on maintenance and housekeeping practices of
the individual refinery.
Ill
-------
Evaporation from open surfaces and leaks from valves and fittings associated
with processing equipment such as cokers and hydrotreaters that operate under
high temperatures may discharge significant levels of heteroatomic substances. Ex-
posure to shale-oil-derived fugitive emissions might result in additional health
hazards if major utilization of shale oil is undertaken.
Fugitive emission controls are primarily based on procedures rather than equip-
ment. Design and maintenance techniques can be employed to reduce or eliminate
fugitive emissions and are discussed in Section 4.
The limited data base on shale oil refining emissions will be expanded as a result
of the November 1978 refining run of 16,000 m3 (100,000 bbl) of Paraho shale oil at
Sohio's Toledo, Ohio, refinery. The run included processing by hydrocracking (to
reduce the nitrogen levels) to produce jet fuel, marine diesel fuel, and residual fuel
oil (No. 5 or 6).
Radian Corporation conducted an assessment of fugitive emissions and an in-
dustrial hygiene survey for the U.S. Navy under an EPA contract. The data from
this study are not yet published, but preliminary analyses indicate that no abnormal
environmental emissions occurred when compared to refining of conventional
crude oil. Unfortunately, the data used to draw the preliminary conclusion are very
sparse. Only an extremely small number of fugitive emission sources were found
and sampled.
In summary, the limited data available to date suggest that the refining of shale
oil in petroleum refineries should produce emissions that are similar to those now
produced when conventional crude oils are refined. These emissions include at-
mospheric discharges of particulates, sulfur and nitrogen oxides, heavy metals, and
hydrocarbons (including potentially hazardous materials). Liquid effluents can be
expected to contain biochemical oxygen demand (BOD), chemical oxygen demand
(COD), suspended solids, oil and grease, phenols, ammonia, sulfides, heavy
metals, and hydrocarbons. Control techniques now being employed in the
petroleum industry should be applicable to controlling emissions from shale oil
refining. The environmental and health effects associated with shale oil refining
should be similar to those occurring under conventional crude oil refining. Again,
it is stressed that the data available are very limited. Further data must be collected
and analyzed before the environmental impacts of refining shale oil are fully
known.
Storage and Handling—The evaporation of volatile hydrocarbon components
during storage and handling is the greatest source of atmospheric emissions in the
refinery. It is recognized that many products handled and stored at a refinery are
more volatile than crude shale oil. Nevertheless, the storage and handling of crude
shale oils, which contain higher levels of arsenic, nitrogen compounds, and oxygen
compounds, could pose potential health or environmental problems for the refiner.
Raw shale oils are expected to undergo a mild thermal treatment at the retort
facility to crack the long paraffin chains that contribute to high pour points. This
would make pipelining of the crude shale oil possible at ambient or slightly elevated
temperatures. Despite this thermal treatment, shale oils can still be expected to con-
tain fewer light ends than typical petroleum crudes. Lower emission rates,
therefore, would be associated with ambient storage and handling of these
naphthadeficient shale oils. (See Section 4 for a discussion of storage tank vapor
controls.)
Initial upgrading steps at the refinery such as dearsenation, coking, and
hydrotreatment of shale oils will result in a synthetic fuel remarkably similar to
natural crude oil. The degree of processing will, of course, affect the ultimate car-
cinogenic activity of the refined shale oil. The storage and handling of upgraded
shale oil products are therefore not expected to provide the refiner with additional
health or environmental problems.
Refinery Sludges—Biological sludges, tank bottom sludges, and API separator
112
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sludges that contain substantial amounts of crude shale oil contaminants might
pose additional health or environmental problems for the refiner. These con-
taminants will include increased amounts of nitrogen oxygen compounds. Trace
element concentrations will be similar to those of natural crude oils, except for
arsenic, which might be present in storage tank sludge at significant levels. Source
controls for refinery sludges are discussed in Section 4.
Combustion of Shale Oil Products
It is very likely that early utilization of shale oils will be as utility fuel or as a
refinery fuel in boilers or process heaters. All criteria pollutants can be expected to
be emitted from the combustion of shale oils, as with petroleum fuels. However,
the quantities of these emissions will be a function of the degree of upgrading in-
volved and the nature of contaminants in the synthetic fuel.
Although little information is available concerning the emissions from the com-
bustion of shale oils, present data indicate -that differences between shale-derived
fuels and their petroleum counterparts in either performance or emissions are in-
significant. [A 1977 Paraho refining study revealed that slightly higher nitrogen
and ash contents of certain shale oil fractions account for the differences in emis-
sions between shale and petroleum-derived fuels (103)] .Also, evidence to date sug-
gests that particulate polycyclic organic matter emissions associated with combus-
tion of refined shale oils are not inherently greater than those from combustion of
similar boiling-range petroleum oils (98).
Thus, the only emission problem that might be associated with the combustion
of shale-derived fuels, as compared with normal fuels, would be slightly higher
NOx emissions when limited upgrading is applied. Four general techniques or
modifications that can be employed for the control of NOx emissions are:
Combustion modification
Fuel modification
Alternate furnace design
Flue gas treatment
Radiation—Prepared by The Pace Company Consultants & Engineers, Inc.,
a Division of Jacobs Engineering Group Inc.
Among trace elements found in Green River Formation oil shale are thorium,
uranium, and potassium. Thorium and uranium are the naturally occurring heavy
radionuclides that decay into various products (daughters) that are also ubiquitous
in nature. The decay products of thorium-232, uranium-235, and uranium-238 are
all found in the earth's crust or atmosphere, and they account for much of the
background radiation to which man is exposed. Of naturally occurring potassium,
the light radionuclide, potassium-40, is only 0.012 percent abundant. Potassium-40
has a half-life of 4x10* years and decays by beta emission to stable calcium-40.
Trace element analysis of TOSCO II spent shale from the Colony Development
Operation site revealed concentrations of 0.99 ppm uranium, 0.77 ppm thorium,
and 2.72 percent potassium, or 3.26 ppm potassium-40 (104). Allowing for a
mineral content of 82.6 percent for 120 I/tonne (35-gal/ton) raw oil shale, and
assuming that all uranium, thorium, and potassium remain in the spent shale after
pyrolysis, the uranium-238, thorium-232, and potassium-40 concentrations in the
raw shale would be 0.82, 0.64, and 2.7 ppm, respectively (105). These data and
assumptions are summarized in Table 3-35.
Table 3-36 is an extension of Table 3-35 and presents a summary of estimated
total radionuclide release anticipated from a 13,600-tonne/day (100,000 bbl/day)
oil shale facility. Such a facility would process approximately 119,724 tonnes
(132,000 tons) of oil shale daily. In a radioactive disintegration series where the
half-life of thorium-232 or uranium-238 (parent) is much longer than that of the
113
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daughters, the daughters can be assumed to be in secular equilibrium with the
parent. Thus, in natural deposits of heavy radionuclides, the daughter's radioactiv-
ity is assumed to be the same as the major parent. The calculations presented in
Table 3-36 assume that all of the radon gas trapped in the oil shale will be released
to the atmosphere during mining, crushing, and retorting; they should be regarded,
therefore, as representing an upper limit.
TABLE 3-35. ESTIMATES OF RADIOACTIVE ELEMENT
CONCENTRATIONS IN COLONY SHALE" (ppm,
Type of shale Uranium-238b Thorium-232 Potassium-40
Spent shale
Raw shale
0.99
0.82
0.77
0.64
3.26
2.7
a Source: References 105 and 106.
^ The low relative natural abundance of uranium-235 {0.715 percent) results in activity of only 4.5 percent of
uranium-238 and its daughters.
The concentration of radon-220, radon-222, and their daughters in an
underground mine atmosphere depends not only on the uranium and thorium con-
tent of the oil shale, but also on the ventilation rate of the mine. In 1975, a survey
was made of the presence of radon-222 and radon-220 daughters in 223 operating
underground coal mines in 15 States (106). According to this survey, there appears
to be no significant health hazard from inhalation of radon-222 and radon-220
daughters in underground coal mines. Coals generally contain more trace amounts
of uranium and thorium than does Green River Formation oil shale.
Radon emanates naturally from soils at the average crustal rate of 1.4 pCi/mz-s
(4xlO-2pCi/ft2-s). Approximately 400 MCi of radon-222 per year are emitted
naturally from the conterminous United States. In performing an initial assess-
ment, this natural emission would have to be compared with anthropogenic emis-
sions. Anthropogenic emissions would involve the emanation of terrestrially en-
trained radon-222 from ores during mining, crushing, and retorting, and the
residual emanation of radon-222 from spent shale disposal areas.
Secular equilibrium will be reestablished in spent shale disposal areas. Because of
the similarity of spent shale to the composition of the rock and soil of the surroun-
ding area, it is probable that little or no additional radon emanation above that of
the natural background of the area will be induced by spent shale disposal opera-
tions (106). This will depend to a certain extent on the methods of shale crushing,
retorting, and stabilization of spoil.
No population exposure or worker dose calculations have been made for the pur-
pose of projecting health effects of oil shale development. Estimates have been
made (106), however, that indicate that population exposure doses derived from
the extraction of shale oil are relatively insignificant compared with geothermal
utilization and coal combustion, liquefaction, and gasification.
Noise—Jacobs Environmental, a Division of Jacobs Engineering Group Inc.
The noise impacts of oil shale development apply to various primary and secon-
dary aspects of the industry. The aspects of oil shale development causing the most
concern are the following: Surface processing plant construction and operation,
mining, reservoir operation, pipeline construction, transmission line construction
and operation, highway construction and operation, railway construction and
operation, and community expansion. A summary of the anticipated noise impacts
caused by these activities is presented in this section.
114
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TABLE 3-36. ESTIMATED RADIOIMUCLIDE EMISSIONS TO THE AIR
FROM A 13,600-TOIMIME/DAY (100,000-bbl/DAY) OIL
SHALE FACILITY8 (^ Ci/day)
Radionuclides
Uranium-238
Thorium-234
Protactinium-234
Uranium-234
Thorium-230
Radium-226
Radon-222
Polonium-218
Lead-214
Bismuth-214
Polonium-214
Lead-210
Bismuth-210
Polonium-210
Thorium-232
Radium-228
Actinium-228
Thorium-228
Radium-224
Radon-220
Polonium-216
Lead-212
Bismuth-212
Polonium-212
Thallium-208
Potassium-40
Total
Fugitive dust
0.64
0.64
0.64
0.64
0.64
0.64
—
0.64
0.64
0.64
0.64
0.64
0.64
0.64
0.16
0.16
0.16
0.16
0.16
—
0.16
0.16
0.16
0.10
0.06
40
50
Gases Particulates
- 4.9
- 4.9
- 4.9
4.9
- 4.9
- 4.9
32,800
- 4.9
- 4.9
- 4.9
- 4.9
4.9
4.9
4.9
1.3
1.3
1.3
1.3
1.3
8,300 -
1.3
1.3
1.3
0.9
- 0.4
- 310.0
41,100 385
a Source: Reference 105.
Noise Generation-
Construction Activities— The largest amount of noise will be generated during
construction of the mine, surface processing facility, reservoir, pipeline, transmis-
sion line, rail line, highway, and community expansions. The construction of these
facilities will cause a large amount of heavy equipment to be moved into an area
which has been historically very quiet. The operation of this heavy equipment and
the blasting that occurs during construction of the mine will have the greatest im-
pact on the environments that surround oil shale developments.
The main source of noise from community expansion is due to road and house
construction. The extent to which this noise affects human activity depends on the
proximity of the construction to local population centers and also on the local
topography and meteorological conditions.
Plant Operation—During operation of a surface processing plant, the greatest
sources of noise are the retort vessels, compressors, heat exchangers, cooling fans,
pumps, control valves, air and steam pipe leaks, and transportation vehicles to and
from the plant. Noise from retort vessels and stacks used in an oil shale processing
facility will have an average decibel rating of 95 to 100 dB (A) at 7.5 m (25 ft) (107).
115
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The major sources of noise in the operation of an underground mine are
associated with the crushers, mining and transportation equipment, ventilation
systems, and blasting. The noise levels from operation of equipment at the mine
will be the same as those cited in the construction phase.
Noises from the operation of a plant-associated water reservoir results from
spillway and outlet operation, dredging, aeration, recreational use, maintenance,
and engine noise.
During operation of a pipeline, compressors and pumps are the main sources of
noise.
During operation, the outer conductor of a transmission line will be the main
source of noise and should produce a negligible impact on human activities and
wildlife (106).
Noise Impacts—
According to guidelines set out in a 1974 EPA document (108), a 24-hr average
exposure to 70 dB (A) and 55 dB (A) may contribute to hearing loss and speech in-
terference, respectively. Current knowledge is insufficient to determine whether
these decibel levels apply to wildlife protection. A large number of laboratory ex-
periments have shown that physiological stress is experienced by certain animals at
varying decibel and sound pressure level exposures. Intermittent exposure to sound
pressure levels of about 80 dB or more have been associated with increased blood
pressure, increased adrenocortical activity, increased levels of serum cholesterol,
decreased fertility, induction of seizures, and various other physiological stresses
and behavioral abnormalities in laboratory animals (109,110). Based on this
evidence, the following impact determinations have been made.
Construction Activities—The greatest noise impact to local wildlife will be ex-
perienced during construction. Based on the estimated noise levels of heavy duty
construction equipment and the results of the laboratory noise stress tests
mentioned previously, it can be assumed that construction of the mine, processing
plant, transmission lines, pipeline, water reservoir and road may cause a temporary
local displacement of wildlife. The noise impact of construction activities during oil
shale development would be very similar to that of community expansion activities,
which produce the same noise levels attributed to heavy-duty construction equip-
ment. Under EPA accepted threshold limits for humans, these levels may cause
temporary discomfort to human residents. But no displacement of wildlife would
be expected from community expansion activities, since a large portion of the local
animals would have already been removed by community establishment.
Plant Operation—It is anticipated that noise-related impacts resulting from the
operation of oil shale processing facilities and directly related support activities will
displace certain species of animals but will have a negligible effect on local com-
munities of people, assuming that population centers are built at sufficiently safe
distances.
The noise levels that may be experienced 7.5 m (25 ft) from a processing facility
such as an oil shale surface processing facility might displace local wildlife popula-
tions. Operation of the mine should create low-profile noise levels; however,
blasting will impose a sharp peak on background. The operation of a pipeline,
water reservoir, and access road may cause wildlife to relocate, thus perpetuating
biological stress and possible consequential population decrease in local
ecosystems.
The extent to which noise created by vehicles traveling on a highway affects the
environment will depend on the number of vehicles using the road, the speed of the
vehicles, local topography and meteorological conditions, and proximity to
population centers. Noise impacts to communities can be minimized by locating the
highway away from noise-sensitive areas such as hospitals, schools, residences, and
various species of wildlife.
116
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Socioeconomic Impacts—Jacobs Environmental, a Division of Jacobs
Engineering Group Inc.
The oil shale region contains approximately 10 counties in three States, including
five counties in Northwest Colorado, two in Northeast Utah, and three in
Southwest Wyoming. The counties that are considered illustrative of all ten are Rio
Blanco, Colorado, and Uintah, Utah.. Generally, employment in the Oil Shale
Region is mainly based on agricultural and mining enterprises. In terms of value of
production, the primary industry category is dominated by mining (111). The il-
lustrative oil shale counties are very thinly populated, with an average density of
.77 persons/km2 (two persons per sq mile). Most of the residents live in single unit
houses located in small towns. Most of the land in this area is used for either graz-
ing, agriculture, or wildlife habitat.
Water availability in the Upper Colorado River Basin depends on physical
availability, State water laws, and the law of the river (a combination of Federal
laws, interstate contracts, and court decisions that divide the Colorado River
waters among the States through which it flows). Presently, the largest use of water
in the oil shale region is irrigation.
The major socioeconomic impacts of any proposed commercial oil shale
development in the oil shale region will be due to: (1) the population growth
resulting from the new work force required for the construction and operation of
the proposed project; (2) the demand for housing, municipal, and human services
generated by the new population; (3) the impacts on the local and regional
economy, including new employment opportunities at higher wage scales, new
public revenues, and changes in the structure of the economy caused by shifts in the
relative importance of the basic economic sectors (112).
The analysis of these social and economic impacts was designed to consider ef-
fects created during project development, operation, and project end. During pro-
ject development, a series of economic, demographic, social, and land use impacts
would be created. Some of these impacts can be traced with reasonable reliability to
characteristics of the new primary industry itself—in particular its size, and the
characteristics of its workforce (occupation, earnings, etc.). Given this information
and a knowledge of socioeconomic profiles and relationships in comparable situa-
tions, preliminary estimates can be made of total employment, female employ-
ment, employee earnings, total income, retail sales and service receipts, total
population, population age distribution, school age population, household
characteristics, housing requirements, land requirements (for residential, business,
and community facility purposes), community development costs (capital and
operating) and revenues, and other impacts associated with the new primary in-
dustry.
Relationships drawn from socioeconomic profiles of mining-dominated counties
have been assembled in a straightforward community development programming
model, which was used to estimate the impacts of the construction and operation
of a synthetic fuels plant (113). A summary of these estimates as they relate to a
unit oil shale facility is quantitatively presented in Tables 3-37 and 3-38. Some
socioeconomic effects of synthetic fuels development, however, cannot be quan-
titatively estimated from characteristics of the primary industry alone, even in
preliminary form. These potential effects would be determined by the interplay of
primary industry development impacts with each prospective community. Ex-
amples of such interplay include the effects of synthetic fuels development on tradi-
tional local economic functions, job opportunities for local residents, local govern-
ment finances, the local crime rate, local prices for essential goods and services,
and the creation or exacerbation of many social and political problems. The results
of this interplay are termed "end impacts," and they define many of the key
socioeconomic issues in synthetic fuels development. Since end impacts would be
the result of the interplay between the development impacts and a particular pre-
117
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impact situation, the outcomes would be almost as variable as local communities.
Socioeconomic Impacts of Oil Shale Development on Tracts U-a, U-b—
Because of a recent court case involving land ownership at Tracts U-a and U-b,
development on those sites has been postponed for an indeterminate time.
The development of an oil shale complex in the White River area of Utah will
produce positive economic impacts on the surrounding local communities and on
the county as a whole. The areas to be most intensely affected are the cities of
Rangely, Colorado, Vernal, Utah and Roosevelt, Utah and to a smaller extent,
Duchesne, Utah.
Approximately 3,450 persons will move into the area to provide services for the
primary work force of 2,300 so that the total employment in the tenth year of
development will be approximately 6,000 workers. The ultimate population in the
fifteenth year will be 12,535, which represents an increase of 30 percent over
baseline projections. The total income in the fifteenth year will ultimately be $147
million, which represents a 56 percent increase over baseline projections. The im-
pact on demand for land and municipal, health, and education services will be
negative in the short term. However, the community is expected to benefit in the
long term from extensive local expenditure and net tax revenues (Table 3-38).
A detailed summary of the projected social and economic impacts is presented in
Table 3-39. The table assumes that no new town will be built, and the impacts have
been presented as areawide impacts, nonspecific to individual townships.
TABLE 3-37. ESTIMATED SOCIO-ECONOMIC IMPACTS OF
OIL SHALE DEVELOPMENT" b
Time periods
Peak Operational
Impact construction phase phase
Employment (total)
Primary
Secondary
Female employment (total)
Primary
Secondary
Employment earnings (total), 1975 $(000)
Primary
Secondary
Average annual income
Per employee, 1975 $
Total income, 1975 $(000)
Total local business income, 1975 $(000)
Total induced population
Total induced families
Housing needs:
Single family
Multi-family
Mobile homes
3,140
2,000
1,140
610
40
570
46,700
26,400
10,300
11,700
40,300
Not Available
5,760
2,270
1,120
500
870
2,530
1,100
1,430
760
40
710
28,700
15,700
13,000
11,300
34,500
20,000
5,260
1,700
1,070
270
450
a Source: Reference 108.
Estimates are based on a 45,000-bbl/day unit oil shale facility.
118
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TABLE 3-38. ESTIMATED COSTS FOR COMMUNITY EXPANSION
RESULTING FROM DEVELOPMENT OF A 45,000-bbl/DAY
UNIT OIL SHALE FACILITY8
Amount
_ Type of Cost _ (in thousands) _
Recreation costs
Capital $ 670
Operating and maintenance • 50
School Costs, 1975 $(000)
Capital 6,960
Operating and maintenance 1,540
Community facilities, 1975 $(000)
Capital 3,340
Operating and maintenance 40
Utilities, 1975 $(000)
Capital 12,470
Operating and maintenance 1,040
Annual revenue, 1975 $(000) 3,300
Total adjusted annual cost, 1975 $(000) 5,310
a Source: Reference 108.
Socio-Economic Impacts of Oil Shale Development at Tract C-a —
Development on Tract C-a is expected to affect the towns of Rangely and Rifle
most intensely, with smaller-scale impacts occurring in Meeker. These communities
would be most seriously affected by the increased demand on municipal services
and the reorganization of the community infrastructure that would be caused by an
increase in the local population.
Direct employment at Tract C-a began in 1977 with the construction of support
facilities such as powerlines. Construction employment rose to 175 during early
1977 and increased to 230 near the end of the year. It is expected to stay at or above
that level of employment ( + 300) until late 1979. Construction will continue in
1980, and employment will gradually decrease and level off at about 100 employees
through 1982. Employment projections beyond 1982 will be made when the deci-
sion to continue commercial development is made. Ninety percent of these Rio
Blanco Oil Shale Development Corporation (RBOSC) employees are expected to
be local, with the remainder being new area residents. Of the total employees, 80
percent are expected to be married, with an average family size of 3.8 members. A
summary of the anticipated employment and population increase is presented in
Table 3-40.
Original estimates set employment at the White River Shale Project (WRSP) at a
peak of 3,500 in year eight. That projection has been increased to 4,800 (personal
communication with Rees Madsen, White River Shale Project, Environmental
Coordinator, October 1979). But since no official revision has been made to other
social and economic impact projections dependent on that figure, all figures
reported for Tracts U-a and U-b are based on original projections of the DDP.
These figures will probably be revised when development activity commences.
119
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TABLE 3-39. SUMMARY OF PROJECTED SOCIO-ECONOMIC IMPACTS OF OIL SHALE DEVELOPMENT
ATTRACTS U-a AND U-blabcl
Annual
employment
Item
Phase 1:
Commercial
development
stage
50,000 bbl/day
production
Phase II:
100,000 bbl/day
production
Year
1
2
3
4
5
6
7
8
9
10
15
20
Primary
400
400
300
300
1,300
1,800
2,300
3,500f
2,500
2,300
2,300
2,300
Secondary
120
120
120
150
650
900
1,380
2,450
2,250
2,300
3,450
3,450
Total
induced
population
924
924
1,218
1,305
4,538
6,218
8,277
13,780
11,310
10,902
12,535
12,535
Total
wages
earned
annually
(in thousands)
$ 12,220
12,220
5,700
6,015
38,665
54,990
25,756
102,725
66,925
58,190
70,265
70,265
Average
employee
wage"'6
$27,400
27,400
14,800
14,800
24,492
25,300
_
22,000
17,320
14,800
14,800
14,800
Projected housing
Total requirements
Total annual (housing units) School
net tax tax single multi- mobile room
revenued revenue6 family family homes requirement
— — — — — —
_ _ _ _ _ _
_ _ _ _ _ _
$1,662,100 $1,906,000 218 25 145
- - - 34.5
_ — _ _ _ _
— — — — — —
8,369,500 10,931,000 1,769 203 2,489 -
_ _ _ _ _ _
- - - - - 87.0
- - - - 93.5
17,248,600 19,522,000 1,972 227 1,643 -
a Source: Reference 108.
b All numbers in this table reflect original projects of Tracts U-a, U-b to be found in the DDP Document. Employment figures and other subsequent numbers are subject to future revision.
c Assumes no new town development.
d 1975 dollars.
e Determined by multiplying the number of employees in each working class by their respective wages, and dividing this number by the total number of employees.
f This figure has been changed to 4,800. Verification is through eeitorial comments by Rees Madsen.
(continued)
-------
TABLE 3-39 (continued)
Item
Phase 1:
Commercial
development
stage
50,000 bbl/day
production
Year
1
2
3
4
5
6
7
8
9
10
Natural gas
utilities
capital costd
$ 375,600
—
—
19,200
1,146,000
440,400
—
—
—
—
Electrical
utilities
capital costd
281,700
—
—
9,900
859,500
442,800
1,222,000
—
—
Water
utilities Hospital
demand bed Doctor
(MGD) reqm'ts reqm'ts
— —
_ _ _
_ _ _
— — -
0.104
- — -
— — —
— — —
2.82
Fire Fire Fire Police- Police
Dentist Nurse Firemen station pumper truck men vehicle
reqm'ts reqm'ts reqm'ts reqm'ts reqm'ts reqm'ts reqm'ts reqm'ts
— — — — — —
_____ — — _
____ — — __
________
- 6.6 0.4 0.4 0.4 6.7 18.5
________
— —
— — — — —
- - 13.6 _____
Phase II:
100,000 bbl/day
production 15
20
Total
3.28 - - -
44.5 7.0 5.0
16.0 1.2
14.0 -
1.2
1.2 28.7 45.6
-------
TABLE 3-40. PROJECTED EMPLOYMENT AND POPULATION INCREASES
RESULTING FROM OIL SHALE DEVELOPMENT AT TRACT C-aa
Year
1977
1978
1979
1980
1981
1982
Maximum RBOSC
employment
230
300
300
100
100
100
Maximum RBOSC
new-resident
employees'1
207
270
270
90
90
90
Maximum
secondary
employment0
104
135
135
45
45
45
Maximum
employment
334
435
435
190
190
190
Maximum
new-resident
population11
631
851
851
274
274
274
a Data presented are unofficial; they are based on projections, data, and criteria submitted to the U.S. Area Oil Shale Supervisor as manpower estimates and housing surveys(115).
b Equals 90 percent of total employment at RBOSC.
c Equals 50 percent of new-resident employees.
d Equals 80 percent of new-resident employees multiplied by average number of family members (3.8) per married employee.
-------
The number of persons employed as service employees to meet the needs of
population increases in the community as a consequence of RBOSC development
(secondary employees) is estimated to be 50 percent of the total new-resident per-
sons directly employed. Fifty-two percent of the service employees are projected as
locally based residents, and 48 percent as new residents. Eighty percent of the ser-
vice employees are projected as being married with a family size of 3.8 members.
It should be pointed out that the documents available for socioeconomic impact
review of C-a development did not quantify the anticipated community impacts.
However, a discussion of the existing facilities and their ability to expand and meet
rising demands is available, and from this, rough impact assessments can be drawn.
The increased population induced into the area by the C-a oil shale project will af-
fect the community infrastructure in the following manner.
Schools in both Rangely and Meeker have additional student-carrying capacity
in the elementary, junior high, and high school levels. The local college, North-
western Community College, had an enrollment (as of March 1979) of 300, with a
resident capacity of 500. Rangely and Meeker school districts have bonding
capacities of $15.7 and $2.9 million, respectively.
All of the housing units available for occupancy in Rangely and Meeker are filled
and new homes are sold before they are completed. A 400-unit housing subdivision
is presently under construction in Meeker and a few houses are available for sale.
To help remedy this situation, RBOSC has devoted much tune, effort, and
money to the development of a new master plan for Rangely and has assisted
Rangely in its application to acquire 6,177 ha (2,500 acres) of BLM land adjacent
to the town. Tract C-a has also been instrumental in the development of a new road
connecting the Tract to Rangely and is assisting the development of a mobile home
park, and a mass transportation system.
Rangely, Meeker, and Rifle all have modern hospital facilities and full-time resi-
dent doctors. A clinic at Colorado Northwestern Community College provides all
the dental hygiene needs in Rio Blanco County.
The water delivery and sanitary waste treatment systems at Rangely, Meeker,
and Rifle have all undergone significant improvements in the past 2 years. These
improvements have been designed to accommodate the increased populations that
are expected to result from oil shale development at Tracts C-a and C-b.
Major funding support for the water systems and sewage treatment plant expan-
sions comes from the State of Colorado's oil shale trust fund. This trust fund is the
State's share of the bonus money paid for the two Federal oil shale leases in Col-
orado. Although to date (1979) some $21 million has been committed to funding
these and other projects geared to mitigate impacts of the oil shale developments,
more than $60 million remains in the fund.
Socioeconomic Impacts of Oil Shale Development on Tract C-b—
The impacts of development on Tract C-b are expected to be centralized in Gar-
field County, with less significant impacts occurring in Rio Blanco County. This is
largely due to the facts that property tax revenues will accrue largely in Rib Blanco
County, while at the same tune population increases will mostly impact Garfield
County. The main impact originates from economic and physical growth in the
rural areas of Rio Blanco and Garfield Counties.
All local physical and economic growth will originate from the increase in
population resulting from direct and indirect employment for the oil shale develop-
ment. The total peak population during the mine development phase and plant
construction phase (including direct employees, their families, service workers, and
their families) is estimated to be 1,400 and 13,500, respectively. The total perma-
nent population, once the proposed project is in operation, is estimated to be be-
tween 6,000 and 6,500.
At present, municipal services such as schools, health services, water sanitation,
utilities, roads, housing, and police and fire protection are all operating at full
123
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TABLE 3-41. SUMMARY OF SOCIO-ECONOMIC IMPACTS OF OIL SHALE DEVELOPMENT AT TRACT C-ba
Average
Annual
employment
Item
Phase 1:
Mine
Development
Phase II:
Plant
Construction
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
31
Primary
320
350
59
59
512
1,446
2,947
2,331
1,145
1,093
1,123
1,123
1,123
1,123
1,145
1,154
1,154
1,154
1,172
1,172
Secondary
212
195
30
30
387
1,463
3,325
3,040
1,563
1,640
1,640
,640
,640
,640
,718
,731
,731
,731
1,758
1,758
Total
induced
population
1,413
1,304
229
229
2,579
7,200
13,461
12,361
5,953
5,860
5,860
5,860
5,860
6,018
6,137
6,185
6,185
6,185
6,280
6,280
Total
wages Average
earned employee
annually0 wagec'd
7,091,362
7,419,948
940,344 18,270
940,344
11,349,278
32,367,041 -
66,467,821 21,824
49,133,861
17,908,133 -
16,049,172
16,049,172 -
16,049,172
16,049,172
16,493,052 15,985
16,818,564
16,951,880 -
16,951,080 -
16,951,080
17,216,112
17,216,112 -
Total
annual
tax
revenue0'6
902,603
1,189,258
341,371
176,945
1,558,645
5,014,425
11,275,710
12,349,615
10,162,858
10,712,419
10,817,850
10,795,792
10,795,792
10,852,164
10,931,411
10,975,600
10,987,186
10,987,186
11,020,846
11,044,191
Total
number
of
families
354
328
62
62
649
1,813
3,403
3,133
1,575
1,585
1,585
1,585
1,585
1,528
1,660
1,673
1,673
1,673
1,699
1,699
Projected housing
requirements
(housing units)
Single
family
96
94
40
40
176
528
1,023
979
795
951
951
951
951
951
977
996
1,004
1,004
1,020
1,020
Multi-
family
51
50
20
20
94
280
540
514
398
470
470
470
470
483
492
496
496
496
504
504
Mobile
homes
349
314
18
18
636
1,762
3,305
2,970
927
656
656
656
656
674
687
692
692
692
703
703
School
room
requirement
19
17
4
4
35
95
179
166
83
83
83
83
83
86
89
89
89
89
90
90
3 Source: Reference 113.
D Derived by adding the monthly employment figures for each year and dividing by 12.
c 1975 dollars.
° Derived by taking the average yearly wage for all employee classes.
e Total excess tax revenue over 31 years is 37.6 million.
-------
capacity. The total front-end capital costs associated with municipal expansion for
6,300 new permanent residents would be roughly $36 million (1975 dollars), ex-
cluding highways. Total annual operating and maintenance costs for the same ser-
vices would be $7.5 million. In per-capita costs, these figures translate to $5,751
capital and $1,200 operating and maintenance costs. Housing costs are not in-
cluded.
Once the project is operational, it will generate more than $11 million per year in
public revenues. Total tax revenues over the 60-year life of the project will be
$273.3 million, which represents an excess, after expenditures (excluding
highways), of $27.4 million. More than $549 million will be paid in wages over the
life of the project.
Details of the projected socioeconomic impact of oil shale development on Tract
C-b have been summarized in Tables 3-41 and 3-42.
TABLE 3-42. AVERAGE ANNUAL MUNICIPAL AND HUMAN SERVICE
COSTS FOR TRACT C-b FOR A 31-YEAR PERIOD8 b
Item
Total per-capita municipal
and human service cost
Vocational/technical needs
Higher education needs
Water requirements
Sewage requirements
Solid waste collection
requirements
Open space and recreation
needs
Government regulation needs
Police protection needs
Fire protection needs
Basic health requirements
Capital
costs
$ 7,997.47
5,424,000
1,995,000
2,540,000
2,770,000
90,200
2,419,544
224,830
192,134
962,810
1,367,531.50
Operating and
maintenance costs
$ 1,204.41
1,097,200
744,800
184,499
135,200
100,500
179,065.50
505,300
201,200
247,700
741,653
a Source: Reference 113.
b 1975 dollars.
Socioeconomic Impacts of Oil Shale Development at Colony—
The major impact of oil shale development on the Colony Tract will be due to
the physical and economic change caused by induced populations of direct and ser-
vice employees for the operation. The impacts have been analyzed by Colony using
three case situations, each one assuming different locations and intensities of
growth. Original estimates showed that 1,200 people would be employed at Colony
during Phase I (construction), and 1,050 during Phase II (operation) (115). These
figures have now been revised, and peak construction employment is now
estimated at 2,500 to 2,700 employees (personal communication with Max Legat-
ski, ARCO Colony Development Operations, Environmental Coordinator, Oc-
tober 1979). Since these revised figures and all social and economic quantifiable im-
pacts dependent on those numbers have not been published, the impacts in this
125
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TABLE 3-43. SUMMARY OF SOCIO-ECONOMIC IMPACTS OF OIL SHALE DEVELOPMENT
AT THE COLONY DEVELOPMENT OPERATION3 COLONY
Impacts
Phase 1:
Construction
Phase II:
50,000 bbl/day
operation
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19'
20
21
22
28
Annual Total Total
employment induced annual
Primary*1 Secondary population revenue0
- - - 2,129
- 7,943
1,200 450 3,438 2,940
- - - 3,036
- - - 4,438
- 5,907
- - - 7,049
- 7,433
- 7,404
- - - 7,477
- 7,605
- - - 7,693
1,050 975 4,875 7,779
_ _ _ _
_ _ _ _
— — — —
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
_ _ — —
— — — —
Projected Total
housing requirements induced
Single Multi- Mobile student
family family homes population
_ _ _ _
_ _ _ _
405 270 675 810
_ _ _ _
_. _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
— — — —
_ _ _ _
975 325 325 1,625
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
_ _ _ _
— — — —
Projected detail of upgrading health
and municipal service facilities
School in surrounding counties
facility Natural Water Electrical
expansion gas utility utility utility
requirement requirement requirement requirement
— —
None — — —
_ _ _ _
_ _ _ _
_ _ _ _
— _ _ _
_ _ _ _
— _ _ _
_ _ _ _
— — — —
— _ _ _
Expansion Expansion Expansion Expansion
— _ _ _
— — Significant —
— — Impact —
— — _ —
— — —
— — —
— _ _
— _
— — —
— — — —
® Source: Reference 116,
D These figures have been revised to 2,500 to 2,700. (Personal communication with Max Legatski, ARCO Coiony Development Operations, October 1979.)
c 1974 dollars.
-------
discussion were based on original estimates published in the Colony Environmental
Impact Analysis (115). This analysis projects the migration of 2,438 persons during
peak construction, and 4,875 persons during peak operation. Because of this large
influx of new local residents, municipal health and utility services are expected to
be strained if no expansion programs are employed. A certain amount of expansion
has already been planned because of the high growth rate expected, regardless of
oil shale development. To assist in the economic completion of these expansion
programs, tax revenues and income distributed throughout the surrounding
localities will be available from the oil shale project.
In Phase I, the annual salaries and wages from the project are estimated to be
$20 million. In Phase II, the annual salaries and wages from the project are
estimated at $12 million. In addition, increases in annual revenues per 1,000 in-
crease in population are estimated to be $432,733.
A summary of the anticipated impacts is presented in Table 3-43. Information in
this table is derived under the assumption that growth resulting from the develop-
ment of the Colony tract will take place according to Case I. This case assumes
scattered growth along the Glenwood Springs/Grand Junction corridor.
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98. Atwood, M. T. The Production of Shale Oil. Chem. Tech., October 1973, p. 617.
99. Crawford, K. W., C. H. Prien, L. B. Baboolal, C. C. Shih, and H. A. Lee. A
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100. Stauffer, H. C., and S. J. Tanik. Shale Oil: An Acceptable Refinery Syncrude. ACS,
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Advanced Catalytic Processes. U. S. Department of Energy, Washington, D.C., 1978.
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109. Information on Levels of Environmental Noise; Requisites to Protect Public Health
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110. A Biologist's Manual for the Evaluation of Impacts of Coal-Fired Power Plants on
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SECTION 4
POLLUTION CONTROL TECHNOLOGY
This section reviews the applicability and shortcomings of technology for control
of participate matter, gaseous emissions, wastewater, and solid waste leachates
resulting from oil shale processing. Although proven control techniques for many
pollutants in process effluents are available, they generally need to be
demonstrated in a large-scale oil shale processing plant.
A wide variety of techniques is cited regarding their potential applicability for
control of particulate matter and gaseous emissions. Many of the techniques have
been successfully used in industries with similar problems, but without the prob-
able wide variety of pollutants, particularly trace elements, resulting from handling
enormous quantities of raw shales.
Wastewaters are characterized, insofar as possible, from the limited information
available. Standard primary, secondary, and tertiary water treatment methods will
be applicable to waste streams, but some of the more highly polluted wastewaters
will require research on process methodology to ensure that priority pollutants and
toxics are removed. Numerous modes of treatment, recycling, and control should
be explored to optimize water utilization at each processing site.
Control of pollutants resulting from solid waste disposal will be an immediate
and long-term problem that will require monitoring during operations and perhaps
several years after shutdown of an operation because of potential leachate prob-
lems. This section reviews control techniques for surface and underground disposal
sites, stabilization of in situ spent shale, and leachate treatment and recycling.
Also reviewed in this section are controls for refinery sludges and vapor losses
from storage tanks. Refinery experience should be directly applicable to these
problems.
AIR EMISSION CONTROLS
Robert Thurnau
The commercialization of the oil shale industry will have a significant impact on
air quality of the Piceance Valley and possibly on the nearby wilderness areas.
Federal, State, and local air pollution statutes will require the process developer to
take a hard look at the air pollution control options available, so that the above-
mentioned statutes are not violated.
Control of Particulates—Mining, Crushing, Screening, Transportation,
Retorting and Spent Shale Disposal
As mentioned earlier, development of the oil shale industry will probably result
in significant particulate emissions which may increase the particulate load in am-
bient air beyond allowable limits. The impact of particulate emissions on ambient
air is emphasized because of the newly enacted legislation (the Clean Air Act
Amendments of 1974).
Particulates, many of which are fugitive dusts, result from all phases of oil shale
industry operations. The need for control of particulates generated from mining,
crushing, screening, transportation, retorting and disposal will be one of the
significant pollution control problems faced by the industry. A wide variety of con-
133
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trol strategies is available for the removal of paniculate matter from ambient air or
the process gas stream. These control techniques offer many differences in collec-
tion efficiency, initial cost, operating and maintenance cost, waste products, and
space requirements.
Water Sprays—
The oldest and simplest control technique is the water spray. Water sprays can be
used where evaporation is possible, and if adjusted properly, the operation has no
runoff. Water sprays have potential application to: (a) spent shale disposal, (b)
grinding and screening operations, (c) mining and blasting activities, and (d)
fugitive dusts from surface vehicles and surface retort feeder systems.
The efficiency of water sprays without wetting chemicals is about 80 percent for
particles the diameter of which is 5 mm (2x10"" in) or greater. Removal efficiency
drops off as particle size decreases and has been reported at 25 percent for particles
in the 1 mm (4x10"' in) range (1).
The addition of a wetting agent helps to reduce surface tension and improve the
wetting, spreading, and penetrating characteristics of water. Reduced surface ten-
sion allows the particles to agglutinate and increases the removal efficiency.
Spray systems have the advantage of suppressing the particulate, and the solids
are carried along with the oil shale, thereby reducing one of the waste disposal
problems by incorporation of the dust into the shale. However, minimizing a prob-
lem in one area of particulate control could intensify the control problems of
another—namely, retorting. Additional advantages of water sprays are that they
are economical and easy to operate. The disadvantages of spray systems are that
they can clog or cause other machinery to clog, and they can freeze in cold weather.
Several oil shale developers have estimated the particulate emissions from their
mining, blasting, crushing, transfer, and disposal operations, along with the pro-
jected degree of air pollution control achievable by a water spray technique utiliz-
ing a wetting agent (2) (Table 4-1).
Chemical Binders—
Chemical binders are an effective tool for the control of fugitive dust emissions.
Chemical solutions are deployed over the desired area, and upon drying, they form
a protective coating over the exposed area. The treatment has the net effect of
reducing the surface area that would be exposed to weathering and erosion, and it
greatly reduces the amount of particulate that would be released from the storage
area. The materials used as binders can range from inorganic salts to polymeric
material. Note that several of the oil shale development areas are rich in carbonates
and bicarbonates, and these compounds might be useful as chemical binders.
The costs for binders vary with the type of material chosen. Estimates have been
set at about $56.65/ha ($140/acre), but these costs can increase rapidly when man-
power and equipment costs are factored into the operation (1).
No data are available to illustrate the effectiveness of chemical binders as a pollu-
tion control device for oil shale particulate emissions.
Cyclones—
Cyclones have been used as air pollution control devices for particulates. They
are a form of inertial separators that utilize centrifugal force and an abrupt change
in direction of the gas stream to reduce the concentration of the dust in the gas.
Cyclones are designed so that the incoming gas stream forms a double vortex, one
of which spirals downward on the outside, and the other of which spirals upward
on the inside. The centrifugal force that moves the particles toward the edge of the
outside wall is a function of the square of the inlet velocity and of the inverse of the
radius of the cyclone. The collection efficiency depends on the amount of energy
expended; thus cyclones with high inlet velocities, small diameters, and long
cylinders are usually the most efficient.
134
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TABL,E 4-1. WATER SPRAY AS A CONTROL TECHNIQUE FOR PARTICIPATES"
Estimated
uncontrolled emission rate
(kg/hr)
Paraho C-b
Activity Ref. 3 Ref. 4
Mining 79.5 2136
Blasting 165.7 -
Primary crushing 165.6 —
Transfer 165.7 37
Retorted shale
disposal — 166
Transfer 245.7 —
Traffic 519.8 -
Wind erosion 207.9 -
Coarse ore
storage — —
Anvil
Points
Ref. 4
840
-
—
—
353
—
—
—
320
Colony
Ref. 4
665
-
—
—
278
—
—
—
253
C-a
Ref. 4
1783
-
-
—
742
—
—
—
450
Paraho
Ref. 3
1.2
2.5
24.9
2.5
-
12.3
131.4
41.6
—
Estimated
controlled emission rate
(kg/hr)
C-b
Ref. 4
43
-
—
4
17
—
—
—
—
Anvil
Points
Ref. 4
17
—
—
—
35
—
—
—
16
Colony C-a
Ref. 4 Ref. 4
13 35
- -
— —
— —
28 37
— —
— —
— —
13 23
Paraho
Ref. 3
98.5
98.5
98.5
98.5
-
95.0
75.0
80.0
—
Estimated
control efficiency
C-b
Ref. 4
98
—
—
90
90
—
—
—
—
Anvil
Points
Ref. 4
98
—
—
—
90
—
—
—
95
Colony
Ref. 4
98
—
-
—
90
—
—
—
95
C-a
Ref. 4
98
—
—
—
95
—
—
—
95
a Based on a 50,000-bbl/day operation.
-------
Single cyclones are generally considered to be efficient only for particles with
large diameters. As the particle size begins to approach 10 mm (4xlO~4 in.), the effi-
ciency of the cyclone decreases. To improve efficiency, several cyclones can be in-
tegrated into the dust collection system, and collection efficiencies of up to 90 per-
cent have been achieved for particles of 5 mm (2x10-" in) in diameter. However, the
greater the desired efficiency of cyclones, the higher the costs, and for particles less
than 10 mm (4xlQ-4 in) in diameter, cyclones are not generally the recommended
collection procedure.
Cyclones have potential application to these oil shale gaseous effluent streams:
Grinding off-gases, screening off-gases, mining dusts, and retorting off-gases.
Fabric Filters—
When high efficiency on small particles (smaller than 5 to 10 mm or 2 to 4xlO"4
in) is required for air pollution control, one of the most widely used methods is the
fabric filter. The fabric is usually constructed in bag form, and the entire system is
called a baghouse. As the effluent gas stream passes through the baghouse, the dust
is removed by one or more of the following phenomena: interception, impinge-
ment, diffusion, gravitational settling, or electrostatic attraction. The initial filtra-
tion builds up a layer of dust or cake on the bag, and as more contaminated air
passes through the system, the dust cake acts as a filter. The cloth serves mainly as
a support structure, and the dust itself is responsible for the high levels of removal
efficiency.
In addition to the high filtering capability of the dust, efficiencies of fabric filters
are also dependent on particulate size distribution, density, chemical composition,
and moisture. Under most conditions, a properly designed and operated baghouse
operates with efficiencies of 99 percent or better on a mass basis for particles as low
as 1 mm (4xlO"s in) in diameter.
Table 4-2 summarizes the performance estimates for fabric filters that are pro-
posed as particulate air pollution control devices at several planned oil shale opera-
tions. As the table shows, baghouses have potential application for particulate con-
trol of many oil shale gaseous effluent streams.
TABLE 4-2. FABRIC FILTER AS A CONTROL TECHNIQUE FOR PARTICIPATES
Paraho Rio Blanco Rio Blanco Anvil Colony C-a
Activity Phase I Phase II Points
Ref. 3 Ref. 5 Ref. 5 Ref. 4 Ref. 4 Ref. 4
Raw shale storage
Primary crushing
Primary stockpiling
Primary ore reclaiming
Subore crushing
Overburden crushing
Secondary crushing
Fine ore storage
Storage bins
Transfer operations
Tertiary crushing
Retort feed
Spent shale disposal
Direct heat
Indirect heat
Combined heat
Estimated uncontrolled emission rate
(kg/hr)
333
—
—
—
—
—
1,866
—
919
—
8,398
8,396
10,659
11,382
10,840
408
141
454
—
—
3,107
610
—
—
—
—
—
—
1,474
—
—
227
1,111
6,577
—
1,497
_
7,484
—
_
—
—
_
780
—
—
—
—
2,403
320
—
79
—
—
632
—
—
—
—
1,904
253
—
63
—
—
—
1,683
—
—
_
—
3,367
450
—
167
2,225
—
_
—
136
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TABLE 4-2. (continued)
Activity
Paraho Rio Blanco Rio Blanco Anvil Colony C-a
Phase I Phase II Points
Ref. 3 Ref. 5 Ref. 5 Ref. 4 Ref. 4 Ref. 4
Estimated controlled emission rate
(kg/hr)
Raw shale storage
Primary crushing
Primary stockpiling
Primary ore reclaiming
Subore crushing
Overburden crushing
Secondary crushing
Fine ore storage
Storage bins
Transfer operations
Tertiary crushing
Retort feed
Spend shale disposal
Direct heat
Indirect heat
Combined heat
Raw shale storage
Primary crushing
Primary stockpiling
Primary ore reclaiming
Subore crushing
Overburden crushing
Secondary crushing
Fine ore storage
Storage bins
Transfer operations
Tertiary crushing
Retort feed
Spent shale disposal
Direct heat
Indirect heat
Combined heat
0.9
—
—
—
—
—
5.6
—
2.8
—
25.2
25.2
22.8
22.8
22.8
99.7
—
—
—
—
—
99.7
—
99.7
—
99.7
99.7
99.8
99.8
99.8
—
0.8
1.4
0.9
—
—
6.2
1.2
—
—
—
—
—
_
—
Estimated
—
99.8
99.0
99.8
—
—
99.8
99.8
—
_
—
—
_
—
—
— —
6.5 2.3
— —
— —
0.5
4.9
29.0 7.2
- 1.0
6.6 -
0.4
33.0
— —
— —
— —
— —
control efficiency
(%)
— —
99.8 99.7
— —
— —
99.8
99.8 -
99.8 99.7
- 99.7
99.8 -
- 99.5
99.8
— —
— —
— —
— —
— —
1.9 5.0
— —
— —
— —
— —
5.7 168.0
0.8 1.4
— —
0.3 0.8
6.7
— —
— —
— —
— —
— —
99.7 99.7
_ _
— _
_ _
_ —
99.7 95.0
99.7 99.7
— —
99.5 99.5
99.7
— —
— _
— —
— —
Wet Scrubbers—
Many different kinds of paniculate collection devices use water as the medium
for removing entrained dusts. Spray chambers, wet cyclones, mechanical scrub-
bers, orifice scrubbers, venturi scrubbers, and packed towers have all been used in
the past. The new Federal and State air pollution regulations have, in essence, re-
quired that wet scrubbers operate at high particulate removal efficiency, and the
consensus seems to be that venturi high-energy scrubbers are the only type of scrub-
ber that will give the desired performance.
The mechanism of particulate removal by a scrubber entails wetting the particle
by exposing it to a spray or mist and removing it from the gas stream. Contact of
137
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the particle with the scrubbing liquid is important, because the removal efficiency is
related to the number of droplets contacted and the energy imparted to them. Dust
particles can also act as condensing nuclei when a gas is cooled below its dew point.
Venturi scrubbers have high efficiencies because of the intimate contact between
the scrubbing liquid and the particulate. Water is sprayed into the throat of the
scrubber, where gas velocities are very high and the pressure drop may be as high as
1.27 m (50 in) of water gauge. The turbulence created by these conditions can result
in removal efficiencies of 99.8 percent on samples of dust smaller than 5 mm
(2xlO~4 in) in diameter. The high efficiency is not without its price, however; high-
energy scrubbers are, in most cases, considerably more expensive to operate than
baghouses.
Scrubbers have been proposed as a control device for several streams associated
with the Paraho process (Table 4-3).
TABLE 4-3. ESTIMATED PERFORMANCE OF THE SCRUBBER AS A
CONTROL TECHNIQUE FOR PARTICULATES
Type of
shale moisturizer
Directly heated
Indirectly heated
Combination
Uncontrolled
emission rate
(kg/hr)
4,105
4,384
4,175
Controlled
emission rate
(kg/hr)
41
44
42
Control
efficiency
(%)
99
99
99
Source: Reference 3
Electrostatic Precipitators—
Electrostatic precipitation is suitable for the collection of a wide range of dusts
and fumes, and electrostatic precipitators have been successfully employed in a
large number of industrial applications since the early 1900's. Electrostatic
precipitators are often favored because they are efficient, possess a low mainten-
ance characteristic, can handle large flow rates, require low pressure drop, and
generally have lower energy requirements.
The incoming gas stream is ionized by means of a high voltage corona discharge,
and the particles in the gas stream are, in turn, ionized by contact with the gas or
bombardment from the gas. The induced electric field causes the particles to
migrate to the electrode of opposite polarity, where they are neutralized. The dust
must be periodically removed from the collecting electrode to maintain maximum
collection efficiency, and usually a technique of rapping the plates with a striker is
employed. Care must be taken not to re-entrain all the dust that was previously
removed. The collected dust is then removed for disposal.
The application of electrostatic precipitators to the effluents from oil shale.
operations is not well defined at this time. It is expected, however, that they will be
employed as a control device on some aspects of oil shale processing. For example,
a "wet" electrostatic precipitator has been used for years at the Paraho demonstra-
tion plant for combined removal of condensed shale oil product and particulate.
Control of Gaseous Emissions
The gaseous emissions stipulated in the legislation pertain to sulfur dioxide,
nitrogen oxides, carbon monoxide, hydrocarbons, and photochemical oxidants.
Sulfur dioxide emissions were broadened to include hydrogen sulfide, since that is
the form from which much of the sulfur dioxide is generated.
Hydrogen Sulfide Removal Processes—
The sulfur content of oil shale can be as high as 7 percent by weight, but a more
138
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typical shale contains less than 1.0 percent. Normally this amount would be con-
sidered quite small, but the vast amount of oil shale rock that must be processed to
produce significant amounts of oil makes the release of sulfur an important prob-
lem. If (a) the yield of the shale is assumed to be 104 I/tonne (25 gal/ton), (b) the
size of the operation is assumed to be 50,000 bbl/day, and (c) the release of the
sulfur occurs as stated in A Preliminary Assessment of the Environmental Impacts
from Oil Shale Development, then up to 68.2 tonnes (75 tons) of sulfur in the form
of H2S could be generated each day (6). A potential emission of this magnitude
needs to be attenuated by an appropriate control technology. Some persons in the
oil shale industry feel that the hydrogen sulfide technology could be transferable
from other petroleum applications, and thus, they do not plan to conduct signifi-
cant research and development studies. The Environmental Protection Agency
does not totally dispute this claim, but would like to see the sulfur control
technologies successfully demonstrated before agreeing with the premise.
The Stretford Process—The Stretford process is a developed technology with
numerous plants in operation in the United States and Europe. The process was
developed for coal gas treatment but was found to be transferable to other
technologies as well. Hydrogen sulfide is dissolved in a mixture of sodium car-
bonate (Na2CO3), and sodium bicarbonate (NaHCO3) and the pH of the solution is
adjusted to a range of 8.5 to 9.5. The dissolved hydrogen sulfide is weakly ionized
(Ka, = 1.0x10"') and forms a small amount of hydrosulfide (HS~). The oxidation
of hydrosulfide was originally carried out with air, but the slow reaction kinetics
seriously influenced the applicability of the process. Therefore vanadium (V) and
sodium salts of anthraquinone disulfonic acid (ADA) were added to promote the
oxidation. The hydrosulfide (HS~) reacts rapidly with the vanadium, allowing the
equilibrium, to be pushed to the right.
H2S = H+ + HS- [1]
This shift allows more hydrogen sulfide to dissolve in the scrubbing solution, and
improves the removal efficiency. Hydrogen sulfide concentrations in the exhaust
gas of 100 ppmv are achievable with the Stretford Process. The overall oxidation-
reduction reaction for the process is:
2H2S + O2 = 2H2O + 2S [2]
A number of problems are associated with the chemistry of the Stretford scrubb-
ing solutions:
a. Carbon dioxide (CO2) is usually absorbed in alkaline systems and converted
to bicarbonates and carbonates. The Stretford process is no exception, and
carbon dioxide scrubbing can somewhat diminish the efficiency of hydrogen
sulfide removal.
b. Thiosulfate (S2O3) = can be formed in the regeneration cycle. Oxygen reacts
with the hydrosulfide (HS), forming thiosulfate. The higher the pH and
temperature, the higher the yield of thiosulfate.
c. Vanadium, oxygen, and sulfur complexes are formed if the concentration of
hydrosulfide is higher than the vanadate ion can oxidize. Potassium or
sodium tartrate has been used to repress this reaction.
d. The scrubbing solution can also be contaminated by gases containing sizable
amounts of tars or hydrocarbons. These compounds can cause foaming and
reduce the efficiency of the system, or even plug the reactor.
e. Hydrogen cyanide (HCN) is also collected by the Stretford system and that
reaction results in thiocyanates that cannot be regenerated. Large concentra-
tions of HCN could seriously affect the system's efficiency and economics.
f. The Stretford process will not remove carbon disulfide (CS2) and carbonyl
sulfide (COS) from the oil shale processing gas stream, and, if present, will
present a serious drawback to utilizing this technology. To date, however,
139
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neither compound has been found in sufficiently high concentrations to
preclude the use of the Stretford process on oil shale gaseous effluents.
The problems associated with the performance of the Stretford process can
usually be overcome by conscientious monitoring of the scrubbing solution. This
process has been selected by the developers for use in several of the planned oil
shale sulfur abatement programs.
The potential for the application of Stretford technology to the oil shale industry
can be seen by examining the data taken from Paraho's recycle gas. During the
retort's operating period, hydrogen sulfide samples were taken and those data were
summarized in Table 4-4. It shows that the concentration of hydrogen sulfide fluc-
tuated some but the average value of 1614 ppmv was well within the limits of the
process.
TABLE 4-4. CONCENTRATION OF H2S IN THE PARAHO RECYCLE GAS
Date of Test
5/75
5/75
8/75
1/76
3/76
1/77
10/77
11/77
1/78
Average
Institution
performing the test
Paraho
Gulf
LFE
Paraho
TRW
Paraho
TRW
Battelle-Northwest
Paraho
—
H2S
(ppm)
1,000
1,500
750-1,200
2,200
2,600
3,000
1,214-1,277
802-930
2,900
1,614
Source: Reference 7.
The average concentration is 1,614 ppmv H2S, which corresponds well with the
1,000 ppm reported by Colley et al. (8).
Union Oil Company has utilized the Stretford process in treating the off-gas
from a laboratory-sized retort and experienced some difficulties (9). Union found
that the sulfur produced by the process was contaminated by charred hydrocar-
bons, which made the resale value of the recovered sulfur low. Union also ex-
pressed an interest in the chemistry of the Stretford solution, indicating that they
were not entirely satisfied with the performance of the standard materials.
These problems notwithstanding, it is still believed that Stretford technology
should be applicable to the oil shale industry, but that the process might have to be
fine-tuned to fit the individual retorting process.
The economics of the Stretford process as applied to oil shale are unknown.
However, based on past experience and 1977 dollars, it is estimated that the invest-
ment costs would be $60 to $80/28.32 SCMD ($60 to $80/1000 SCFD) (1). The
operating costs of the system would vary with the purity and resale value of the
sulfur being recovered.
The Claus Process—This sulfur-removing process was pioneered in the 1880's
and is still practiced today with very little change. The basic reaction is:
2H2S + SO2 Bauxite Catalyst 3S + 2H2O [3]
After a thermal conversion step, hydrogen sulfide and sulfur dioxide are brought
together over a bauxite catalyst at a temperature of about 238° to 370 °C (400° to
700 °F). The chemical reaction as written in Equation [3] will occur with a conver-
sion rate of 65 to 85 percent. The lower the reaction temperature, the more effec-
tive the conversion.
140
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There are problem areas. Upon initial inspection, the process appears to solve
two pollution problems simultaneously and would seem to be an ideal control
technology for oil shale processing and retorting. However, the application of this
process to oil shale technology is not as straightforward as has been hoped, and
might require adjustment to each oil shale system.
The most important variable in the process is the ratio of hydrogen sulfide (H2S)
to sulfur dioxide (SO2) as they appear in-the gas stream at the catalytic converters.
If the stoichiometry is less than 2:1 (Equation [3]), the efficiency of the process is
significantly diminished, and sizable concentrations of hydrogen sulfide are emit-
ted from the converter.
The achievement of the desired concentrations of H2S and SO2 can also present
problems if the sulfurous feedstock consists of only one of the reactants. Under
these conditions, part of the feedstock requires oxidation or reduction before reac-
tion, and maintaining a ratio of 2:1 can be a problem. Because of the pyrolyzing
nature of the oil shale processes, the principal sulfur component of the retort off-
gas is hydrogen sulfide. However, the Claus Process, as routinely practiced in the
refining industry, includes a hydrogen sulfide and the feed stock to the unit can be
accurately controlled.
In addition to the proper stoichiometry, the feedstock to the Claus plant requires
relatively high concentrations of the sulfurous compounds. Research in this area
indicates that the minimum concentration for efficient operation of a Claus plant is
10 percent H2S (10). Data collected by Radian and Paraho indicate hydrogen
sulfide concentrations of about 5 percent and 0.16 percent for the indirect heating
mode of operation at the Paraho site (8). This figure is considerably less than
minimum estimate, and for a Claus plant to be applicable, a hydrogen sulfide
enricher (concentration step) would have to precede it in the treatment scheme.
This is common practice in the refining industry.
A third area of concern relative to utilizing Claus plants for oil shale effluent
treatment revolves around their reliability. The maintenance and downtime of the
units because of the corrosive nature of the sulfur and the gas, plus the plugging
problems resulting from condensed sulfur, necessitate back-up capability. Carbon
dioxide (CO2) is usually present in oil shale process gas, and unless it is removed,
CO2 can lead to the formation of carbonyl sulfide (COS). All of these operating
problems influence the economics of the Claus system in a negative way.
The end product of a Claus system is called a tail gas, and it usually contains
sizable concentrations of residual H2S. If incinerated, emissions of 1.0 to 3.0 per-
cent sulfur dioxide (SO2) are released. Concentrations as high as 0.3 percent would
violate most air standards; thus some form of additional tail gas treatment would
be necessary.
The sulfur produced by the Claus system has been rated higher in quality than
that produced by the Stretford process, but before this factor can be an asset, there
must be a market for the produced sulfur.
In summary, the application of a Claus plant to oil shale operations would de-
pend on the operating characteristics of the particular retorting process. If the 10
percent hydrogen sulfide concentration is the minimum required for economical
operation, and if the limited amount of published operating data is representative,
most oil shale plants would have to install some form of hydrogen sulfide enrich-
ment system upstream of the Claus plant, and tail gas treatment downstream.
Claus Plant Tail Gas Cleanup. The tail gas from a Claus plant usually contains
sizable concentrations of H2S and SO2. With sulfur emission regulations being
quite severe, especially in the oil shale area of Colorado, it is likely that the
developers would be required to treat the Claus plant effluent for the removal of
sulfurous compounds. Processes developed specifically for Claus plant tail gas
treatment (and their removal effectiveness) that may find some application in the
oil shale industry are SCOT (300 ppmv before incineration), Beavon (300 ppmv, no
141
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incineration), and the Institute Francais du Petrok (IFF) (2500 ppmv before in-
cineration).
The SCOT (Shell Glaus off-gas treating) process was designed specifically to
clean up the off-gas from a Claus Plant. The off-gas is heated with a reducing gas
or hydrogen, and the mixture is passed through a bed of cobalt-molybdate catalyst
where within equilibrium considerations all the compounds containing sulfur are
reduced to H2S. The H2S is routed to an absorber, where the gas is dissolved and
concentrated. Heat is applied to the absorbing solution, and the concentrated H2S
that is liberated from the absorbing medium is returned to the Claus plant.
Both the SCOT and the Beavon processes are adversely affected by high concen-
trations of CO2. Since oil shale gaseous emissions are projected to be rich in CO2,
additional operating constraints such as larger recycle gas streams, more fuel con-
sumption, and perhaps steam injection may be necessary.
In the Beavon process, the tail gas from the Claus plant is heated by mixing it
with hot combustion products of fuel gas and air. The mixture is passed through a
catalyst, where all the sulfur compounds are converted to H2S. The H2S-rich gas is
cooled by a slightly alkaline buffer solution and then treated by a Stretford unit.
The basic reaction used in the IFF process is the same as that used for the Claus
process, except that it occurs in a liquid phase rather than the gaseous phase. The li-
quid phase is composed of a polyalkylene glycol and a 5-percent by weight catalyst,
orthophthalic acid monopolyethylene glycol ester. Hydrogen sulfide (H2S) and
sulfur dioxide (SO2) are very soluble in this system and, if the operating parameters
are held at optimum conditions, efficient conversion to sulfur results. The most im-
portant operating variable, like the Claus plant, is that of the H2S/SO2 ratio, which
must be kept at or above 2:1. The IFF process has several advantages that could
make it attractive to the oil shale industry. First, the process shows flexibility in be-
ing able to accommodate wide changes in incident loading while being able to
maintain constant design conversion rates. Second, the gas can be treated at higher
temperatures than other processes, thus reducing the sensible heat loss.
As noted earlier, the ratio of H2S to SO2 is very important. If this ratio dips
below 2:1, the system can fail completely, requiring a complete replacement of the
scrubbing liquor.
Other Applicable Control Systems—Selexol and other physical absorption pro-
cesses are similar to the IFF system in that they are liquid-based, but they differ in
the fact that the hydrogen sulfide is desorbed essentially unchanged in these
systems.
Methanol was the initial solvent used, but it has given way to other solvents that
have been specifically designed for sulfur removal. Perhaps the most widely known
of these systems is Allied Chemical's Selexol solvent process. Dimethyl ether of
polyethylene glycol (DMEPG) is a solvent that can be used for the removal of acid
gases and for the selective absorption of H2S. The H2S can be desorbed and yield a
gas stream suitable for the Claus plant feed.
The physical absorption systems can also treat other undesirable gases generated
during oil shale retorting. Gases such as COS, CS2, mercaptan, and thiophene can
be dissolved, but they are not reduced to H2S, and they are not released during the
regeneration step. A buildup of these contaminants can adversely affect the effi-
ciency of operation, but today very little evidence has been presented to indicate
that any of the above pollutants are present in appreciable concentrations in retort
off-gases.
More than 40 selective solvent plants have been built, and it seems likely that the
direct application of this technology to oil shale emissions is possible.
Sulfur Dioxide Removal Processes—
The magnitude of the sulfur dioxide (SO2) emission problems depend on degree
of prior sulfur clean-up (H2S treatment) and the type of fuel used in the processing.
Most developers have planned to use desulfurized fuel to meet their heating and air
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pollution control needs, and therefore most of the sulfur emissions are generated in
the retorting of the shale. As stated earlier, the amount of sulfur liberated by the
processing of the shale can be significant, and treatment will probably be required.
A Claus plant can recover better than 95 percent of the hydrogen sulfide but a
sizable amount of sulfur dioxide (SO2) and H2S will also be liberated by the process
if tail gas processes are not used. The following technologies are presented to ad-
dress the problem of SO2 emission.
Wellman-Lord Process—The Wellman-Lord SO2 recovery process is a very ver-
satile technology and has enjoyed widespread acceptance among many industries
dealing with SO2 control. It is anticipated that the process will be adaptable to the
oil shale industry. This contention is supported by the fact that Colony planned to
use this SO2 treatment process on their emissions of tail gas after Claus (2).
The basic chemical reaction of the process involves the conversion of sulfite
(SO3)= to bisulfite (HSO3)~ and can be summarized in Equation [4]:
SO2 + Na2SO3 + H2O 2NaHSO3 [4]
The bisulfite solution is pumped to an evaporator and heated by steam. The
heating reverses the reaction and liberates a concentrated stream of SO2 that can be
used for making either sulfur or sulfuric acid. The sodium sulfite produced by
heating is dissolved and recirculated to the absorption column.
The Wellman-Lord process has a number of drawbacks that influence the
economics of the process. Oxidizing agents such as sulfur trioxide can oxidize the
sulfite (SO3)= to sulfate (SO4)= and reduce the efficiency of the process. It has
been suggested that these problems can be minimized by a prescrubber and by
treating a fraction of the absorbing solution for sulfate removal; but both add to
the costs of the process. Second, compared to other SO2 treatment systems, the
capital costs are higher, as are the energy requirements for everyday operation.
On the other hand, the Wellman-Lord process is considered to be a second-
generation SO2 removal process. The amount of sludge produced is considerably
less, and the scaling tendencies that occur under alkaline conditions have been
reduced. This SO2 process is considered to be an advanced technology transferable
to the oil shale industry with little additional research and development.
Citrate Process—The Bureau of Mines has developed an SO2 treatment process
for acid gases that seems to have a very promising application to the oil shale in-
dustry. Pilot-plant tests have been successfully carried out on gas containing 5000
ppmv of SO2 from a smelter and a coal-fired boiler.
Sodium citrate/citric acid is an excellent buffer system and maintains an op-
timum pH for SO2 absorption at 4.5. Sodium thiosulfate (Na2S2O3) is added to
facilitate the formation of the (SO2 - S2O3)= complex and improve the efficiency
of the system. Hydrogen sulfide is generated onsite and added to the system, with
the result being an in-solution reaction equivalent to a gas phase Claus reaction.
Hydrolysis of the dissolved sulfur dioxide yields HSO3", and the bisulfite reacts with
the H2S in the following reaction:
HSO3- + H+ + 2H2S — 3S + 3H2O [5]
The sulfur is separated by flotation, and the unreacted portion of the thiosulfate
absorbing solution is returned to the absorber. A natural consequence of the reac-
tion is the oxidation of thiosulfate (S2O3)~ to sulfate (SO4)=. To maintain acceptable
levels of thiosulfate, a portion of the absorbing solution is cooled to form a concen-
trated sulfate solution that eventually precipitates as Na2SO4'10H2O. The crystals
are removed by filtration, and the liquor is returned to the process.
The economics of the process are still undefined because of lack of data from
commercial-sized units, but it has been suggested that the costs will be competitive
with limestone scrubbing.
The application of this system to oil shale processes is very attractive. Previous
work had necessitated the onsite generation of H2S as one of the reactants.
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Estimates of many of the off-gases of the various oil shale processes already con-
tain this component in sufficient concentrations to sustain the reaction. It naturally
follows that if SO2 control is necessary, a portion of the retort off-gas could be
diverted, and both sulfur emission problems could be handled simultaneously.
Alkali Scrubbing—Lime/Limestone Scrubbing. The oldest and probably best
known of the alkali scrubbing systems is limestone process. A nonregenerative
slurry of 5 to 10 percent of calcium oxide or carbonate is circulated through a
scrubber, wherein the slurry contacts the flue gas and removes the SO2 as calcium
sulfite or sulfate. Although the process has been studied in great detail for over 30
years, the chemical reactions occurring in the carbonate slurry are still not com-
pletely defined. Basically, the reactions involve the absorption of SO2, hydrolysis
to sulfurous acid (H2SO3, Ka = l.TxlO'2), ionization to sulfite (HSO3)', and reac-
tion with calcium to form calcium sulfite (CaSO3) and calcium sulfate (CaSO4).
It has been suggested that because of the lack of predictability of the limestone
scrubbing chemistry and the effect of different flue gas characteristics, results of
pilot-scale activities are required for each new potential application. Oil shale
operations would fall into this category, and it might be anticipated that each proc-
ess would need to be evaluated individually before limestone scrubbing could be
optimized.
In operations where the heat content of the product gas is low or where it is
decided not to utilize its heat content, gas combustion followed by alkali scrubbing
may be the best economic solution to the sulfur dioxide emission problem. Best
estimates by the utilities is that limestone slurry scrubbing will cost $50 to $70/kw
to install and 3.9 to 5.5 mills/kw-hr to operate (11). These costs may be difficult to
translate into costs for the oil shale industry, but the fact that they are the lowest of
the competing SO2 removal processes is of primary importance.
Regardless of how advanced the alkali scrubbing technology has become, it is
not without its problems. The question of the system's reliability has surfaced on
more than one occasion, but recent successful tests have helped to reduce this
criticism. However, the problem of large volumes of scrubber sludge has not been
resolved .
Dual Alkali. The Dual Alkali process, as the name suggests, is a system that in-
corporates several alkaline compounds for scrubbing sulfur dioxide out of stack
gases. The process has several potential advantages over the conventional lime
slurry scrubbers. Higher reliability coupled with lower maintenance and improved
sludge characteristics and capital costs are the features that could make it attractive
to the oil shale industry for sulfur dioxide removal.
The process uses sodium hydroxide (NaOH) and sodium sulfite (Na2SO3) to ab-
sorb the SO2 from the gas and convert it to sodium bisulfite (NaHSO3). The
scrubbed gases pass on to the stack, and the scrubbing solution is circulated to the
regeneration tank. Calcium is added in the form of lime or limestone and reacts
with the bisulfite to regenerate sodium hydroxide and sodium sulfite. The
precipitated calcium solids are removed in a clarifier.
The costs of the double alkali systems are difficult to estimate for the oil shale in-
dustry and can only be compared to other industrial applications and utilities.
Green (12) has estimated the capital costs of the double alkali systems at $86.87 to
$819.31/cmm ($2.46 to $23.2/cfm) for industrial applications and $43.2 to
$189.0/kW for electric utilities. The operating costs were also reported as 5.5 to 6.5
mills/kWh.
The environmental aspects of the sludge handling problems are not as severe
with double alkali as with limestone scrubbing; however, the volume of sludge is
still significant and could cause problems if not handled properly.
Magnesium Oxide. The magnesium oxide process is similar to other alkaline flue
gas desulfurization processes in that the reaction products are bisulfite and sulfate.
The process is different in that the magnesium oxide used for the scrubbing solu-
tion has a higher affinity for SO2 than lime, and the process is regenerable.
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Magnesium oxide hydrolyzes to form magnesium hydroxide, Mg(OH)2, and the
hydroxide (OH)~ reacts with the SO2 to form magnesium sulfite (MgSO2) or sulfate
(MgSO4). Both reaction products have a low solubility and can be easily crystalized
out of solution. The magnesium sulfite/sulfate is routed to a regeneration calciner,
where heat and coke (a reducing agent) are added. The desulfurization reaction is
reversed, and a concentrated stream of SO2 (10 to 20 percent) is liberated. The gas
can be made into sulfuric acid or sulfur, and the calcined magnesium (MgO) is
returned to the make-up slurry.
Philadelphia Electric has reported capital costs for a magnesium oxide system on
a 120-MW boiler at $90/kW and operating costs at 4.7 mills/kWh (13).
The main environmental problems deal with the manufacture of sulfuric acid
and the process byproducts.
Nahcolite Ore—Nahcolite is a naturally occurring mineral that contains 70 to 90
percent sodium bicarbonate. If the bicarbonate is subjected to heat, carbon dioxide
is driven off and the remaining sodium carbonate (Na2CO3) is available for reaction
with sulfur dioxide.
There are several important implications of sulfur dioxide control by nahcolite
that should be investigated by the oil shale industry. First and most important is
that sizable amounts of nahcolite are available near some of the oil shale deposits,
and this resource could offer an economic advantage to the sulfur control strategy
for that oil shale process. A second advantage of the system is that the nahcolite is
injected dry, and the water pollution problems are thereby minimized. A third plus
for the system is its simplicity. The simpler a control system, the smaller the capital,
operating, and maintenance costs, generally.
To date, operations of the nahcolite system have been carried out on a small
scale, and the results should be viewed in that light. Preliminary data indicate that
capital and operating costs may be lower than limestone scrubbing.
NOX Control—
Oxides of nitrogen are a natural product of the combustion of conventional
fuels, and they are expected to be a significant air pollution emission relative to oil
shale development. The emission of these substances contributes to secondary
chemical reactions in the atmosphere that result in the formation of photochemical
oxidants. In addition, the emissions themselves are undesirable from a
physiological point of view.
When compared to ordinary laboratory conditions, the requirements for NOX
formation are very severe. Temperatures in excess of 980 °C (1,800 °F) are needed to
supply the endothermic energy necessary to break the nitrogen to nitrogen triple
bond (225 kcal). However, the conditions experienced by reactants in or near a
flame are very extraordinary, and sufficient energy is available to rupture the
nitrogen molecule. Unburned oxygen also experiences these conditions, and when
the two gases are in proximity in the flame, they will form NOX according to the
equation:
N2 + O2 =^ 2NO [6]
Control of the NOX problem is similar to the sulfur problem in that it can be ap-
proached in several ways. If combustion conditions can be properly controlled, the
amount of nitrogen and/or oxygen available for reaction can be minimized, and
the amount of NOX produced can be kept to a minimum. A second option would
be to disregard combustion conditions and clean up the off-gases.
It is common knowledge that engineering solutions designed to minimize an air
pollution problem at the source are more effective than retrofitting control devices
to a particular process. The oil shale industry is still in the pilot-plant phase of most
of its systems and it is still in a position to design low furnace emissions of NOX into
commercial-scale units. In the future, if the need arises for additional NOX control,
appropriate retrofit control systems could be added.
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The following discussion centers on combustion modifications and control
technologies for NOX abatement.
Combustion Modifications. Several approaches exist to modifying the combus-
tion conditions to result in lower emissions of oxides of nitrogen. The specific
design of a combustion chamber can greatly influence the amount of NOX formed.
The tighter the burning pattern, the more intense the heat flux and the greater op-
portunity for oxides of nitrogen to be formed. In general, it has also been found
that the more turbulent the combustion conditions, the higher the NOX emissions.
Research has been undertaken to minimize the NOX emissions, but in most cases, it
has resulted in lower combustion efficiency.
Two-Stage Combustion. To address the problem of combustion efficiency and
NOX emissions, a two-stage burning system was developed. In the first stage, only
85 to 95 percent of the stoichiometric air needed for combustion was supplied. The
remaining air was injected above the burners to complete the combustion. Systems
of this type have reduced NOX emissions by about 50 percent.
Tangential Firing. As stated earlier, the interaction between closely-spaced
burners tends to elevate the NOX emissions. Tangential firing removes some of the
burner proximity, and firing is carried out on a tangent to a circle at the center of
the furnace. The result is less flame interaction, more radiant heat transfer to the
cooling surface, and lower concentrations of NOX produced.
Flue Gas Recirculation. Flue gas recirculation has been applied to combustion
sources for NOX reduction. The gas has some sensible heat associated with it and
does not quench the reaction temperature as dramatically as excess air thereby
allowing the kinetics of the formation reaction to be reversed toward molecular
nitrogen and oxygen. The recirculated gases are lower in oxygen than excess air and
present less of the reactant necessary for the formation of NOX. There are,
however, some problems with flame stability, which have limited the application of
this technique to NOX reduction.
Fuel Modifications. In addition to atmospheric nitrogen, fuel-bound nitrogen
can be a major contributor to the NOX problem. Any fuel burned onsite should be
of such quality as to assure low oxides of nitrogen emissions. Some operators have
suggested the use of a portion of the shale oil as a fuel in the process itself. If this
option is exercised, pretreatment of the oil should be done to reduce the high levels
of nitrogen contained in the shale oil.
Low NOX Burners. Low NOX burners have reduced the thermal and fuel-derived
NOX emissions by various methods. One method employs a thin flame and good
mixing to promote rapid combustion, thereby reducing levels of NOX. A second
method utilizes an internal recirculation of the combustion gases to reduce NOX
emissions, and a third method uses stratified combustion. The combination of one
or more of these techniques is usually employed in the low NOX burners available
on the market today. The performance of these units usually results in NOX emis-
sions low enough to be in compliance with the air pollution regulations, but data
from operating experience are limited.
Control Technologies. If sizable quantities of NOX are formed as a result of
combustion or processing of oil shale, removing them by some form of add-on
NOX control technology could be a reasonable alternative. To date, however, very
little has been done in this area, because it is generally believed that NOX emissions
are not going to be a very significant problem. It may be possible to combine NOX
abatement with SO2 control, and it seems logical, from a presumed cost-effective
viewpoint, that the problem should and could be approached in this manner.
Limestone Scrubbing. The limestone slurry employed for SO2 control will also
remove NO2 or an equimolar mixture of NO/NO2 from flue gases. The process is
the same as outlined for alkaline scrubbing of sulfur dioxide, except that an addi-
tional end product, calcium nitrate, is quite soluble in solution and will build up.
Work done at Wisconsin Electric's Oak Creek power plant (12) indicated about a
20-percent reduction in NOX emissions using limestone slurry scrubbing.
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Chiyoda Thoroughbred 102 Process. The Chiyoda Thoroughbred 102 process
utilizes ozone to oxidize NOX to NO2 and thereby enhances its absorptive proper-
ties. After oxidation, the flue gas is introduced into a packed tower and treated
with dilute sulfuric acid containing a ferric catalyst. Pilot-plant studies have in-
dicated NOX removal efficiencies of 60 percent. Again, the build-up of calcium
nitrate could be an operational problem.
Selective Catalytic Reduction Processes. Several nitrogen oxide processes have
been developed by the Japanese for the selective reduction of NOX. The Kurabo
process mixes the flue gas with ammonia and reacts the mixture over a bed of cop-
per and alumina. Pilot-plant data indicate about a 90 percent conversion of NOX to
N2. The Hitachi shipbuilding process and the Sumitomo process both use ammonia
injection and subsequent reduction over a metal catalyst. Based on experience with
these systems, a number of very large denitrification plants are being built.
Air Emission Controls for Hydrocarbons and Carbon Monoxide—Prepared for
Dale Denny and Bruce Tichenor by Radian Corporation
This section describes hydrocarbon and carbon monoxide emission control
technologies that are currently applied to distillation, cracking, and other process
sources in natural crude oil refining and that might be applied in oil shale retorting
or shale oil refining. The four basic approaches to hydrocarbon and carbon
monoxide control that are discussed here include: destruction, recovery and recy-
cling, containment, and conversion.
Direct flame incineration and catalytic incineration are two methods of control
by destruction. These control techniques are applicable for combustible hydrocar-
bons that do not have a high recovered product market value, or that are too dilute
to be economically recovered. The recovery and recycling control technologies in-
clude compression-condensation, condensation, and adsorption systems. Each of
these systems allows recovery of the controlled hydrocarbons; they are most
economical for hydrocarbons with a high market value. The third approach to
hydrocarbon control is vapor containment, the principle behind adsorption
systems. In adsorption systems, hydrocarbon emissions are trapped on the surface
of an adsorbent such as activated carbon. These adsorbed hydrocarbons must later
be removed or recovered by one of the other hydrocarbon emission control
technologies. The last approach, conversion, involves utilizing the shift conversion
process to react carbon monoxide with steam to form carbon dioxide and
hydrogen.
In addition to the above control technologies, fugitive emission controls are also
discussed.
Direct Flame Incineration—Emission control by direct flame incineration (also
termed thermal combustion) is widely used to control combustible gaseous
materials such as hydrocarbon vapors, aerosols, and particulates. These systems
are also used extensively in removing odors and in reducing the opacity of visible
plumes from ovens, dryers, stills, cookers, and refuse incinerators. The principle of
operation consists of ducting the exhaust process gases to a combustion chamber
that employs direct-fired burners to combust the process gases to their appropriate
oxides. A well-designed plant flare system is a good example of control by direct in-
cineration.
In direct flame incinerators, the combustible process gases are delivered to a
refractory-lined incinerator by either the process exhaust system or by a self-
contained blower. If the process gases do not have a sufficient heating value to sus-
tain combustion, a metered fuel stream is combined with a portion of the process
gases in the burner and then allowed to combust in the combustion zone. If the
process gases have a high heating value, air must often be introduced at the burner
instead of fuel. The remaining process gases are then introduced into the mixing
zone where they are combusted. For maximum destruction of contaminants, the
combusted gases are retained briefly in a reaction zone where additional oxidation
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occurs before being vented to the atmosphere. When sized and operating properly,
most direct-flame incinerators will obtain 99 + percent destruction of hydrocarbon
compounds. Most units are sized to operate at efficiencies between 95 and 99 per-
cent.
Many components in the process gas stream form hazardous combustion prod-
ucts such as nitrogen oxides, sulfur oxides, hydrogen chloride, hydrogen fluoride,
trace elements, and particulates. When required, the most common means of con-
trolling these secondary pollutants is aqueous solution scrubbing. Noise can also be
a problem in high turbulence incinerators and is normally reduced through the ap-
plication of standard acoustical technology.
Catalytic Incineration—Catalytic incineration is a widely used alternative to
direct flame combustion for the control of combustible gaseous materials such as
hydrocarbon vapors and aerosols. These systems are also used extensively in
removing odors and in reducing the opacity of visible plumes from ovens, dryers,
stills, cookers, and refuse incinerators. The principle of operation consists of duct-
ing exiting process gases to an incineration chamber filled with a catalyst. Upon
contact with the catalyst, the selected components of the process gases are oxi-
dized. The use of a catalyst allows more complete combustion at lower
temperature, resulting in lower fuel costs and more economic materials of
construction. However, catalysts are generally selective and may not destroy as
many components of the process gases as direct flame incineration. In addition,
because of catalyst fouling and poisoning, pollutants must be free of smoke, par-
ticulates, and heavy metals and other catalyst poisons.
When sized and operated properly, catalytic incinerators will obtain 95 to 99 +
percent destruction of selected compounds. Many catalysts are highly selective as
to the reactions they promote. Although relatively reliable and simple to operate,
catalytic incinerators are more complex than direct flame incinerators. Accurate,
dependable fuel and/or air controllers are required to maintain close control of
catalyst bed temperature in the midst of highly variable process gas heating values
and flow rates. Catalyst beds are also highly susceptible to fouling and poisoning
by halogens, heavy metals, and sulfur species. As a result, catalyst beds must be
routinely cleaned and eventually replaced.
As in direct incineration, aqueous scrubbing may be required to remove secon-
dary pollutants resulting from combustion. Likewise, standard acoustical
technology may be required in high turbulence incineration.
Compression/Condensation—Compression/condensation systems are desirable
for recovering concentrated hydrocarbon vapors from relatively small gas streams.
The compression/refrigeration/absorption (CRA) recovery system is based on the
absorption and condensation of compressed hydrocarbon vapors with cool liquid
from storage. Compression/refrigeration/condensation (CRC) vapor recovery
systems are based on the condensation of hydrocarbon vapors by compression and
refrigeration.
In both systems, incoming vapors are first passed through a saturator, where
they are sprayed with fuel to insure that the hydrocarbon concentration of the
vapors is above the explosive limit. This step is performed as a safety measure to
reduce the hazards of compressing hydrocarbon vapors. The saturated vapors are
then compressed and passed through a condenser or heat exchanger. In the CRC
system, most of the hydrocarbons are condensed in a condenser. Essentially
hydrocarbon-free air is vented from the top of the condenser. In the CRA system,
the compressed vapors are cooled in a heat exchanger before entering an absorber.
In the absorber, the cooled vapors are contacted with chilled liquid product drawn
from storage and are condensed and absorbed into the liquid. The remaining air,
containing only a small amount of hydrocarbons, is vented from the top of the ab-
sorber.
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The vapor collection efficiencies of both CRA and CRC systems are dependent
on the inlet hydrocarbon concentration. Current CRA systems can surpass 90 per-
cent recovery for inlet hydrocarbon concentrations of greater than 20 percent by
volume. The CRC units can recover 96 percent of the hydrocarbons in saturated
gasoline vapors, and 88 to 90 percent in subsaturated gasoline vapors.
No secondary pollutants are generated, but vent streams from a compres-
sion/condensation system may require incineration.
Condensation—Condensation is usually applied in combination with other air
pollution control systems. Condensers located upstream of afterburners, carbon
beds, or absorbers can reduce the total load entering the more expensive control
equipment. When used alone, condensation often requires costly refrigeration to
achieve the low temperatures needed for adequate control.
Condensers employ several methods for cooling the vapor. In surface con-
densers, the coolant does not contact the vapor or condensate; condensation occurs
on a wall separating the coolant and the vapor. Most surface condensers are com-
mon shell-and-tube heat exchangers. The coolant normally flows through the
tubes, and the vapor condenses on the outside tube surface. The condensed vapor
forms a film on the cool tube and drains away to storage or disposal.
Contact condensers usually cool the vapor by spraying a liquid at ambient
temperature or slightly cooler directly into the gas stream. Contact condensers also
act as scrubbers in removing vapors that normally do not condense. The use of
quench water as the cooling medium results in a waste stream that must be con-
tained and treated before discharge.
Equipment used for contact condensation includes simple spray towers, high-
velocity jets, and barometric condensers. Contact condensers are generally less ex-
pensive, more flexible, and more efficient in removing organic vapors than surface
condensers. On the other hand, surface condensers recover marketable condensate
and present no waste disposal problem. Surface condensers require more auxiliary
equipment and have greater maintenance requirements.
Condensers have been widely used (usually with additional control equipment) in
controlling organic emissions from petroleum refining, petrochemical manufac-
turing, dry cleaning, degreasing, and tar dipping. Condensation processes with
significant refrigeration requirements are being used for the recovery of gasoline
vapors at bulk gasoline terminals and service stations.
Control effectiveness depends on hydrocarbon contaminants and condenser
operating parameters. In the removal of gasoline from saturated vapors, removals
of about 99 percent can be obtained. Efficiencies for recovering heavy hydrocar-
bons with nonrefrigerated condensers can exceed 99 percent.
Secondary environmental problems include the disposal of noncondensibles and
the treatment of the liquid effluent from contact condensers. The noncondensible
gas effluent can be vented to the atmosphere or further processed (e.g., in-
cinerated), depending on the effluent composition. The liquid effluent from con-
tact condensers must be treated or separated before disposal or reuse.
Absorption—Absorption is the process by which certain constituents of a gas
stream are selectively transferred to a liquid solvent. Absorption may be purely
physical, with the solute simply dissolving in the absorbent, or it may be chemical,
with the solute chemically reacting with the absorbent or with reagents dissolved in
the absorbent. Typical absorption equipment includes plate towers, packed towers,
spray towers, and venturi scrubbers. After absorption, the vapor-laden absorbent
may be regenerated, used as make-up to nearby processes, or disposed. The most
common absorbents used for the removal of hydrocarbons are nonvolatile
petroleum liquids ("lean oils")- Other commonly used absorbents are water and
aqueous solutions of oxidizing agents, sodium carbonate, or sodium hydroxide.
Several lean oil absorption systems are in service at pipeline terminals for the
control of loading emissions. These systems treat gas flows of less than 0.5 mVsec
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(1,000 scfm). Absorption is quite commonly used in petroleum and petrochemical
operations for treating gas streams with relatively high concentrations of organic
vapors. Organic vapors removed include alcohols, ketones, amines, glycols,
aldehydes, phenols, organic acids, and light hydrocarbons.
Control effectiveness depends on inlet hydrocarbon concentration. Lean oil ab-
sorption systems routinely achieve removal efficiencies in excess of 95 percent for
inlet hydrocarbon concentrations of 24 percent or greater. Lean oil absorbers have
little impact on methane. Higher removal efficiencies are achieved with larger oil
flow rates attained at greater cost.
Secondary emissions depend on the fate of the solute-laden absorbent. If the ab-
sorbent is regenerated, a regeneration gas is produced that consists of the stripped
solute and the stripping gas (usually steam or air). If this regeneration gas stream is
incinerated, hazardous combustion products may be produced. If the stripped
vapors are condensed, the condensate may pose a liquid disposal problem. If the
solute-laden absorbent is simply disposed, further treatment or neutralization is re-
quired. Another secondary pollutant is absorbent carried into the "clean" exit gas.
Adsorption—Adsorption is the process by which components of a gas are re-
tained on the surface of granular solids. The solid adsorbent particles are highly
porous and have a very large surface-to-volume ratio. Gas molecules penetrate
pores of the material and contact the large surface area available for adsorption.
Vapors retained on the adsorbent are subsequently desorbed. Both the vapors and
the adsorbent can be recovered for reuse.
Activated carbon is the most widely used adsorbent because it can selectively ad-
sorb hydrocarbons from gases even in the presence of water. Because of their
strong affinity for water, other adsorbents such as silica gel, activated alumina, and
molecular sieves are better suited for the treatment of "dry" gases. Soda lime alone
or combined with activated carbon has also been used to adsorb certain hydrocar-
bon vapors.
After completion of the adsorption cycle, the used adsorbent may be either
regenerated or replaced. Regenerative systems reactivate the adsorbent by desorb-
ing the adsorbed vapors. The desorbed vapors may then be reused or disposed.
Nonregenerative systems usually return the used adsorbent to the vendor for
regeneration. The adsorbent is most commonly regenerated by steam stripping,
although air stripping and vacuum stripping are also used. The steam and pollutant
vapors may then be directly incinerated or routed to a condenser, after which they
can be separated by gravity decantation or by distillation. Although two-unit ad-
sorber systems have been proven efficient, a third unit may be desirable to allow a
freshly regenerated bed to cool after steam stripping.
Adsorption is highly efficient (in excess of 99 percent) in removing hydrocar-
bons. The process is technically feasible for controlling hydrocarbon emissions
from: (a) tail gases from sulfur recovery processes, (b) streams produced in the
regeneration of acid gas removal systems or, (c) other waste streams containing
hydrocarbons. However, adsorption is normally used for treating streams of low •
hydrocarbon concentrations. Particulates and condensibles must be removed in a
pretreatment step.
Secondary pollutants arise during gas pretreatment and regeneration. Par-
ticulates and condensibles in the inlet gas to the adsorber must be removed in a
pretreatment step; the removed particulates and condensibles must then be safely
disposed. Regeneration gases typically consist of steam, nitrogen, oxygen, and
desorbed vapors. If the regeneration gas stream is incinerated, hazardous combus-
tion products may be produced. If the steam and vapors are recovered by conden-
sation and separation, the water stream may require further treatment because of
the presence of soluble hydrocarbons.
Shift Conversion—In the shift conversion process, steam is reacted with carbon
monoxide to form carbon dioxide and hydrogen. This endothermic process is con-
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ducted in a fixed-bed catalytic reactor. External cooling is usually employed be-
tween multiple catalyst beds to maintain an optimal temperature range for the
equilibrium conversion. Excess carbon dioxide formed in the shift conversion proc-
ess can be separated and vented to the atmosphere.
The shift conversion process is used to remove carbon monoxide formed during
steam reforming or partial oxidation methods for hydrogen production; it is also
used to remove carbon monoxide from acid-gas streams. It would be applied when
CO emissions were high enough to make it cost effective.
There are no secondary pollutants from the shift conversion process. However,
if the chromium/iron oxide catalyst used in the shift conversion is regenerated
rather than sent to disposal or metal recovery, impurities that blind or poison the
catalysts may be released to the atmosphere. The most likely types of con-
taminants, in addition to hydrocarbons, will be trace elements such as nickel,
vanadium, iron, arsenic, and selenium, which may be present in the feedstock
gases.
Fugitive Emissions—In contrast to the previous air pollutant categories, which
are classified by pollutant type, fugitive emissions are defined by their origins.
Fugitive hydrocarbon emissions have two principal sources: leaks and evapora-
tion from open surfaces. Unlike fugitive dust, which arises in a diffuse pattern over
an area, many fugitive hydrocarbon losses occur from specific points, such as
valves, flanges, pump seals, compressor seals, and drains. However, these sources
are so numerous in most plants processing hydrocarbon liquids that the emissions
can be considered diffuse for practical purposes.
Fugitive emission controls are primarily based on good plant design and
maintenance procedures rather than equipment. Plant design items that help
reduce fugitive emissions include:
Confinement, diversion, and flaring
Dual seals
Sparing of critical pumps, compressors, and valves
Use of surface condensers rather than direct-contact units (barometric or low-
level jet)
Probably the most important item in preventing fugitive emissions is the institu-
tion of a good preventive maintenance program. Such a program would include
making use of outages and normal downtimes for repairing and testing potential
fugitive emission sources on a systematic basis.
WASTEWATER TREATMENT CONTROLS
Thomas Powers
The chief EPA concern about environmental control technology for oil shale
wastewaters is that the environment be protected by the best practicable methods
available at the time of implementation. Water sources, their quantities and
characteristics, water uses, wastewater treatments particularly for reuse, and final
water disposal alternatives must be considered to arrive at an optimum environ-
mental control system for each process facility.
Existing water pollution control technology may be applicable to most of the
waste streams encountered in oil shale processing. However, several of the more
highly polluted wastewaters will require research on process methodology to ensure
that priority pollutants and toxics are removed to ensure safe reuse or discharge.
Process wastewaters, spent shale compaction wastewaters. and mine dewatering
wastewaters may pose significant problems that will have to be resolved before
commercialization by the industry. The data used in this evaluation of treatment
controls for the oil shale industry are based on oil shale process pilot-plant studies
and projections by developers.
151
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Water pollution problems at a specific site will depend on the oil recovery proc-
ess used, the quality and quantity of available raw water, and final reuse or disposal
objectives. Figure 4-1 shows a generalized water flow and options.
WATER
USES
WASTEWATER
TREATMENT
FINAL
MATER DISPOSAL
Surface — »•
Water
Water
Water
Runoff »•
Water
Treatment
Water '
Treatment
Water
Treatment
h*i
».
— Dust Control »>
i — Mining Applications »>
— Power Generation ^
— Potable --^
— Fire Protection *•
— Sanitary »•
— Process (retort) »•
RECYCLE
*l
[*
Treatment |~
Treatment [~
Wastewater
Treatment
Wastewater
Treatment
-*•
•»
-*. water Reinjection
Into Aquifer
-*• Injection Into
In Situ Retort
Stream
Pond
-»• Grouting
-^ Spray •*
Leachate
And Storm
Runoff 1
-^ Spent Shale^ .
Compaction
-^ Revegetation
Leachate And
Storm Runoff 1
Figure 4-1. Oil shale water and wastewater utilization.
For treatment, options must be designed to produce water acceptable for use in
the process (recycled wastewater) or water acceptable for discharge, or both.
Typical techniques available for this application are as follows:
Biological:
Activated Sludge
Trickling Filter-Rotating
Biological Contactor
Aerated Lagoons
Oxidation Ponds
Anaerobic Filters
Physical:
Sedimentation
Flotation
Filtration-Microscreening
Ammonia Stripping
Evaporation Ponds
Carbon Adsorption
Chemical:
Ion Exchange
Coagulation
Oxidation-Reduction
-Ozonation
Wastewater Treatment Methods
As additional data on waste streams become available, it will be possible to
determine the optimum process for a specific application. In some cases, it may
also be necessary to apply tertiary methods for the removal of refractory organics,
residual nutrients, trace metals, dissolved solids, or trace quantities of organics that
present a problem in either reuse or discharge of the wastewater. Tertiary methods
may play a role in permitting maximum utilization and minimum discharge of
water by the oil shale industry.
152
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Wastewater Sources, Quantities, and Characteristics
The utilization of water and wastewater for oil shale development is forecast as a
complex problem. The optimum system would be one with a zero discharge, that is,
total recycling. To project such a system applying these principles to each oil shale
process, it is necessary to identify and quantify the raw water supply and aqueous
wastes from oil shale processes. The major wastewater streams from oil shale proc-
essing are summarized in Table 4-5.
Process Wastewaters from Retorting Operations—
Process wastewaters have been classically defined by EPA as . . ."any water
which, during manufacturing or processing, comes into direct contact with or
results from the production or use of any raw material, intermediate product,
finished product, by-product or waste product" (15). The term "process
wastewater pollutants" means pollutants present in process wastewater.
The characteristics of wastewaters produced during retorting (Operations la
through li in Table 4-5) vary considerably. Retort wastewaters can, however, be
generally characterized by the use of water quality parameters (as in Table 4-6),
organics content (Table 4-7), and trace element content (Tables 4-8 and 4-9). The
quantities of the constituents listed in Tables 4-6 through 4-9 are the determining
factors in the choice of treatment method or methods used to achieve water quality
design.
Shale Oil Upgrading Wastewaters—
Oil cooling wastewater (2a through 2e in Table 4-5), upgrading process
wastewater (2f through 2i), and wash waters (2j through 2m) constitute the major
process discharges from upgrading operations that convert shale oils to refined
products. Except for the rates given in Table 4-5, little information is available on
oily cooling wastewaters and upgrading process wastewaters. At present, Union
plans to process the sour water stream in the ammonia separation unit for the
removal of light hydrocarbons by degassing and the removal of hydrogen sulfide
and ammonia by stripping. Wastewater reuse is forecast by other developers as well
and will ultimately be demonstrated on full-scale facilities. Portions of the sour
water have been characterized, but information is generally not available as to the
specific trace organics and toxic substances that could be present to cause prob-
lems.
Regarding the characteristics of wash wastewaters, the Union Oil Co. has
estimated the generation rates of some constituents in boiler blowdown for a
50,000-bbl/stream day crude shale oil plant (Table 4-10) (26).
The Union Oil Co. has also described the characteristics of wastewater from
backwashing and water rinsing operations upstream of treatment for boiler feed-
water by ion exchange (Table 4-11) and the characteristics of wastewater from
regeneration of ion exchange resins (Table 4-12) for a 50,000-bbl/stream day plant
(26).
Wastewater from Process Gas Cleaning and Air Pollution Control—
Air pollution control technologies are expected to use water for removing
pollutants from the air. Examples of similar wet collection devices are numerous in
industrial applications. Mining dust control, retort gas cleaning, tail gas cleanup
and foul water stripping operations generate major waste streams (3a through 5b in
Table 4-5). Major constituents in such waters include shale dust particulates,
hydrocarbons, H2S, NH3, phenols, organic acids and amines, thiosulfate, and thio-
cyanate. Quantities of wastewater anticipated have been estimated in several cases
(2). Data are not complete, however, on the quantity and quality of water required
for air pollution control devices to be utilized in the developing oil shale industry.
Air scrubbers, elutriation scrubbers, moisturizer scrubbers, and ammonia recovery
units are anticipated as principal sources of wastewater.
153
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TABLE 4-5. UTILIZATION OF WATER AND WASTEWATER FOR OIL
SHALE DEVELOPMENT8
Water use
Barrels of water per barrel of shale oil
Requirement Consumption Discharge
Total utilization (for surface retorts)b 3.776 to 4.38
1. Process —
(a) Retort pyrolysis water —
(b) Combustion of organics —
(c) Dehydration of minerals —
(d) Groundwater fin situ) —
(e) Coker steam condensate —
(f) Product gas cooling condensate —
(g) Pyrolysis steam condensate —
(h) Oil storage —
(i) Product gas cleaning (retort) —
2. Upgrading shale oil (hydrogenation) —
Oily cooling wastewaters —
(a) Quenching —
(b) Vessel cleanout —
(c) Spills cleanup —
(d) Coker blowdown —
(e) Process steam condensation —
Process wastewaters —
(f) Stripping condensed steam —
(g) Drum cleaning wash water —
(h) Chemical reaction wastewaters —
(i) Spent caustic streams —
Wash wastewaters —
(j) Plant storm water runoff —
(k) Hydraulic decoking —
(I) Steam boiler bloxdown —
(m) Boiler feedwater treatment
blowdown —
Backwashing and water rinse —
Regeneration —
3. Air control and gas cleaning —
(a) Ammonia —
(b) Moisturizer scrubber —
(c) Elutriation scrubber —
(d) Gas cleaning (upgrading) —
4. Dust control —
(a) Shale ash —
(b) Scrubber —
5. Mine applications (dewatering) —
(a) Dust control —
(b) Crushing —
6. Power generation blowdowns —
7. Cooling, non-contact 1.3
8. Potable and fire water protection 0.18
9. Sanitary —
10. Revegetation —
11. Moisturized spent shale runoff —
12. Storm water runoff —
13. Spent shale leachate —
14. Spray irrigation leachate and runoff —
2.85 to 2.88 0.926 to 1.5
0.25 to 0.31c 1.5to22d
- 0.103 to 0.120
- 0.192 to 0.32
- 1 to 22d
- 0.021
- 0.151
0.151
- 0.06
- 0.123
0.62 to 0.93 0.629
0.72 0.170
0.007
0.335
0.124
0.21
0.343
0.171
0.452
c
0.24
0.15
0.63
0.69
0.12
0.048 to 0.3
0.925to 1.87
0.05
0.025
0.03
0.019
0.205
0.017
0.027
0.038
0.123
0.490
1.0 to 6.8-8.3
0.02 to 0.089
0.20 to 0.25
0.03 to 0.069
0.0 to 0.02
Variable
Variable
Variable
a Data from References 2, 5 and 16 through 29.
The "Total utilization" figures are those reported by certain surface developers as their combined, lump-sum, water
flow rates; the individual unit-process wastestream rates shown come from a variety of other data sources, some from
in situ operations. Consequently, the sum of the individual rates do not equal the total rate. It must be noted that many
sources of water utilization are shown for illustrative purposes only.
c Union estimates 2.12 barrels water/barrel oil consumption for all uses; mining, crushing, retorting, shale cooling,
leaching revegetation, sanitary, etc in a 10,000 TPD experimental plant.
° Upper level of this range is a result of groundwater infiltration into in situ retorts.
154
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TABLE 4-6. WATER QUALITY PARAMETERS FOR IN SITU
RETORT WATERS8
Parameter
Alkalinity
BODB
Carbon, bicarbonate (as HC03~)
Carbonate (as CO3= )
Inorganic
Organic
Chemical oxygen demand
Nitrogen, ammonia (as N)
Ammonium (as N)
Organic
Oil and grease
Phenols
Solids, total
Sulfur, sulfate
Concentration range (ppm)
18,200 to 110,900
350 to 5,500
4,200 to 42,000
0 to 7,500
1,960 to 19,200
2,830 to 19,000
8,500 to 43,000
1,700 to 13,200
930 to 24,450
73 to 1,510
580 to 3,800
2.2 to 169
6,350 to 121,000
42 to 2,000
a Source: references 16 and 17.
TABLE 4-7. MAJOR ORGANICS IN RETORT
WATERS*
Compound Concentration (ppm)
Acetic acid 600
Propanoic acid 210
n-Butanoic acid 130
Acetamide 230
n-Pentanoic acid 200
Propionamide 50
n-Hexanoic acid 250
Butyramide 10
Phenol 10
n-Heptanoic acid 260
o-Cresol 30
m & p—cresols 20
n-Octanoic acid 250
n-Nonanoic acid 100
n-Decanoic acid 50
"Major organic components in retort water from the Laramie Energy
Technology Center (LETC) 150 ton retort. Reference 30.
Waste-water from Mine Dewatering—
Water from aquifers encountered during mining and in situ retorting operations
must be removed by dewatering systems. The quality and quantity of such waters
will vary with the location and the processing technique employed. Surface retort-
ing process developers reportedly intend to use this mine water for wetting and
compacting retorted shale, and for dust control. In situ developers are working
toward reinjection of a portion of the mine dewatering flows and/or toward using
these wastewaters for spray irrigation. The major constituents of concern in mine
water are sodium, bicarbonate, and chlorides.
155
-------
The major potential oil shale developments are located in the Piceance Creek
Basin of Colorado, Utah, and Wyoming. The Piceance Creek Basin area contains
groundwater that is normally discussed in terms of lower and upper aquifers (even
though there is a multiple aquifer system) separated by the Mahogany Zone of oil
shale. The mine drainage is not uniform throughout the Piceance Basin. The south
end of the basin near the rim will produce little or no mine water.
The characteristics of the groundwater for the C-a and C-b lease tracts are ex-
pected to change as water enters the mine, moves downward, and travels horizon-
tally to the sumps where it will be collected. There is presently information on
groundwater leaching of raw shale but not on surface stored raw shale. It is an-
ticipated that water soluble inorganic salts (particularly sodium bicarbonate) and
organic materials can be leached (see Section 3, Leaching of Solid Wastes). Infor-
mation is not now available to ascertain the characterization of organics actually
present in the mine drainage. The level of organics may not be greater than 10 mg/1
(8.34xlO"5 Ibs/gal) and may not be significant in oil shale process water utilization
(Table 3-32).
The treatment of mine drainage waters for onsite use and possible above-ground
disposal will require information on both the organics and inorganics contained in
the waters. Values for the major inorganic constituents of the groundwaters that
will enter the mines are shown in Table 4-13. Table 4-14 summarizes Tract C-a and
C-b flow rates.
TABLE 4-8. TRACE ELEMENT CONCENTRATION (ppm) IN WATERS
FROM SURFACE AND IN SITU RETORTS
Surface retorts
Element
Be
Hg
Cd
Sb
Se
Mo
Co
Ni
Pb
As
Cr
Cu
Zr
B
Zn
Li
V
Mn
F
Ba
Fe
Refs.
2,25,29
—
—
0.96
0.06
0.005
0.03
0.002
1.0
0.007
0.16
0.003
0.44
0.045
0.006
0.002
0.019
0.3
0.09
5.7
Ref.
31
_
—
—
0.7
0.1
0.04
0.2
0.2
1.0
0.3
0.2
—
5.0
0.4
1.0
0.03
0.3
7.0
2.0
5.0
Ref.
32
_
—
—
0.1
0.006
0.004
0.034
_
_
0.004
0.16
—
0.55
0.045
—
_
0.02
3.1
—
—
Ref.
33
0.01
0.007
0.005
0.47
0.37
0.26
0.01
0.26
0.012
0.003
0.02
0.26
0.04
—
1.2
0.023
—
0.03
0.49
In
Ref.
34
0.01
0.07
0.1
0.1
0.07
1.0
0.1
6.0
0.02
0.007
0.07
6.0
0.4
0.3
0.7
0.1
25.0
0.05
25.0
situ retorts
Ref.
35
0.39
0.016
0.98
—
0.65
—
—
6.0
0.02
—
—
—
0.43
—
—
—
—
0.13
1.0
Ref.
36
0.01
0.001
—
—
—
—
—
0.03
2.0
—
0.2
—
—
5.0
—
—
—
—
—
—
Ref.
32
—
0.02
0.003
—
—
—
—
—
0.1
0.3
—
5.0
—
—
1.0
—
—
—
—
—
—
156
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TABLE 4-9. TRACE ELEMENTS IN SURFACE AND IN SITU
RETORT WATERS"
Element
Ag
Al
As
B
Ba
Be
Bi
Br
Ca
Cd
Ce
Cl
Co
Cr
Cs
Cn
Dy
Er
Eu
F
Fe
Ga
Gd
Ge
Hf
Hg
Ho
1
K
La
Li
Lu
Concentration range
(ppm)
0.002
0.024
0.0
0.26
0.002
to
to
to
to
to
0.23
0.8
10.0
8,
2
.8
.0
0.0b -
0.001
0.009
0.41
0.00
0.001
0.023
0.002
0.004
0.002
0.003
to
to
to
to
to
to
to
to
to
to
0,
0,
36
,009
,66
0.0b
0,
,1
2.0
0,
0,
,65
,3
0.01
0.2
—
0.0015
0.00029
0.3
0.49
to
to
to
0.010
54
77
0.02
0.02
0.001
0.002
0.01
to
to
to
0.007
0
0
.004
.39
0.00008
0.003
3.4
0.0017
0.004
0.00009
to
to
to
to
to
0.33
70
0.010
Element
Mg
Mn
Mo
Na
Nb
Nd
Ni
P
Pb
Pr
Rb
S
Sb
Sc
Se
Si
Sm
Sh
Sr
Tb
Th
Ti
Tm
U
V
W
Y
Yb
Zn
Zr
Concentration range
(ppm)
3.
0.
0.
8.
0.
0.
0.
0.
0.
0,
0.
14
0,
,2
,019
,006
3
,001
,001
,034
,58
,002
,0006
,036
004
0.0003
0.
1.
0.
0,
0,
0,
0,
0,
0.
0,
0,
0,
0.
0.
0.
0,
,003
7
,00031
,11
,003
.0011
,004
,2
.003
,002
.004
.003
,002
.00036
,037
,003
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
350
0.
0
1300
0
0
.3
.47
.005
.055
2.6
9
0
—
0
310
0.
0
.2
.37
.59
.047
.0004
3.1
48
0
100
3
0
0
21
—
4
11
0
0
—
14
0
.003
.0
.002
.013
.6
.024
.050
.4
.39
1.0
0.003
a Data from References 2, 7, and 24-27.
Not detected to these levels of concentration.
TABLE 4-10. CHARACTERISTICS OF STEAM BOILER
SLOWDOWN, UNION B PROCESS8
Constituent
TDS
Hardness (as CaC03)
Sodium
Chloride
Sulfate
Generation
kg/hr
2.7
0.3
0.5
0.8
0.8
rate
Ib/day
145.1
14.5
28.9
43.4
43.4
a Source: Reference 26.
157
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TABLE 4-11. CHARACTERISTICS OF WASTEWATER FROM
BACKWASHING AND RINSING OPERATIONS,
UNION B PROCESS3
Colorado River
White River
Concentration Generation rate
Constituents (mg/l)
IDS
SS
Hardness
Chloride
Sulfate
Calcium
Magnesium
454
25
214
119
129
60
17
kg/hr
4.6
0.2
2.2
1.2
1.3
0.6
0.2
Ib/day
242
13
114
63
69
33
9
Concentration
(mg/l)
551
32
300
42
188
84
24
Generation rate
kg/hr
5.5
0.3
3.0
0.4
1.9
0.9
0.2
Ib/day
293
17
160
22
100
45
13
a Source: Reference 26.
TABLE 4-12. CHARACTERISTICS OF REGENERATION
WASTEWATERS, UNION B PROCESS8
Constituent
TDS
SS
Hardness
Chloride
Sulfate
Calcium
Magnesium
Concentration
(mg/l)
20,430
2,043
9,889
2,780
4,500
2,190
1,130
Generation
kg/hr
129
13
63
18
28
14
7
rate
Ib/day
6,830
680
3,310
930
1,510
730
380
a Source: Reference 26.
A great variation can be found by sampling at different levels and locations
within the aquifers and by sampling at different times of the year. The extent to
which leaching in the mine will add to the contaminants will depend on the volume
of flow, the contact time with raw shale, and the extent to which dust and par-
ticulates are cleansed from the mine environment.
Power Generation Slowdowns—
Power generation blowdowns (6 in Table 4-5) include blowdowns to minimize
scaling and blowdowns from boiler feedwater systems, but they exclude steam
stripping wastewaters as proposed in other reports. The Union Oil Co. has
estimated some characteristics of boiler feedwater before and after blowdown in
Table 4-15 (26). Blowdown waters will require complete characterization.
158
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TABLE 4-13. SOME WATER QUALITY CHARACTERISTICS FROM GROUNDWATERS IN PICEANCE BASIN8
Aquifer concentrations (ppm)
Characteristic
Potassium
Sodium
Calcium
Magnesium
Bicarbonate (Na)
Chloride
Sulfate
Fluoride
Dissolved solids
Low
0.8
66.0
2.4
3.6
336.0
5.2
41.0
0.1
469.0
Alluvial
Mean
2.5
490.0
57.0
80.0
1220.0
42.0
430.0
5.0
1750.0
High
6.8
2900.0
120.0
160.0
3560.0
270.0
1500.0
33.0
6720.0
Low
0.2
55.0
7.4
9.8
307.0
3.4
24.0
0.0
345.0
Upper
Mean
1.5
210.0
50.0
60.0
550.0
16.0
320.0
1.0
960.0
High
6.0
650.0
110.0
187.0
918.0
63.0
850.0
12.0
2180.0
Low
0.4
230.0
2.8
3.0
493.0
1.3
4.2
5.0
491.0
Lower
Mean
11
3980
8
10
9100
690
80
28
9400
High
78
16,000
15
26
40,000
2,900
350
66
38,900
3 Source: Reference 18.
-------
TABLE 4-14. SOURCES AND FLOW RATES OF WATER FROM TRACT C-a
Source
Dewatering wells:
Upper aquifer
Dewatering wells:
Lower aquifer
Mine seepage water
Total Tract C-a
Estimated
flows (gpm)°'b
1,350°
3,900d
6,300C
3,600°
11,250°
13,800d
Water-to-Oil Ratio
(bbl/bbl)
0.812°
2.35d
3.79C
2.17°
6.772°
8.31d
0 Source: Roforonco 18,
D Tho estimate of dewotorlng flows (or Tract C-a IB given In the modified detailed development plan for u 67,000
bbl/Btroom day shale oil production rate (181. Tho in situ mine drolnugo volume for Truct C-b IB estimated between 1,0
and 1,68 bbl of walor/bbl of oil 1201.
° Original oatlmato,
Current upper aquifer dowatorlng rato Included.
Cooling Water Discharges—
Cooling water is used in retorting and shale oil upgrading to absorb heat that
cannot be economically recovered. Noncontact cooling water (7 in Table 4-5)
should be essentially pollution free. Noncontact cooling water, as defined by EPA,
is water used for cooling that does not come into direct contact with any raw
material, intermediate product, waste product, or finished product. On the basis of
several different raw water supply sources, the Union Oil Co. has estimated the
characteristics of cooling tower blowdown as given in Table 4-16 (26). It is an-
ticipated that the presence of biocides and other pollutants in cooling tower
blowdown may require special treatment.
Potable and Fire Treatment Discharges—
The contaminants in water treatment discharges (8 in Table 4-5) will be primary
coagulants and chemical sludges, backwash solids from the filtration system, and
blowdown from the zeolite softening system. Characteristics of water treatment
discharges have not been forecast specifically for an oil shale processing facility. It
is anticipated that blowdown from the potable water treatment system could be
treated by the domestic sewage system. Other wastewater treatment blowdowns
may also be amenable to treatment in the domestic treatment plant if toxic and
other materials are not present.
Storm Water Runoff and Leachate from Spent Shale Disposal—
Three types of solid wastes are produced from oil shale retorting operations: car-
bonaceous spent shale, burned spent shale, and raw shale itself. The surface retorts
consume most of the raw shale fed to them, whereas in situ retorts will require
larger quantities of raw shale above-ground storage. True in situ retorting results in
very little solid waste for disposal above ground. Different leachate and runoff
characteristics will result from each solid waste. Other sludges and solid wastes
from oil shale processing will perhaps be added to the shale for onsite, above-
ground disposal and may also change the leachability characteristics of the com-
bined solid wastes.
160
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TABLE 4-15. CHARACTERISTICS OF UNION B BOILER FEEDWATER
AND SLOWDOWN8
Characteristic
IDS (mg/l)
Conductivity (^ mhos/cm)
Hardness (mg/l)
Sodium (mg/l)
Chloride (mg/l)
Sulfate (mg/l)
Boiler
feedwaterb
50
75
5
10
15
15
Boiler
blowdown
331
496
33
66
99
99
a Source: Reference 26
b Low pressure steam generation equipment only.
TABLE 4-16. CHARACTERISTICS OF UNION B COOLING TOWER
SLOWDOWN8
Raw water supply source
Characteristic
resulting concentrations
IDS (mg/l)
Conductivity (^ mhos/cm)
Hardness (mg/l)
Sodium (mg/l)
Chloride (mg/l)
Sulfate (mg/l)
Fluoride (mg/l)
Chromium (mg/l)
Colorado
River
1,589
2,490
749
333
417
452
—
53
White
River
1,929
2,968
1,050
273
147
658
1
53
Upper
aquifer
3,360
5,250
1,295
735
56
1,120
4.9
53
Lower
aquifer
32,900
50,750
203
13,615
2,415
280
98
53
a Source: Reference 26.
The quantities of leachate and storm water runoff (12 and 13 in Table 4-5) that
will result from shale disposal are unknown. Numerous factors affecting
wastewater volumes and qualities are discussed elsewhere in this document.
Available data on experimental leachate from shale disposal indicate that it will be
highly polluting. The volume of wastewater from leaching and storm runoff will be
variable.
Application of Treatment Methods to Oil Shale Wastewaters
The methods of wastewater control technology that yield the greatest potential
for water recycling and that meet final disposal criteria should ultimately be chosen
by the developers of oil shale. Each developer will have an opportunity to explore
the recycling methodology available to produce zero discharge and thus complete
control of environmental pollutants. The optimum system for each process is yet to
be determined.
161
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Numerous modes of treatment, recycle, and control should be considered in try-
ing to optimize each process developer's water utilization scheme. The concept of
complete recycle will require maximum reuse, and some degree of treatment. The
extent to which this concept must be reached will be determined on a case by case
basis through existing regulatory mechanisms.
In order to solve the water utilization problems facing the oil shale industry, it is
necessary to consider all of the pollutants to be controlled and provide for ap-
propriate handling. Since a zero discharge water system is currently the goal of
several developers, detailed information on pollutant characteristics and process
water quality requirement is needed. It should be noted that, in the past,
wastewater streams have been characterized and reported on in a combined man-
ner, rather than as individual unit process streams. Judgments on selected treat-
ment options for specific wastewaters cannot be made in the absence of data on
specific pollutant characterization.
The following descriptions of treatment options consider clusters of combined
wastewater streams to the extent supportable by the data. Oil shale wastewaters are
known to contain dissolved and suspended solids, oil, trace elements and metals,
trace organics, toxic substances, dissolved gases, and sanitary wastes (e.g., see
Tables 4-6 through 4-10). The basic approach will be to provide water of a quality
for recycling and when necessary, discharge to the environment.
A hypothetical schematic diagram for oil shale wastewater treatment is presented
in Figure 4-2. The idealized processing scheme depicted does not necessarily reflect
optimum design recommendations, but rather an avenue of approach since the
treatments have not been demonstrated.
Regarding pretreatment and/or wastewater blending possibilities, the following
generalizations can perhaps be made. The wastewaters containing dissolved solids
(greater than 1,000 mg/1 or 8.34xlO~3 Ibs/gal) and suspended solids (those grouped
on the left half of Figure 4-2) should be essentially free of oil and trace organics and
can be collected and flow-equalized in large holding lagoons before treatment. The
oily wastewaters (above 10 mg/1 or 8.34x10"' Ibs/gal) from all wastewater sources
should be collected and processed by the API separator before receiving further
treatment. Trace element and metal-contaminated wastewaters should be essen-
tially free of oil and dissolved solids, thereby allowing separate treatment.
Wastewaters containing trace organics are not anticipated to be great in volume,
but highly diverse as far as the types of organic pollutants contained therein. Toxic
wastewaters are anticipated to be small in volume and to require careful control.
Wastewaters coming from scrubbers that treat common oil shale process gases such
as H2S, NH3, and CO2 will require specific controls and treatment before water
reuse or discharge. The sewage and water treatment wastes should be examined to
determine the advantages of separate treatment as compared with beneficial and
safe use of the nutrient, organic, and water content.
Dissolved and Suspended Solids Wastewater Treatment System—
A scan of the available data previously summarized indicates that the following
wastewater streams are candidates for the solids treatment system (see Table 4-5 for
the stream numbering key):
(Id) Groundwater (in situ, not organically contaminated)
(2j) Plant storm water runoff (diversion)
(21) Steam boiler blowdown
(2m) Boiler feedwater treatment blowdown
(4b) Dust control scrubber wastewater
(5) Mine drainage or mine dewatering wastewater
(6) Power generation blowdowns
(7) Non-contact cooling water blowdown
162
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,
ultraviolet I
I sterilizer I
L
Figure 4-2. Comprehensive hypothetical schematic diagram for oil shale wastewater treatment.
No one plant would utilize all treatments shown. The degree of treatment will vary dependent on reuse purpose.
(See Table 4-5 for key to wastewater streams indicated in the circles above.)
-------
(13) Spent shale leachate
The in situ process ground water may be high in organics and oil contents. If oil
and other organics are present, these wastewaters should be considered as can-
didates for the oily wastewater treatment system. Figure 4-2 indicates some of the
potential treatment processes which may be applicable to these streams (37,38,39).
Oily Wastewater System—
Special considerations should be exercised when designating a candidate waste
stream for treatment in the oily wastewater treatment system. The aqueous stream
should contain more than 10 mg/1 (8.34x10'' Ibs/gal) oil, and certain toxic elements
and organics should not be present in concentrations above the treatment
capabilities of the system. The candidate wastewaters for the oily wastewater treat-
ment system include the following (see Table 4-5 for the stream numbering key):
(la) Retort pyrolysis water
(Ib) Combustion of organics water
(Ic) Dehydration of minerals water
(Ih) Oil storage water
(2g) Drum cleaning wastewaters
(2k) Hydraulic decoking wastes
It is probable that in situ retort groundwater may be added to the volumes of oily
discharges mentioned earlier. The volume of groundwater could be substantial.
The system may also have to be modified to reduce specific pollutants before the
indicated treatment. Figure 4-2 indicates some of the potential treatment processes
which may be applicable to these streams (40,41).
Trace Elements and Metals Removal System—
Wastewater streams that contain some trace elements and metals of concern may
be controllable by use of a small treatment system. The waste streams identified as
potential candidates are (see Table 4-5):
(2f) Stripping condensed steam
(2h) Chemical reaction wastewaters
(2i) Spent caustic streams
Other plant wastewaters could be added if they are shown to be high in trace
elements and metals of concern and low in oil and organics. It is anticipated that
the design of this system will be site-specific and will depend upon effluent volumes
and required recoveries for each individual wastewater. Figure 4-2 indicates some
of the potential treatment processes which may be applicable to these streams
(40,42,43).
Trace Organics Treatment System—
The trace organics of environmental concern present in oil shale wastewaters are
suspected to be present primarily in the upgrading process area. The major sources
of trace organics may include (see Table 4-5):
(2a) Quenching
(2b) Vessel cleanout
(2c) Spills cleanup
(4a) Shale ash dust control
Other waste streams may contain only organics and be amenable to this system.
Only a process-by-process analysis will indicate which specific candidate effluents
may be appropriate. Figure 4-2 indicates some of the potential treatment process
which may be applicable to these streams (40,44,45,46).
164
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Toxics Treatment System—
Toxic components of oil shale wastewater can be treated in a variety of ways,
depending on the nature of the problem and the appropriate solution for each
specific case. Oil shale processing is known to produce carcinogens, mutagens,
priority pollutants, and other hazardous wastes. The specific system capable of
handling toxic liquid wastes will possibly receive the following candidate
wastewater discharge streams (see Table 4-5 for the stream numbering key and
Figure 4-2 for the flow sequence):
(le) Coker steam condensate
(2d) Coker blowdown
(2e) Process steam condensation
(3b) Wastewater from moisturizer operations
(3c) Elutriation scrubber wastewaters
The toxic substances anticipated will include trace and concentrated organics,
metals, and other concentrates that may present a health problem. High
temperature incineration is a thermal destruction method successfully employed by
industry to render many organic compounds in byproduct effluents innocuous.
Alternatively, chemical techniques could be used to destruct or chemically tie up
toxic substances found in oil shale wastewaters. Figure 4-2 indicates some of the
potential treatment processes which may be applicable to these streams.
Treatment System for Wastewater Containing Dissolved Gases—
The treatment systems needed to remove contaminants from off-gases wetscrub-
ber effluents are not new, but they have not yet been applied to the oil shale in-
dustry. As an example, a liquid-phase process (Stretford) to remove hydrogen
sulfide from gaseous effluents is planned but little applicable work has been done
on the liquid effluent. Until the complete system of air controls has been
demonstrated, the treatment system for wastewaters containing these dissolved
gases can only be hypothesized.
The main effluents to be controlled include wastewaters from the following unit
operations (see Table 4-5 for the stream numbering key):
(If) Product gas cooling condensate
(li) Product gas cleaning
(2c) Spills clean-up
(3a) Ammonia control
(3d) Gas cleaning
Figure 4-2 indicates some of the potential treatment process which may be ap-
plicable to these streams.
Domestic Wastewater Treatment System—
The domestic wastes which include laundry, sanitary kitchen wastes, etc. should
be given careful considerations as to the role they may play as a source of nutrients
for biological systems, for revegetation, etc. For these uses the public health
aspects must be considered (see Table 4-5 and Figure 4-2).
SOLID WASTE CONTROLS
Edward Bates
Surface Disposal of Overburden, Lean Shale, and Spent Shales
Surface disposal of at least some spent shale as well as possible surface disposal
of overburden, lean shales, raw shale fines, and chemical solids will occur as part of
any oil shale operation. However, overburden handling is expected to approach
significant size only for surface mining operations. Control technology for mining,
165
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handling, and disposal of overburden would be similar to that for other extractive
industries, although application to specific oil shale localities needs to be demon-
strated. Techniques employed in the surface mining of coal should generally be ap-
plicable to surface mining of oil shale. Disturbance of the minimum area necessary,
use of water sprays and chemical binders to control dust, conservation of existing
soil, and use of arid area revegetation techniques would be applicable. The major
problems anticipated are in the huge size of any operation envisioned, bulking ef-
fects, prevention of leachates that might affect surface or groundwater quality, and
retention of adequate moisture in the root zone to establish and maintain vegetative
growth. Selective placement, sizing, and compaction of backfilled overburden
materials would assist in controlling the leachate and moisture retention problem.
Lean shales could possibly be disposed of along with the overburden in the mine
cuts if their leachates are demonstrated to be free of contaminants that would af-
fect water quality. Disposal of other process wastes, including spent shales in the
mine cuts, may prove troublesome because of the risk of leachates impacts on
groundwater quality. Because of bulking effects, it would also be impossible to
return all mined material to the cut.
Surface Disposal of Spent Shale and Raw Mined Oil Shale
Any oil shale operation other than a true in situ operation must include disposal
of some spent oil shale on the surface, either in the form of disposal piles or as can-
yon fills. Studies to date by EPA and others indicate that revegetation of spent oil
shales is possible if properly conducted. Numerous studies have been conducted in-
cluding those by Colony Development Operation (47), TOSCO Corporation (48),
and Union Oil Company (49). Since 1973, EPA has been investigating the en-
vironmental impacts and possible control technologies for surface disposal of spent
shale. Field test plots have been constructed and studies made on coarse-textured
USBM spent shale, fine-textured TOSCO II spent shale, and coarse-textured
Paraho (direct mode) spent shale. The plots were constructed in Colorado at a low
elevation (1,700 m or 5,700 ft), very dry site near Anvil Points and at a higher eleva-
tion 2,200 m (7,200 feet), moister site in Piceance Basin near Black Sulfur Creek.
The most significant results of these ongoing studies to date may be summarized as
follows (42,50):
If spent oil shales such as the ones used in these studies are to be quickly stabi-
lized with native vegetation, they will require careful management which may in-
clude leaching, N and P fertilization, and irrigation for establishment. Nitrogen
application will be required for a few years after establishment.
The infiltration rate of the fine-textured spent shale is very slow, and thus the
erosion potential may be high when this material is subjected to high-intensity
summer storms. The slow infiltration rate must be considered when planning
stabilization of this spent shale.
Resalinization of leached fine-textured spent shale with resultant vegetation kill
occurred in these studies probably because a water table was established. If a
water table is not established, then resalinization should not occur.
Application of leach water on a continuous basis (100 cm or 39 in. over 10 days)
proved more effective in preparing the shale for revegetation than intermittent
application.
A surface stabilization alternative indicated by these studies consists of use of
soil over unleached spent shale (30 cm or 12 in. soil in the cited study). This alter-
native would work only for lower pH spent shales into which roots of adapted
species can grow, thus utilizing stored water. High pH (11-12) spent shales, into
which roots will not grow, would require thicker soil cover. Even with soil cover,
irrigation and fertilization during the first year would still be required for fast
cover establishment. Table 4-17 presents a summary of vegetative cover
established on test plots for TOSCO II, USBM, Paraho and Union B spent
166
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TABLE 4-17. PERCENT OF VEGETATIVE COVER ESTABLISHED
ON SPENT OIL SHALE TEST PLOTS
Year and %
Site
1973
25%
EPA low elevation site (1,700 m), seeded 1973:a
TOSCO spent shale
15 cm soil cover/TOSCO
30 cm soil cover/TOSCO
USBM spent shale
15 cm soil cover/USBM
60 cm soil cover/USBM
Soil control
Paraho spent shale
20 cm soil cover/ Paraho
40 cm soil cover/ Paraho
60 cm soil cover/ Paraho
80 cm soil cover/ Paraho
Soil control
50
80
80
56
70
70
64
—
—
—
_
_
-
EPA high elevation site (2,200 M), seeded 1975:
TOSCO spent shale
15 cm soil cover/TOSCO
30 cm soil cover/TOSCO
USBM spent shale
15 cm soil cover/USBM
30 cm soil cover/USBM
Soil control
—
—
_
—
_
—
-
1974
25%
,b
42
60
61
55
68
64
58
—
—
—
—
—
a,b
—
_
—
—
—
—
-
1975
25%
67
78
74
82
84
78
80
—
—
—
_
_
-
58
44
56
54
54
48
50
1976
25%
72
80
75
77
87
84
85
—
—
—
_
—
84
82
—
80
73
65
79
Paraho spent shale (seeded 1977)c — — — —
20 cm soil cover/ Paraho
40 cm soil cover/ Paraho
60 cm soil cover/ Paraho
80 cm soil cover/ Paraho
Soil Control
Union Oil Co. site (1,770 m), seeded
Union B spent shale
15 cm soil cover/Union B
30 cm soil cover/Union B
Soil control
Union Oil Co. site (2,300 m), seeded
Union SGR spent shale
15 cm soil cover/Union SGR
30 cm soil cover/Union SGR
Soil control
Union Oil Co. site (2,300 m), seeded
Union SGR spent shale
15 cm soil/Union SGR
Soil control
—
—
_
_
—
1975:M
—
—
—
-
1975:e
_
_
—
-
1975:e
—
_
-
—
—
—
—
-
_
—
—
-
—
—
—
-
—
—
-
—
_
—
—
-
38
73
75
65
—
_
_
-
—
—
-
—
_
—
—
-
59
56
69
65
42
49
51
65
7
47
76
slope
1977
2%
_
—
_
—
—
—
—
5
70
70
85
80
80
—
_
—
—
_
—
-
15
65
65
80
80
60
_
—
—
-
—
_
—
-
—
—
-
25%
29
32
46
53
38
42
36
5
85
80
80
80
75
60
52
50
60
52
42
46
10
75
75
65
75
55
45
37
40
41
18
29
29
41
13
46
54
1978
25%
66
76
70
65
72
78
75
66
66
62
65
64
83
63
69
62,
61
78
70
67
44
66
60
53
53
98
80
87
78
79
36
64
71
79
16
33
69
a 1978 data are mean of 2% and 25% slopes.
b 1973-76 data for EPA plots are from Reference 42.
1977-78 data for EPA plots are from Reference 51.
c The Paraho high elevation lysimeter was actually located at Anvil Points, Colorado but irrigation was used to
simulate at site elevation of 2,200 m.
Union data are from Reference 49, Tables 5 and 6, west aspect.
e West aspect. Reference 52, Tables 6 and 14.
167
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shales. The table shows that with proper management, it is possible to vegetate
spent shale successfully. The figures for 1977 and 1978 are especially significant.
The year 1977 was very dry and resulted in substantial reductions in vegetative
cover. The vegetation did, however, survive the drought of 1977 and shows a
good recovery in the moist year 1978. Thus it appears that once established,
vegetative cover will survive without irrigation.
The presence of deer and domestic livestock on disposal areas must be carefully
controlled to prevent grazing before establishment of a strong, permanent
vegetation cover. Such control may initially require exclusion by fencing.
Pocket gophers and other burrowing animals can be expected to move into the
revegetated areas. This control is difficult or impossible, and thus the site
stabilization scheme must be sufficiently resilient to allow for such disturbances.
Disposal sites on south aspects at the lower elevations (F2.000 m or 6,560 ft) have
very dry microclimatic conditions and require more intensive management than
more moist locations.
Erosion is a continuous natural process. Thus soil cover or spent shale modified
for plant growth eventually erode, particularly from steep upper slopes. This
process must be considered in future waste stabilization research and planning.
On the basis of the studies, it is recommended that high pH spent shale (such as
Paraho direct mode) be covered with soil to insure that an adequate vegetative
cover is quickly established. Tables 4-17 and 4-18 illustrate the importance of soil
cover in initial establishment of vegetation. More study is needed on soil-cover
treatments before a recommendation on the depth of soil cover can be made.
TABLE 4-18. PERCENT OF PLANT SURVIVAL AFTER 1 YEAR, BY SITE
TREATMENT AND TOPOGRAPHICAL ASPECT, ROAIM
PLATEAU8
Treatment
Topsoil
Rock mulch
Straw amendment
Subsoil only
Aspect mean
North
79
62
35
76
63
Aspect
Level
89
69
38
74
67
South
79
53
36
76
60
Treatment Mean
82
61
36
75
a Source: Reference 41.
Since the pollution potential from soluble salts is high, water should not be
allowed to leach through retorted oil shale and enter the hydrological system.
Possible alternatives for preventing water movement through retorted shale in-
clude revegetation, compacting the material to make it impervious to water flow,
if possible, and/or covering the material with a sufficient depth of soil material
to hold the seasonal precipitation, particularly from spring snowmelt. Surface
runoff from soil covered disposal sites may be of much better quality but should
be evaluated on an individual site basis.
Results from EPA's Paraho spent shale lysimeter study (50) suggest that water
moved into and through the compacted shale in the leached treatments.
Therefore, additional research is needed to insure that the material can be made
impervious, before a compacted zone is used to prevent water movement
through the commercial disposal pile.
168
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Additional research is needed on the rates of cooling of retorted shale under
commercial disposal pile conditions. If elevated temperatures are maintained in a
disposal pile, a very dry site could result because of warmer surface temperatures
and the resulting higher evaporation potential.
Additional research is needed to assess the dust control problems from retorted
shale disposal piles. Dust control measures such as water sprays may in turn pose
their own environmental problems.
Initial surveys of two vegetation species successfully grown on spent shale and
soil-covered spent shales show higher levels of some trace elements than vegeta-
tion grown on the soil controls. Some trace elements may inhibit plant growth or
prove harmful to animals feeding on the vegetation.
Canyon fills or disposal piles should be protected from the effects of severe
storm events, especially flash flooding.
Since 1976, the U.S. Forest Service has been studying the effects of soil amend-
ments, drip irrigation, containerized plants versus seeding, and species survival in
revegetating surface spent shale piles. Test sites for revegetating TOSCO II spent
shale are located at Sand Wash, eastern Utah, within the Salt Desert shrub zone
(very dry) and on the Roan Plateau, western Colorado, in the upper mountain
brush zone (more moist). Preliminary recommendations by the U.S. Forest Service
resulting from these EPA-sponsored studies may be summarized as follows (48):
Disposal embankments of processed oil shale should be covered with 30 cm (1 ft)
or more of local topsoil that has shown good capability for supporting vegeta-
tion. Use of topsoil increases the number of species adapted for revegetating
disposal embankments and greatly reduces the need for fertilizers. Topsoil was
superior to broken rock fragments, which in turn were superior to barley straw
as a soil amendment.
Several native saltbushes and two introduced Chenopodiaceae species that
showed excellent performance in these studies should be considered for use in
revegetating processed oil shale disposal embankments in the arid salt desert
shrub zone. Grasses that should be considered for use in that zone include four
native species (Indian ricegrass, galleta, blue grama, alkali sacaton) and two in-
troduced grasses (crested wheatgrass and Russian wildrye). Galleta, blue grama,
and alkali sacaton are warm-season grasses that require adequate summer
moisture for successful establishment.
In the more mesic mountain brush zone, the Chenopodiaceae and other shrubs
that performed well in these studies should be considered for revegetating proc-
essed oil shale disposal areas that have been covered with 30 cm (1 ft) or more of
topsoil. Native grasses that should be considered for use in the mountain brush
zone include beardless bluebunch, streambank, thickspike, and western
wheatgrasses, and Great Basin wildrye; introduced grasses include smooth
brome, fairway, intermediate, tall, and pubescent wheatgrasses.
Use of container-grown plants on arid and semiarid sites can ensure successful
revegetation of disposal areas where fall planting of seeds has failed. One liter
(.26 gal) or more of water per plant should be applied at the time of planting and
as needed during the first growing season.
Whereas supplementary water might not be required beyond the first growing
season for plant survival, additional moisture stored in the processed shale
underlying a covering layer of topsoil would enhance plant growth. Surface con-
figurations such as contour furrowing and/or pitting should be employed on
disposal areas to increase water infiltration and prevent runoff and erosion.
Site treatment such as the use of soil cover appears to be more significant to plant
survival and growth than either aspect (north, south, etc.) or slope (Table 4-18).
169
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Trace Element Uptake by Vegetation—
Little work has been done to date to determine if vegetation grown on spent
shale disposal areas contains increased levels of trace elements, especially metals.
Increased levels of some elements, such as boron and fluorine, may be toxic to
plants, and others such as molybdenum, selenium, and arsenic may be toxic to
animals. Table 4-19 summarizes results from trace element uptake studies of plants
grown on spent shale revegetation plots. Although data are still very meager, some
initial conclusions and tentative findings can be stated as follows:
Conclusions:
Plants grown on some spent oil shales have increased levels of some trace
elements compared to plants grown on native soils. Implications of these in-
creased levels are not known.
Uptake of trace metals is influenced by the type of spent shale.
Uptake of trace metals may vary with the type of vegetation.
Tentative findings:
Plants grown on TOSCO II spent shale tend to have increased levels of
fluoride, iron, molybdenum, and zinc.
Plants grown on USBM spent shale tend to have increased levels of boron,
fluoride, molybdenum, selenium, and zinc.
Plants grown on Paraho spent shale tend to have increased levels of iron,
lithium, and molybdenum.
Plants grown on Union B process spent shale tend to have increased levels of
copper, molybdenum and zinc.
Use of 15 to 20 cm (6 to 8 in.) of soil cover over the spent shale produced
mixed results on trace metal uptake; concentration of some metals in plants
decreased, and others increased.
Spent or Raw Shale Leachate—
Some leachate could probably be produced from any surface disposal of spent or
raw oil shale, and this leachate could probably adversely affect surface and ground-
water quality. A discussion of the nature of solid waste leachates and their possible
impacts on surface and groundwater quality was presented earlier in Section 3.
Some provision for collection, treatment, and/or reuse of this leachate will likely
be necessary. Use of an impermeable lining below the disposal pile, coupled with
installation of a drainage system to collect the leachate for treatment or reuse, may
be desirable. The surface retorting technologies are tending toward a zero discharge
concept, which would necessitate the collection, treatment, and reuse of this
leachate. If an impoundment structure is used for the collection or evaporation of
this leachate, it will be especially important to insure that leachate will not seep
through the bottom lining of the impoundment and enter the groundwater system.
As in the case of the disposal piles, provision should be made to protect the im-
poundment structure from the effects of severe storms, especially flash floods.
Spent shale leachate of poor water quality may possibly be produced for many
years beyond the period of time that any particular oil shale facility would be in
operation. Therefore, a technology needs to be developed and employed to prevent
leachate from causing surface and groundwater pollution after cessation of retort-
ing operations. Such a technology could perhaps take the form of an essentially
maintenance-free evaporation pond to contain the leachate that is produced.
Process-generated solid wastes such as spent catalysts, lime sludges, coke, and
other solids from water and wastewater treatment systems may contain highly toxic
substances such as arsenic and require disposal as toxic substances. Disposal of
these wastes by burying them in the spent shale pile would probably result in in-
creased levels of toxic pollutants in the spent shale leachate and impacts on surface
170
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TABLE 4-19. TRACE METAL UPTAKE BY PLANTS GROWN ON EPA SPENT OIL SHALE TEST PLOTS
(oom)
Shale type
TOSCO l£
TOSCO II3
15 cm soil
over TOSCO II
USBM3
UO LJ IVI i
b
a
USBM
15 cm soilb
over USBM
Paraho
20 cm soil
over Paraho
Union Process B shale
Plant As
.Fourwing
Saltbush <0.02
Western
wheat grass
Fourwing <0.2
Saltbush
Fourwing
Saltbush <0.2
Western
wheat grass
Fourwing <0.2
Saltbush
Fourwing <0.2
Saltbush
Fourwing <0.2
Saltbush
Fourwing 1
Saltbush
B Cd
69.7
c 0.07
126.59
c 0.1
53.69
c 0.04
29.13
c 0.02
c 0.04
c 0.05
39.0 0.22
Cr Cu F
4.13
<0.1 1.4 c
4.71
0.2 0.9 c
6.36 2.0
<0.1 0.8 c
2.85
0.1 0.4 c
0.1 <0.1 c
<0.1 0.2 c
6.2
Fe Hg Li Mn Mo Ni
4.71
70 <0.1 <0.05 18 1.3 4.6
4.25
76 <0.1 <0.05 18 2.4 3.8
22.71
57 <0.1 <0.05 16 2.8 2.2
5.07
72 <0.1 1.0 21 6.4 1.9
114 <0.1 1.5 16 2.6 0.2
108 <0.1 <0.05 28 8.4 2.0
1.3
Pb Se
<0.1 1.1
0.22
<0.1 3.2
<0.1 4.5
0.45
<0.1 3.8
<0.1 1.0
<0.1 2.0
5 1.0
V Zn
0.4 404
<0.2 289
<0.2 49
<0.3 22
<0.2 4.3
<0.2 7.8
22.5
a Reference 45. Mean of North and South aspects, high and low elevation plots, 1976 and 1977.
b Reference 46. Samples collected 11-1-78.
c Value questioned.
d Data from application of Union Oil Company to Colorado Mined Land Reclamation Board, March 26, 1979.
-------
TABLE 4-19 (continued)
Shale type
Union Process B shaled
Union Process B shaled
15 cm soil overd
Union Process B shale
15 cm soil overd
Union Process B shale
15 cm soil overd
Union Process B shale
Soil control3
Anvil Pointsb
Soil control3
Anvil Points
Soil controld
Union
Soil controld
Union
Soil control
Union
Plant
Grass
mixture
Winterfat
Fourwing
Saltbush
Grass
mixture
Winterfat
Fourwing
Saltbush
Western
wheat grass
Fourwing
Saltbush
Grass
mixture
Winterfat
As
1.8
2.2
1
2.0
1.5
<0.2
1.0
2.2
2.5
B
39.5
22.5
34
34
27
66.98
c
9.19
44.5
7.5
22.5
Cd Cr
0.04
0.23
0.20
0.06
0.20
0.12 0.2
0.26
0.05
0.33
Cu F Fe
6.7
9.6
5.6
5.9
8.7
1.91
4.3 c 57
2.17
5.6
4.8
8.2
Hg Li Mn Mo Ni
6.7
7.6
5.7
4.8
7.1
5.53
0.1 <0.05 18 0.7 3.1
2.69
4.7
3.9
2.7
Pb
2
2.5
6
1.5
3
<0.1
4.5
1.5
3.5
Se
1.0
1.0
1
1
1
0.5
0.19
1.0
1.5
1.0
V Zn
28.5
47
48
26
41.5
0.2 0.0
27
18.5
27.5
a Reference 53. Mean of North and South aspects, high and low elevation plots, 1976 and 1977.
b Reference 54. Samples collected 11-1-78.
c Value questioned.
d Data from application of Union Oil Company to Colorado Mined Land Reclamation Board, March 26, 1979.
-------
and groundwater quality. Disposal of some process wastes along with the spent
shale may be possible after it is demonstrated that they do not themselves produce a
leachate and that they do not facilitate production of additional pollutants in the
spent shale leachate. A future alternative method for handling potentially toxic
wastes such as spent catalysts may be to return them to the manufacturer for
regeneration and subsequent reuse.
Underground (Mine) Disposal of Spent Shale—Bob Newport
A single commercial surface retorting operation will generate a minimum of
45,000 tonnes/day (50,000 tons/day) of spent shale. Particle size of this waste
depends on the retorting process used and ranges from finely divided residues to
boulders more than 20 cm (8 in.) in diameter. Water passing over this waste pro-
duces a leachate of extremely low quality. Total dissolved solids have been
measured at 130,000 mg/1 (0.108 Ibs/gal). In addition, spent shale contains up to 5
percent organic carbon. Some fractions of this organic material have been found to
contain polycydic aromatic hydrocarbon compounds that have carcinogenic
components. These figures are used only to indicate the potential pollutants that
could be made available during shale disposal.
To answer the concern about disposing of spent shale in a manner that is en-
vironmentally acceptable, various methods have been considered: Surface disposal,
mine backfilling with dry spent shale, and backfilling with spent shale slurry. The
preferred method depends on whether the mine is wet or dry. Because of potential
chronic leaching, spent shale should not be returned to a wet mine. Adverse
leachate problems are much easier to control on the surface than in a subsurface
environment. Numerous research studies indicate that, except for stabilization and
revegetation, shale spoil, because of its adverse leaching potential, should be pro-
tected from moisture to the extent practical.
Groundwater is the ultimate recipient of shale leachate from surface disposal or
mine backfill. Because of potential leaching of organic and inorganic compounds
by groundwater, a concerted effort should be made to minimize leachate volumes
entering the groundwater system.
In the case of a dry mine, however, the return of the dry spent shale to the mined
areas may be acceptable pending further study and the promulgation of future
regulations. This system creates support, reduces subsidence potential, and reduces
surface storage of spent shale by approximately 60 percent.
Current research indicates that potential adverse environmental and operational
problems can result from pumping spent shale in a slurry form back into an oil
shale mine or abandoned retort. Low compressive strengths of shale slurry, the
potential for chronic leaching of slurry backfill and surface storage of slimes
created by slurry production and application all pose a potential serious threat to
groundwaters of the Piceance Basin and should be critically investigated prior to
the initiation of the shale slurry backfill operations. For these reasons, hydraulic
backfilling of spent shale is not recommended at this time.
Stabilization of In Situ Spent Shale—by Edward Bates
True and modified in situ retorting processes leave the retorted shale below the
ground, which avoids many of the problems of surface disposal but also creates a
greater potential for groundwater pollution. In addition, any subsidence that may
occur could fracture overlying aquifers and result in water movement between
aquifers and probable lowering of groundwater quality. Dealing with these poten-
tial impacts would require development and implementation of new control
technology not available at this time.
Control of Leachate—
The prevention of groundwater and surface water (from groundwater recharge
of surface streams) pollution by true or modified in situ retorting is an unsolved
173
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problem. Some possibilities that have been proposed include the use of high retort-
ing temperatures, slurry backfilling, exhaustive leaching and treatment, and
hydrologic barriers or bypass.
High Retorting Temperatures—Maintaining high retorting temperatures (ap-
proximately 1,000° to 1,200°C or 1,832° to 2,192°F) encourages the restructuring
of shale minerals into insoluble igneous or metamorphic mineral complexes. The
formation of such complexes at temperatures of approximately 900° to 1,200°C
(1,650° to 2,192°F) under laboratory conditions has been demonstrated and re-
ported by Smith, Rubb, and Young (55). If the results of such laboratory studies
are applicable to field retorting conditions, then this approach might serve as a
primary control technology. However, several questions must be answered before
applicability of this approach can be assessed. First, it must be determined that the
mineral complexes produced by field conditions are similar to those indicated by
laboratory studies under controlled conditions. Second, the spent shale mineral
complexes produced in the field must be shown to remain insoluble under condi-
tions that exist years after backflooding of modified or true in situ retorts. It must
be established that the water quality of backflooded retorts will not cause a
breakdown of these mineral complexes. And, third, and perhaps most difficult, it
will be necessary to demonstrate that retorting conditions can be controlled to pro-
duce a spent shale that is uniform in respect to its insolubility. This step may be dif-
ficult, since one of the retorting problems is maintaining a uniform retorting front.
Portions of the retort, especially fringe areas, may not reach temperatures high
enough to produce the mineral complexes reported in laboratory studies.
Slurry Backfilling for Cementation—It has been suggested that finely crushed
surface-retorted shale grout could be hydraulically injected into burned out
modified in situ retorts to fill void areas and cement the retorts to make them im-
permeable to water flow.
Surface-retorted shale has been shown to have some cementation properties
under controlled conditions (56,57,58). However, several questions must be
answered before this can be considered as an applicable control technology to pre-
vent leachate generation from modified in situ retorts. It must be demonstrated
that injected spent shale slurry will develop adequate cementation strengths and
very low permeability values when injected into the environment of burned out
retorts. The question of whether injected spent shale itself would produce a
troublesome leachate must be addressed. As discussed in Section 3 under Solid
Waste Impacts, the leachates from surface-retorted shale (Table 3-27) may affect
water quality. It is possible that such injection may compound the problem of
groundwater pollution rather than solve it. The mechanics of injecting the slurry so
as to obtain a uniform distribution within the retort may prove very difficult.
Permeabilities to flow of injected slurry may be highly variable within the retort,
making uniform dispersion to seal the retort impossible. Preliminary cost estimates
for grouting retorts with spent shale slurry have been stated by Persoff and Fox as
being $2.70/bbl of oil for the C-a lease tract and $3.80/bbl for the C-b tract (59).
However, the Rio Blanco Oil Shale Company has stated that they believe the actual
costs will be much lower (personal communication from Kay Berry, Rio Blanco Oil
Shale Company).
Exhaustive Leaching and Treatment—If it is found that spent shale within true
or modified in situ retorts does indeed produce a leachate that can significantly
lower groundwater quality and if efforts to seal the retorts to prevent water move-
ment through them fail, then a serious water pollution hazard could exist.
One possible approach to resolving such a problem would be to intercept and
remove the leachate and contaminated groundwater near the retorts by pumping
followed with adequate treatment and reinjection downgradient from the retorts.
In addition to the obvious problem of cost, a major unanswered question affecting
this approach is the length of time that such a program might have to be main-
174
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tained before the retorts would be adequately leached to permit safely discontinu-
ing the pumping and treatment process. Pumping and treating would likely be
necessary for a number of years following retorting. Analysis of water samples
from the Rock Springs, Wyoming Site 6 of the Laramie Energy Technology Center
showed some improvement, but they were still far from restored to the background
water quality 50 months after retorting (59). Possibly, the leaching process could be
deliberately accelerated to reduce the treatment period, but such technology has yet
to be developed. Preliminary cost estimates for collecting leachate and treating it
on the surface by activated carbon and reverse osmosis have been estimated by Per-
soff and Fox at $1.20/bbl of oil production, based on treating six pore volumes of
leachate (59).
Hydrologic Barriers—The use of hydrologic barriers such as barrier pillars to
control the inflow of water into the retort area and prevent the spread of leachates
from the retort area has been suggested as a partial solution to the problem.
However, barrier pillars alone cannot be expected to be very effective, since the
retort zones often intersect aquifers or other zones of water movement. Effective-
ness of barrier pillars could be substantially increased by use of grouting to seal
more permeable zones and fractures. Barrier pillars properly designed and supple-
mented by grouting could reduce the magnitude of the rate of leachate plume
development under favorable hydrogeologic conditions, but they are not by
themselves likely to solve the problem. Preliminary cost estimates for construction
of a grout curtain around the retort area have been estimated by Persoff and Fox at
$1.70 to $2.80/bbl of oil for the C-a and C-b lease tracts, respectively (59).
Hydrologic Bypass—The use of a hydrologic bypass to divert a major portion of
the groundwater flow around the retort area has been theorized (59). Essentially, a
hydraulic bypass would capture most of the groundwater flowing toward the retort
area, carry it around the retort zone, and return it to the groundwater flow system
downgradient from the retorts. The design of such a system would vary with the
local hydrology but would likely involve use of numerous wells.
A hydraulic bypass system carefully designed for local hydrology could possibly
make a substantial reduction in the quantity of leachate produced, but will not by
itself solve the problem. In addition, a hydraulic bypass system may permit the
mixing of waters between aquifers of differing quality. Preliminary cost estimates
for constructing a hydrologic bypass system for the C-a and C-b lease tracts have
been estimated by Persoff and Fox at $0.25 and $0.50/bbl of oil produced, respec-
tively (59).
Prevention of Subsidence—
Modified in situ retorting, conventional underground mining, and possibly true
in situ retorting may pose fracturing and subsidence problems unless subsidence
control technology is provided. For conventional underground mining, some con-
trol technology presently exists for other mineral commodities that could probably
be modified and applied to the specific hydrologic and geologic environment of a
particular underground oil shale mine. Backfilling of mine voids with spent shale
could provide additional support, though groundwater pollution could be a con-
cern. Weakening of pillar strength by spalling and weathering would require special
attention to avoid long-term problems.
For modified and true in situ retorting an acceptable control technology has not
been demonstrated. Both these technologies depend on fracturing the oil shale to
be retorted. Technology to fracture the shale and yet not seriously fracture or
weaken surrounding rock and support pillars has not been perfected. Recent ex-
perience of the Occidental Oil Shale Company at their Logan Wash site indicates
that problems in controlling the nature and extent of fracturing still exist.
Subsidence need not reach the surface to have serious impacts on the environ-
ment. Fracturing of overlying water-bearing strata may result in loss of this water
175
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resource to the retort zone, compounding the problem of leachate production and
doubly affecting groundwater resources. Injection of spent shale or other cement-
ing material into burned out retorts may provide additional support and help pre-
vent fracturing of overlying strata. However, the key to controlling subsidence or
fracturing of surrounding strata will likely lie in learning to control the rubblization
process and developing a technology for providing adequately-sized and
appropriately-spaced support pillars capable of supporting overlying strata. The
possible effects of heat on the strength of support pillars and overlying strata
should be investigated to assure that adequate support will remain after retorting.
OTHER PROCESS CONTROLS
Prepared for Dale Denny and Bruce Tichenor by Radian Corporation
Storage Tank Vapor Controls
Floating-roof tanks and internal floating covers are two tankage alternatives to
standard fixed-roof storage tanks that offer substantial hydrocarbon emission con-
trol. These alternatives lower both diurnal breathing losses and filling losses
associated with fixed roof tanks by eliminating the vapor space inside the tank.
Floating-roof tanks consist of a welded or riveted cylindrical steel wall equipped
with a deck or roof that is free to float on the surface of the stored liquid. The roof
rises and falls according to the depth of stored liquid. To insure that the liquid sur-
face is completely covered, the roof is equipped with a sliding seal around its cir-
cumference, which fits against the tank wall. Additional emission control is pro-
vided by employing double sliding seals. Roof drains are also provided to protect
against excessive loading by rain and snow.
Internal floating covers are floating roofs or floating decks provided inside a
standard fixed-roof tank. They are equipped with sliding seals and are free to float
on the product surface in the same manner as floating roofs. A primary advantage
of internal floating covers is that they are protected from the weather and do not
require provisions for rain and snow removal.
Floating roof and internal floating cover technology is well developed, having
been applied by the petroleum and chemical industries for many years. Internal
floating covers are more applicable for locations with very high wind, rainfall, or
snowfall, than are floating roof tanks. Also, internal floating covers may be
retrofit to fixed-roof tanks. Both are available as prefabricated units in a variety of
styles for tanks ranging in size from smaller than 400 m3 or 14,126 ft3 (2,500 bbl) to
more than 95,000 m3 or 3,354,894 ft3 (600,000 bbl). Costs for floating covers vary
with the size of the storage tank. A recent report (60) indicates installed costs of
$40-50,000 for floating roofs on tanks with capacities of 16,000 m3 or 565,040 ft3
(100,000 bbl).
Floating roofs and internal floating covers are very reliable and require only a
minimum of maintenance. Sliding seals exposed to harsh weather must be routinely
inspected and occasionally replaced. Heavy snows must be removed from exposed
floating-roof tanks.
Standing storage emissions from floating-roof tanks and internal floating covers
are approximately 15 percent of comparable fixed-roof tank emissions, and work-
ing emissions (those resulting from level changes after filling or discharging) are less
than 1 percent of comparable fixed-roof tank emissions. Actual emission reduc-
tions are a function of tankage operations, but, in general, net emissions from
floating-roof and internal floating-cover tanks average less than 10 percent of emis-
sions from comparable fixed-roof tanks. No secondary pollutants are associated
with floating-roof tanks or internal floating covers.
176
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Refinery Sludge Controls
The most common sources of refinery sludges are as follows:
Cooling water sludge API separator bottoms
Alkylation sludge Treating clays
Biological sludge Storm water silt
Tank bottom sludge
Existing practices in refineries that are employed to limit or reduce these sludges
and other solid wastes consist primarily of source control methods.
The initial step in applying source control techniques involves identifying and
monitoring sources of oil, water, and other contaminants. Two policies that can be
implemented to help monitor and control solid wastes are:
Refinery permit systems that allow oily streams to be released to drains only with
the approval of the environmental department, and
Shutdown planning that provides for prearranged disposition of oils and wash
waters.
After solid waste sources have been identified and monitored, the next step is to
implement in-plant operating procedures or equipment changes to reduce the
amount of wastes from these sources. Operating procedures that might be
employed include water re-use and segregated drains for process and storm water.
These methods introduce less water into oily drains and also result in reduced
amounts of soluble contaminants and biosludges. Treatment methods such as
aerobic digestion, incineration, settling, and centrifugation significantly reduce the
quantity of sludge for final disposal and help recover oil and remove water from
solid wastes.
Equipment which can be utilized to reduce the amount of contaminants to oily
drains and the oil content of API separator solid wastes include mechanical seals
for pumps and flow-by sample valves. In addition, the installation of mixers in
storage tanks to keep solids suspended in the oil will diminish tank bottom sludge
formation.
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Pollutants from Industrial Wastewaters with Volatile Solvents. EPA-600/2-78-220, U.S.
Environmental Protection Agency, Cincinnati, Ohio, 1976.
47. Bloch, M., and P. D. Kilburn, eds. Process Shale Revegetation Studies, 1963-1973. Col-
ony Development Operation, Atlantic Richfield Co., Denver, Colo. 80202.
48. Merino, J. M., and R. B. Crookstun. Reclamation of Spent Oil Shale. Mining Congress
Journal, October 1977.
49. Berg, W. A., J. T. Herron, H. P. Harbert, and J. E. Kiel. Vegetative Stabilization of
Union Oil Company Process B Retorted Oil Shale. Bulletin 135, Colorado State Univer-
sity Experiment Station, Fort Collins, Colo. 80523, 1979.
50. Harbert, H. P., W. A. Berg, and D. McWhorter. Lysimeter Study on the Disposal of
Paraho Retorted Oil Shale. EPA-600/7-79-188, U.S. Environmental Protection Agency,
Cincinnati, Ohio, 1979.
51. Berg, W. Colorado State University. Unpublished data, December 1978.
52. Herron, J. T., W. A. Berg, and H. P. Harbert, III. Vegetation and Lysimeter Studies on
Decarbonized Oil Shale. Bulletin 136, Colorado State University Experiment Station,
Fort Collins, Colo. 80523, January 1980.
53. Kilkelly, M. K., R. E. McFadden, and W. L. Lindsay. Trace Element Content of Plants
Growing on Processed Oil Shales. Progress Report COO-4017-2, June 1, 1977 to May 31,
1978, DOE Contract EY-76-5-02-4017. University of Colorado, Boulder, Colo., 1978.
54. Hittman Associates, Inc. Analysis of Selected Samples for Metals Uptake. U.S. En-
vironmental Protection Agency, Cincinnati, Ohio. (In press.)
55. Smith, W. J., W. A. Rubb, and N. B. Young. High Temperature Reactions of Oil Shale
Minerals and Their Benefit to Oil Shale Processing In Place. In llth Oil Shale Sym-
posium Proceedings. Colorado School of Mines Press, Golden, Colo., 1978.
56. Peterson, R. W., and F. C. Townsend. Geotechnical Properties of a Fine Grained Spent
Shale Waste. In llth Oil Shale Symposium Proceedings. Colorado School of Mines
Press, Golden, Colo., 1978.
179
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57. Woodward Clyde Consultants. Laboratory Tests on Paraho Pilot Plant Retorted Oil
Shale. Open File Report 66(2)-76, U.S. Bureau of Mines, U.S. Department of the In-
terior. Available as NTIS Report PB 253 598, National Technical Information Service,
Springfield, Va., 1975.
58. Woodward Clyde Consultants. Laboratory Tests on Retorted Shale from the Direct
Heated Semi Plant. Open File Report 66(3)-76, U.S. Bureau of Mines, U.S. Department
of the Interior. Available as NTIS Report PB 253 599, National Technical Information
Service, Springfield, Va., 1975.
59. Persoff, P., and J. P. Fox. Control Strategies for Abandoned In Situ Oil Shale Retorts.
In Proceedings of the 12th Oil Shale Symposium, Golden, Colo., April 18-20, 1979. Col-
orado School of Mines Press, Golden, Colo., 1979.
60. Gunther, A. Reduction of Air Emissions from Gasoline Storage Tanks.
EPA-600/2-79-108, U.S. Environmental Protection Agency, Office of Research and
Development, Washington, D.C., May 1979.
180
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SECTION 5
SAMPLING, ANALYSIS AND MONITORING
This section discusses the sampling, analysis, and monitoring techniques and
programs that should be a part of any commercial oil shale activity. It describes
analytical methods and the application of those methods to air, surface and ground
water, and solid waste leachates.
This section cites the need for baseline sampling, analysis, and monitoring prior
to oil shale recovery and processing in order to maintain the environment as nearly
as possible in its original condition. It also cites the need for monitoring programs
to predict and thus to aid in preventing environmental damage. Finally, it considers
the need for long-term monitoring, particularly around shale disposal sites, after
conclusion of oil shale processing activities.
Monitoring needs may be satisfied by the oil shale developer, the government,
and by other organizations. It may be useful, therefore, to distinguish between
regulatory requirements which the developer must meet and environmental answers
which may be answered through government research. It may also be in the best in-
terests of the industry to perform some limited screening research monitoring.
After a discussion of ambient and stationary air monitoring techniques, a discus-
sion of water pollutants of concern is presented, but with greater emphasis on
monitoring, including siting and frequency of sampling. This discussion cites the
need for biological monitoring in addition to the use of physical and chemical tests.
Predictive capability is emphasized in the discussion of solid waste disposal sites
because of the potential need for corrective action at these sites during and follow-
ing processing activities to control leachate movement. The discussion of solid
waste disposal also cites the need to inspect shale disposal sites regularly for stabil-
ity and integrity.
AIR
Robert Thurnau, David Sheesley and Michael J. Pearson
This section incorporates both stationary and ambient air monitoring tech-
niques. Table 5-1 summarizes the accuracy and precision of data for all methods
discussed here.
Gases
The contribution of gaseous pollutants to the atmosphere by oil shale processes
is a very important aspect of the environmental problem associated with oil shale.
The analytical determination of these compounds is important from a process as
well as from an environmental point of view. Gaseous emissions are discussed
relative to stationary source testing and ambient air monitoring. Actual data from
several testing occasions have been included to illustrate concentrations en-
countered and variability of results.
SO2, Stationary Source Method—
The method for SO2 determinations is Method 6, Determination of Sulfur Diox-
ide Emissions from Stationary Sources (1). In this method, a gas sample is passed
through an impinger train containing a 3-percent hydrogen peroxide absorbing
solution. The sulfur dioxide is measured as a sulfate by barium-thorin titration.
181
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TABLE 5-1. PRECISION AND ACCURACY RANGES FOR MONITORING
METHODS USED IN THE ANALYSIS OF OIL SHALE
EFFLUENTS
Pollutant and method
Accuracy and/or precision
1. Sulfur dioxide, S02:
A. Ambient:
1. Std method (Schiff)
2. Flame photometric
3. Pulsed fluorescent
B. Source:
1. Std method (sulfate titration)
2. Oxides of nitrogen, NOX:
A. Ambient:
1. Arsenite method
2. Chemiluminescence
B. Source:
1. Std method (phenoldisulfuric acid)
3.- Carbon monoxide, CO:
A. Ambient:
1. Std method (nondispersive infrared)
2. GC (THC method)
B. Source:
1. GC
4. Combustion gases:
A. Source:
1. Carbon dioxide (GC)
2. Nitrogen N2 (GC)
3. Oxygen 02 (GC)
5. Suspended particulate (Std hi-vol method)
6. Ozone:
A. Ambient:
1. Ultraviolet Absorption (Std method)
2. Chemiluminescence
B. Source:
1. Kl method
7. Hydrogen sulfide, H2S
A. Ambient:
1. Sulfur-specific photometric detector
B. Source:
1. Cd(OH2) method
8. Carbon disulfide, CS2 and
carbonyl sulfide, COS:
A. Source:
1. Cd(OH2) for CS2
2. CdClj for COS
9. Ammonia, NH3:
A. Ambient:
1. Indophenol
B. Source:
1. Impinger method
(Avg. value) 41 ± 6^/m3
NRa
18.914.3 ppmv
Range: 60 to300pi/m3±
1 V/m3 SDb
Precision: 5 ppb
217.3 ±39.6 ppmv
+ 3 ppm bias
Range: 3.43 to 40.6
Average difference: 3.2%
2.60 + 0.2% (v)
25.93+1.45% (v)
60.89 ±3.50%
NR
3.7% Precision
1.7% Precision
6% Precision;
- 5% accuracy bias
NR
2.76%, relative SD 0.1 ngs
1.764± 42.5 mg/m3
NR
NR
Range: 1 to 30 ppb;
precision: 30%
4,457 ±891 mg/m3
182
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TABLE 5-1. (continued)
Pollutant and method
Accuracy and/or precision
10. Trace metals:
A. Ambient (metals on particulate):
1. Mercury (silver wool)
2. Lead (3% HP03 on filter)
3. Arsenic (glass filter)
B. Source (metals in gas):
1. Mercury (impinger)
2. Arsenic (GC/MS)
11. Hydrogen cyanide, HCN:
A. Source:
1. Hydrolysis to NH3
12. Sulfates, SO;:
A. Ambient:
1. Methylthymol blue
13. Particulate analysis (Inorganics on the
particulate):
A. Ambient:
1. Nitrate NOa (cadmium reduction)
2. Fluoride F~ (ion selective electrode)
14. Particulate loading:
A. Ambient:
1. Stacked filters
B. Source:
1. Isokinetic sampling
15. Organic:
A. Ambient:
1. BAP
2. PAH GC/UV
3. POH (Ultrasonic collection)
4. Ambient organics (cartridge method)
B. Source:
1. C, C6(GC)
NR
Range: 80 to 125 g/m3;
precision: 3.7%
Coefficient of variation: 4%
± 10% relative SD
NR
81.25 ±5.81 mg/m3
Recovery: 91% to 99%;
relative SD; 2% to 4%
Recovery: 94% to 103%;
relative SD; 2 to 3%
5% to 10% relative SD
NR
Range: 10 to 400 ng; coeff.
of var. ± 0.07
NR
±5% Precision
NR
NR
Not Reported.
Standard deviation.
This method was used in two separate testing occasions at the Paraho oil shale
retort by TRW. Results, reported as reliable at the Paraho operation are summar-
ized as follows: (2,3)
Date SO2 (ppmv)
10/15/77 16.0
10/17/77 22.0
10/17/77 14.5
10/19/77 23.0
Mean and SD 18.9 ±4.3
183
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This method is subject to interferences from free ammonia, water soluble ca-
tions, and fluorides. Ammonia and fluorides have been identified as present in oil
shale effluents and could interfere with the determination. The TRW Corporation
tests added a sulfuric acid trap to remove ammonia and recorded SO2 concentra-
tions of 11 and 14 ppmv. The lower values might indicate that there could be an in-
terference, but more data are necessary before it can be stated with any certainty.
This is the type of work that is envisioned as being done by the methods manual
study mentioned earlier. However, until otherwise indicated, Method 6 (1) will be
used for the measurement of SO2.
S02, Ambient Methods—
Colorimetric Analysis—By a principle based on the Schiff reaction and West-
Gaeke modifications (4) sulfur dioxide is absorbed from ambient air volumes into a
solution of potassium tetrachloromercurate (PTCM). The resulting dichloro-
sulfitomercurate complex is reacted with pararosaniline and formaldehyde to form
a colored dye. Absorbance of this colored solution is measured spectrophotometri-
cally.
The EPA reference method (5) is called either manual or automated. A revised
standard of test also appears in the American Society for Testing and Materials
(ASTM) Annual Book of Standards, (6).
The method is applicable to the ambient atmospheres in the range of 5 to 13,000
mg/m3 (0.002 to 5 ppm). Autoanalyzer techniques, absorption collection efficiency
of sampling, and manipulation of sample solution aliquot have lowered the limit of
detection to 5 mg/m3 (7-9).
Flame Photometric Detection—Ambient air can be sampled continuously and
supplied to a flame photometric detector. An in-line H2S scrubber is required by
the equivalency method under designation by EPA to remove H2S and pass SO2.
SO2 is converted to an S2 excited molecular species that emits light near the 394
nanometer (nm) wavelength, and intensity is measured with an optically filtered
photomultiplier tube. Response is approximately equal to the square of sulfur atom
concentration (10,11).
Analyzers that chromatographically separate SO2 from other gases in ambient
atmospheres do not respond to changes in concentration as quickly as those that
monitor without prior separation. Concentrations over the range of 0.01 to 1 ppm
are measured in atmospheres containing low concentrations of sulfur-containing
gas and CO2.
Pulsed Fluorescent Detection—Ambient air is sampled continuously and sup-
plied to a fluorescent chamber where SO2 is detected. The method is an EPA-
designated equivalent method (12,13). Pulsating ultraviolet (PUV) light is focused
through a narrow band pass filter into the fluorescent chamber. SO2 molecules are
excited, and fluorescent light is emitted and measured by a photomultiplier tube.
The fluorescent radiation is proportional to SO2 concentrations in ambient air.
The method is applicable where instrumentation is operated on the 0.5 ppm full-
scale range within a temperature range of 20 to 30 °C (68 to 86 °F) and where
suitable power is available. Ambient atmospheres with concentrations greater than
5 ppbv over a 24-hr period are measured with a rise and fall time of 4 min as con-
centration is changed.
NOx, Stationary Source Method—
The method employed for oxides of nitrogen determinations is Method 7, Deter-
mination of Nitrogen Oxide Emissions from Stationary Sources (1). Grab samples
of the gas are collected in an evacuated flask containing a dilute sulfuric
acid/hydrogen peroxide solution. The nitrogen oxides, except nitrous oxide (N20),
are oxidized to nitrate and determined by the phenol disulfonic acid method. This
method was used by TRW in the examination of the off-gas of the Paraho oil shale
retort and found to be acceptable (2,3). The results of their analysis are as follows:
184
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Date NOX (ppmv)
10/15/77 160.0
10/17/77 235.0
10/17/77 250.0
10/19/77 224.0
Mean and SD 217.3 ± 39.6
The amount of scatter for the NOX data is more severe than for the SO2 data, but
valid conclusions cannot be drawn with this limited information.
NOi, Ambient Methods—
Bubbler Method—NO2 is measured in ambient air by specifically removing NO2
with sodium arsenite reagent solutions through reactions between nitrite ion (NOr)
and diazotizing and coupling reagents. Analysis of the colored azo dye is per-
formed with a spectrophotometer at 540 nm of 10-nm bandwidth (14).
The method is applicable to ambient atmospheres for 24 hr and for determina-
tion of NO2 concentration in the range from 0.005 to 0.4 ppm. Interferences are
negligible in ambient air quality monitoring when the procedure is applied in
underdeveloped areas. NO and CO2 have been found to be potential interferences
in urban atmospheres (15).
Chemiluminescence—The chemiluminescence procedure for measuring NO2
uses the principle of gas phase reaction of NOX and O3 to form NO2 and light.
Detection of NOX (NO + NO2) requires conversion of NO2 to NO, since the reac-
tion is directly proportional to NO in the presense of excess O3. Typically, NO2-to-
NO converters are capable of quantitative conversion for long periods before
needing maintenance (16).
This principle has application in ambient monitoring and automated monitoring
networks in the range of 0.005 to 1 ppm with linear response over these concentra-
tions. It is an EPA Federal reference method (17).
CO2, CO, Ni, and O2, Stationary Source Method—
These parameters are usually indicative of the process efficiency and can be
determined with a gas chromatograph. A column of silica gel and a molecular sieve
is placed in series with a thermoconductivity detector, and the gas is separated into
its various components. Table 5-2 summarizes the data taken at Paraho during one
testing sequence (3).
TABLE 5-2. SUMMARY OF CO2, O2, N2, AND CO
DATA TAKEN AT PARAHO
Date C02 02 N2 CO
10/17/77
10/17/77
10/19/77
10/19/77
10/20/77
10/20/77
10/21/77
Mean and SD
25.08
25.71
25.92
25.14
27.36
28.28
24.02
25.93
- 60.94
63.89
54.83
57.82
- 60.93
- 63.91
0.78 63.91
0.78 60.89
2.94
2.43
2.81
2.68
2.45
2.68
2.18
2.60
+ 1.45 ±3.50 +0.2
185
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Workers investigating the emissions from a TOSCO II operation also have
reported using a gas chromatograph to determine the composition of the gas by
analyzing it for CO, CO2, O2, and N2 (18). Researchers at the Laramie Energy
Technology Center have also employed this technique for analysis of the off-gas
(19).
CO, CHt, NMHC, Ambient Methods-
Flame lonization Detection—Measured volumes of ambient air are delivered 4 to
12 times/hr to a gas chromatographic column where HC, CO2, and H2O are
separated from methane and CO. Methane (CH4) is transferred and measured in a
hydrogen flame ionization detector . The CO is eluted to a catalytic reduction tube
and reduced to CH4 before passing through the FID. Hydrocarbons (HC) are also
transferred quantitatively to the FID, and nonmethane hydrocarbons are deter-
mined by subtracting the methane from the total hydrocarbon (THC) value (20).
The method is applicable to the semicontinuous measurement of THC, CH4, and
CO in ambient atmospheres over the range 0.025 to 2 ppm for THC, 0.025 to 1
ppm for CO, and 0.025 to 2.0 ppm for CH4 (3,21).
Nondispersive Infrared—The principle of nondispersive infrared (NDIR) is
based on the absorption characteristics of CO at infrared wavelengths. The spec-
trometer measures the absorption of CO using two parallel infrared beams and a
selective detector over the range of 1 to 100 ppm (0.7 to 115 mg/m3 or 3.06x10"" to
5.03xlO-2 grains/ft3) (22). The procedure is an EPA Federal reference method (17).
Application depends on the ambient atmosphere to be monitored, since the
degree of interference by water vapor can be equivalent to 11 mg of CO/m3 or
4.81xlO-3 grains/ft3 (10 ppm) (23).
Hydrocarbons at concentrations found in suburban ambient atmospheres do not
ordinarily interfere, since 325 mg methane/m3 or 0.142 grains/ft3 (500 ppm) will
give a response equivalent to 0.7 mg/m3 or 3.06x10-" grains/ft3 (0.5 ppm) (24).
Trace Metals, Stationary Source Method—
A system of four impingers commonly used in Method 5, Determination of Par-
ticulate Emissions from Stationary Sources, is usually employed for the collection
of trace metals. The first is filled with 3M H2O2, the second and third are filled with
0.2M (NH4)2 S2O, plus 0.02M AgNO3, and the fourth is filled with Drierite*. The
peroxide is used for SO2 removal, and the persulfate solution removes trace metals
such as Hg, Se, Sb, As, or Pb that pass through the peroxide solution. The sampl-
ing train can also use IC1 as the oxidizing medium when specific tests for mercury
are made. It has been demonstrated by Fox (25) that the impinger method is effec-
tive for collecting mercury samples. The samples are then brought to the laboratory
and analyzed by atomic absorption spectroscopy (AAS).
TRW used the impinger technique described above to evaluate the mercury emis-
sions from the Paraho oil shale retort and reported mercury concentrations of
0.304, 0.120, 0.155, 0.235 and 1.298 mg/m3 or 1.33xlQ-4, 5.24x10-', 6.77x10-',
1.03x10-", 5.67x10-" grains/ft3 (0.304, 0.120, 0.155, 0.235, and 1.298 ppb) (3). This
technique was stated by TRW to be accurate to ± 10 percent. Trace metal ex-
periments carried out by Shendrikar and Faudel (18) were conducted by passing the
gases from the Fischer Assays through 100 ml (.026 gal) of 1:1 nitric acid x water
mixture. The samples were boiled down and diluted to a known volume and used to
represent the gaseous fraction of the total trace metal concentration. No data were
presented on collection efficiency.
Arsenic was determined by TRW, but the levels were too dilute to be detected by
AAS methods (3). An outline of the method used to convert arsenic to arsine
(AsH3) is given, and a gas chromatograph/mass spectrometer (GC/MS) technique
for analysis is presented for concentrations of less than 1 ppb.
Fruchter (26) found arsenic in the form of arsine at levels of 0.015 mg/m3 or
6.55x10-' grains/ft3 (0.015 ppb) in the off-gas from the LETC 9-tonne (10-ton)
retort by using neutron activation analysis and x-ray fluorescence.
186
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Ozone, Ambient Methods—
Ultraviolet Absorption—The analytical principle employed for ozone utilizes the
intensity changes of UV energy as the light beam traverses a fixed pathlength oc-
cupied by a volume of air containing ozone (27).
Continuous instrumentation utilizing the UV absorption principle has applica-
tion in the ambient atmosphere and will measure concentrations from 0.003 to 1.0
ppm. It has been projected as an equivalent method.
Chemiluminescence—Chemiluminescence can be used as the analytical techni-
que for ambient ozone measurements. Sample gases containing ozone and reagent
ethylene are combined, and the chemiluminescent light produced as a result of the
reaction is photometrically detected (28,29). Instrumentation to monitor O3 con-
tinuously in the ambient atmosphere is specified in the Federal Register (30).
Ambient atmospheres are monitored over the concentration range of 10 mg/m3
to 2 mg/m3 or 4.37x10-' to 8.74x10-" grains/ft3 (0.005 to 1.00 ppm). The
chemiluminescent detection of O3 with ethylene is not subject to interference from
common gaseous air pollutants such as NO2, CO, NH3, and SO2 at ambient con-
centrations.
AT/, and HCN, Stationary Source—
Both NH3 and HCN can be analyzed using the same sampling train. The sample
is drawn through three impingers with 5 percent HC1 for ammonia removal and
then passed through another impinger that contains concentrated H2SO4 for
hydrolyzing HCN to NH3. Samples were titrated by the Los Angeles Air Pollution
Control District using this method, and the accuracy was estimated at ± 5 percent
for the hydrogen cyanide (3). Table 5-3 summarizes the reported data for NH3 and
HCN from the recycle gas of the Paraho Retort.
TABLE 5-3. SUMMARY OF NH3 and HCN EMISSIONS
IN THE RECYCLE GAS FROM PARAHO
mg/m3
Date NH, HCN
10/17/77
10/17/77
10/17/77
10/17/77
10/19/77
10/19/77
10/20/77
10/20/77
Mean
±SD
5,032.0
4,093.0
4,987.0
3,519.0
4,560.0
NR
6,028.0
3,611.0
4,457.0
±890.8
Not Reported (NR)
NR
NR
NR
79.50
80.59
75.56
89.33
81.25
+ 5.81
Ambient Ammonium Method—
Atmospheric ammonia is collected by drawing a known volume of air through a
dilute sulfuric acid solution. Ammonium sulfate is formed and then reacted with
phenol and alkaline sodium hypochlorite to form the blue dye, indophenol.
Sodium nitroprusside is used as a catalyst to speed up the reaction. After reaction is
complete, the solution can be analyzed spectrophotometrically (31). The
mechanism of this reaction has been proposed by Rommers and Vissor (32).
The range and sensitivity of the method is reported (33) as 20 to 700 mg/m3 or
8.74xlQ-6 to 3.06x10-" grains/ft3 (0.025 to 1 ppm) with a sampling rate of 1 to 2
1/min (.26 to .52 gal/min) over a sampling time of 1 hour. The detection limit is
0.02/mg NH3/m3 (8.74x10'' grains/ft3) (33).
187
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Hydrogen Sulflde, Stationary Source Method—
The method used for hydrogen sulfide is Method 11, Determination of
Hydrogen Sulfide from Stationary Sources (34). The method utilizes about 0.20 M
solution of cadmium hydroxide (Cd[OH]2) to precipitate the hydrogen sulfide as
CdS. The precipitate is oxidized with I2 and back-titrated with thiosulfate. TRW
ran four H2S determinations at Paraho with this method and got a mean of 1,764.7
mg/m3 (0.771 grains/ft3) and an SD of 42.5 (3).
Hydrogen Sulflde, Ambient Method—
A gas chromatographic separation of substances is used in conjunction with
sulfur-specific detection by the flame photometric detector. The detector measures
sulfur-containing gases at the 399 ± 5 nm emission line of sulfur in a hydrogen-rich
flame, with a specificity ratio of sulfur to nonsulfur compounds of between 10,000
and 30,000 (35).
Carbonyl Sulflde and Carbon Bisulfide, Stationary Source Method—
Carbonyl sulfide and carbon disulfide are collected by passing the gas through a
series of impingers. Typically, the first impinger contains Cd(OH)2 to remove any
hydrogen sulfide. The second impinger is empty to collect any carryover. The third
impinger contains 100 mg (1.54 grains) of 7.5 percent CaCl2 and 1 percent NH4OH
for collection of carbonyl sulfide. The fourth impinger contains 100 mg (1.54
grains) of alcoholic KOH to collect carbon disulfide, and the last impinger contains
silica gel. The hydroxide and chloride solutions are normally oxidized to SO4 by
hydrogen perioxide and analyzed by gravimetric methods. TRW used these tech-
niques for the analysis of COS and CS2 in the gas stream of the Paraho Retort. The
results are summarized in Table 5-4 (3).
TABLE 5-4. SUMMARY OF COS AND CS2 DATA
FROM PARAHO
Date
9/6/77
9/6/77
9/6/77
mg/m3
COS
32.6
50.0
NDa
CS2
58.3
NDa
NDa
a None detected.
Based on the range of data, it might be inferred that this method should be a can-
didate for additional study.
Organics (C, - C6), Stationary Source Method—
Direct measurement of organics in the gas stream is usually limited by the boiling
point of the organic compound, and carbon compounds with more than six carbon
atoms are usually too dilute to analyze without some separation and/or concentra-
tion procedure. Figure 5-1 shows how the percentage of hydrocarbon in the gas
stream varies with boiling point and illustrates the point very clearly that the C6 +
fraction is extremely dilute. Note, however, that the concentration of organic
material in the gas stream depends on the type of process used to retort the shale,
and some systems have produced markedly different gas compositions.
188
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-180 -140 -100
-60
-20
+60 +100
BOILING POINT TEMPERATURE, C
Figure 5-1. Percentage of hydrocarbon in the gas stream versus boiling point of
carbons 1-6.
The light-end organic compounds (C, - C6) are usually present in sufficiently high
concentrations to be routinely determined by gas chromatographic techniques. The
conditions vary to some extent and are summarized for two testing occasions in
Table 5-5.
Most of the n-alkanes and n-alkenes can be identified by their retention time
data. Other compounds that do not fall into that category can be identified by
using mass spectroscopy.
Analysis of the gas stream for organics larger than six carbons requires the addi-
tion of more sophisticated equipment, usually a GC/MS system. Since these
189
-------
TABLE 5-5. SUMMARY OF GAS CHROMATOGRAPH CONDITIONS
FOR C, - C.
Source
Level 1 Assessment
(Ref. 36)
TRW (Ref. 3)
Column
Poropak Q in
6'SS columns
Poropak Q in
6'SS columns
Detector
Flame ionization
Flame ionization
Temperature
100°C
isothermal
60 to 160°C
@ 20°C/min
samples are collected in a cold trap, they are analyzed as the solid fraction. Their
analytical description will be covered in a later section.
Organics, Ambient Methods—
Gas Chromatography—Ambient air samples are collected through grab sam-
pling techniques using plastic bags with air valves. Portions of the ambient air in
the bag are analyzed for C, through C, hydrocarbons by GC (37).
The method has applications in atmospheres containing 0.01 ppm. The lower
limit for C3 through d HC can be extended by concentrating 100-ml (2.64xlO-2 gal)
aliquots or more of sample in a freeze trap. This limit is 0.1 ppbv.
Sampling is accomplished by flushing the plastic bag three times with ambient air
and then filling the bag for transport to the GC for analysis. Integrated sampling
can be done with large-volume bags and appropriate storage times before analysis.
Analysis is performed on a single column at 0°C (32 °F), with separated com-
ponents being detected by a flame ionization detector.
Fluorometric—Samples of benzo(a)pyrene and other aromatic hydrocarbons
collected on membrane filters are extracted with benzene for subsequent separation
by thin-layer chromatography. The BaP fractions from the TLC separations are
extracted, evaporated, and dissolved in sulfuric acid for quantitative fluorometric
measurement (38).
The fluorometric final analytical step of the procedure is linear over the range
from 10 to 400 ng (10'' g) (1.54xlQ-7 to 6.17x10-' grains), and sample aliquot size
from the benzene extraction must be adjusted so that sample concentration falls in
this analytical range. Ambient air containing 0.02 to 0.8 mg/m3 (8.74x10"' to
3.50x10"" grains/ft3) would correspond to this range.
UV Spectroscopy—Sampling for polynuclear aromatic hydrocarbons is con-
ducted with-a suitable air mover and membrane or glass fiber filters, with subse-
quent GC separation of extraction mixtures. Polynuclear aromatic compounds are
collected from GC eluate and analyzed by UV spectroscopy (38).
The method has a range of concentration from 2 to 1000 mg/m3 (8.74x10-' to
4.37x10-" grains/ft3), with sample volumes as low as 0.5 m3 (17.66 ft3). Ambient at-
mospheres in oil shale areas will require that large volumes of air be sampled.
Detection limits lie in the range of 0.2 to 2.7 mg/sample (3.09xlQ-6 to 4.17xlO'!
grains/sample) for individual compounds as collected on membrane filters.
FID/GC Method— Filter samples of aromatic HC can be extracted ultrasonically
in CS2 or benzene solvent, and the solvent solution is analyzed by FID/GC. The
method is not specific, and analysis is qualitative for classes of compounds as
defined in the Federal Register (39,40).
Ambient concentrations of 0.05 to 10 mg/1 (4.17xlQ-7 to 8.34xlO~J Ibs/gal) can
be measured with a sufficient volume of sampled air (usually 1 m3 or 35 ft3).
Absorption, Purge and Trap Gas Chromatography—Ambient organic
concentrations are determined on a semiquantitative basis by sampling through
specially designed cartridges mounted in place of the filter on a high volume air
sampler. Absorbed organic material is quantitatively desorbed from the cartridge
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with separation and identification, first by GC and then by MS (41).
The technique has application in ambient atmospheres with concentrations of
organics ranging from baseline levels (low concentrations) to relatively high con-
centrations when sampling for specific time periods at 100 to 250 ppm. Detection
limits are typically 0.1 ng/m3 (4.37x10-" grains/ft3) (42).
Participates—David Sheesley and Michael J. Pearson
The solid material collected at an oil shale retorting operation can be split into
two categories: controllable and fugitive emissions.
Controllable emissions are those process emissions that are confined by ducts,
pipes, etc. that constrain their movement and direct them to a suitable control
device. These types of emissions can be accurately sampled by utilizing isokinetic
sampling techniques outlined in Method 5, Determination of Particulate Emissions
from Stationary Sources (1). The primary method of analysis is to weigh the filters
and correlate the mass to the volume of gas sampled. If taken properly, this value
will reflect the concentration of the solids in the process stream at the time the sam-
ple was taken.
The uncontrollable, or fugitive, emissions present a severe sampling problem
because of their lack of confinement. High volume samplers are usually employed
as the method for collecting fugitive emissions. Care must be exercised to space or
align the samplers properly in order to collect representative samples. Isokinetic
sampling techniques are not employed, but a calibrated orifice allows a reasonably
good estimation of the volume of gas that has passed through the filter, and the
concentration of the dust in the air can then be determined. Unless some specific
experimental conditions are instituted, this technique has the disadvantage of not
being able to differentiate between various aspects of oil shale activities. Data on
fugitive emissions from mining operations can contain information on blasting
operations that are not distinguished from the total. An advantage of the technique
is that it allows collection of large amounts of particulates that can be used for ad-
ditional analysis. The main analytical technique for fugitive emissions is the deter-
mination of the mass of particles collected.
Additional analytical procedures can be carried out on the collected particulate,
and these techniques can be found under the following section on solid waste
sampling and analysis.
Ambient Particulate Sampling Methods—
Hi-Vol Sampler—The principle of the high volume (Hi-Vol) particle sampler is
filtration sieving from a moving air stream. The glass fiber collects particles by in-
terception and diffusion mechanisms according to the size of airborne particulate
being sampled.
Particles with diameters of less than 100 mm or 3.94x10"' in. (Stokes equivalent
diameter) are normally collected over a 24-hr period at a flow rate of 1.1 to 1.7
mVmin (38.8 to 60.0 ftVmin). The method is applicable in an ambient atmosphere
having concentrations of suspended particulates in the 10- to 1,000-mg/m3
(4.37xlO-6 to 4.37x10- grains/ft3) (43).
Stacked Filter Unit—Ambient air can be sampled through stacked membrane
filters, and particles in the air stream are physically separated into two frac-
tions—12 and 0.2 mm (4.72x10"" and 7.87x10"' in.) (44,45). Typical mass loadings
on the two filters suitable for subsequent analyses are 25 mg/m3 (1.09x10"'
grains/ft3) for the larger and 16 mg/m3 (6.99x10"' grains/ft3) for the smaller filter.
The procedures have application where concentrations of the ambient at-
mospheric constituents are of the order of nanograms per cubic meter (ng/m3).
Sampling flow rate is adjusted according to the face velocity required to meet
calculated efficiency of collection on membrane filters (46).
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Virtual Impactor—Ambient air is sampled by a dichotomous sampler, and par-
ticles in the air stream are physically separated according to size by inertial impac-
tion and collected by filtration. Filter samples are transported to a laboratory
where analyses of the size-fractionated particulate matter may be carried out
through a variety of analytical procedures. Mass loading on the filters is sufficient
for energy-dispersive x-ray fluorescence (EDXRF) spectroscopy, ion
chromatography, and spectrophotometric analysis (47,48). Nondestructive
EDXRF analysis is followed by sonification extraction and transfer with subse-
quent analysis (49). Ion exchange chromatography and analyses for hydrogen ion,
sulfate ion (by thorin spectrophotometry), and ammonium have been performed
(48).
Analytical Methods for Ambient Particulate Samples
Ambient Sulfates Method—
Ambient sulfates are collected by drawing air through a glass-fiber filter with a
hi-vol pump (50). The filters are extracted with H2O and the extract is analyzed for
sulfates by the methylthymol blue (MTB) method using a single channel Technicon
Autoanalyzer II system equipped with a linearizer (51).
The MTB method is based on the spectral difference that exists in basic solutions
(ph 12.5 to 13.0) between the barium ion (Ba+t) complex of MTB and the free MTB.
At this pH, the barium complex is blue, and free ligand is brownish-red (absorbs
light at 460 nm). Thus the color of solutions containing both the free ligand and the
complex appears as gray. The amount of free ligand, monitored colorimetrically at
460 nm, is the measure of the amount of sulfate in the sample because the reaction
of sulfate with MTB-Bat+ results in an equivalent amount of free ligand.
The method is applicable to the collection of 24-hr samples in the field and subse-
quent analysis in the laboratory.
Nitrates, Ambient Method—
Ambient nitrates are collected by drawing air through a filter with a high-volume
pump. The exposed hi-vol filters are extracted with H2O and analyzed for nitrates
by reduction of the nitrate to nitrite by a copperized reductor column. The nitrite is
reacted with sulfanilamide in acidic solution to form a diazo compound. This com-
pound then couples with N-1-naphthylenediamine dihydrochloride to form a red-
dish purple azo dye that is determined colorimetrically at 520 nm using a Technicon
Autoanalyzer II.
The method is applicable to the collection of 24-hr ambient samples in the field
and subsequent analysis in the laboratory.
Trace Metals—
Lead—Lead is extracted from filter strips by using 3 percent nitric acid (HN03)
as an extracting solution and then sonifying for 30 min. The concentration of lead
in the resulting solution is determined quantitatively using flame atomic absorption
(AA) spectrophotometry (52).
Ambient air volumes of 2,400 m3 (84,746 ft3) are typical, with a linear range of
analysis of 15 mg/ml (8.74xlQ-6 Ibs/gal). The method can be used for sample ex-
tracts containing between 0.03 and 7.5 mg/m3 (1.31x10-' and 3.28x10'' grains/ft')
of inorganic lead. More concentrated solutions can be diluted and the upper limit
of the range thereby extended.
Mercury—Ambient air is drawn through silver wool in glass tubing where
elemental mercury is collected and then desorbed at high temperature for transfer
to AA analysis (53).
The sampling procedure has application for atmospheres with concentrations of
0.02 to 10 mg/m3 (8.74x10-' to 4.37x10-' grains/ft3) at collection flow rates of 100
to 200 cmVmin (6.10 to 12.20 in.Vmin) over a 24-hr period.
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Arsenic—Air is sampled through glass fiber filters for 24 hours to collect particles
containing arsenic. Arsenic and the more natural aerosol, arsenic acid, are ex-
tracted from filter strips using 0.5 percent sodium hydroxide (NaOH) as an extract-
ing solution. The concentration of arsenic in the resulting solutions is determined
quantitatively using graphite-furnace AA spectrophotometry.
The method can be applied to ambient air samples of at least 10 m3 (353 ft3) hav-
ing concentrations in the range of 0.1 to 1.0 mg/m3 (4.37xlO~8 to 4.37xlO~7
grains/ft3). The method can be used for sample extracts containing between 0 and 3
mg/ml (0 and 2.50xlO~8 Ibs/gal) arsenic. More concentrated solutions can be
diluted and the upper limit of the range thereby extended (54).
Fluoride—Fluoride ion concentrations in H2O soluble samples extracted from
hi-vol filters can be measured directly using a F" selective electrode in conjunction
with a standard pH meter with an expanded millivolt scale. Electrode potentials are
measured at 60-, 90-, and 120-sec intervals. Values extrapolated over arbitrarily
long times are calculated and compared with the calibration curve determined from
standard fluoride solutions (55).
The detection is approximately 0.002 mg FVml (1.16x10-' Ibs/gal). The upper
range for this procedure is 0.1 mg FVml (5.82x10'' Ibs/gal). Samples with fluoride
concentrations above this upper working limit can be analyzed using appropriate
dilution techniques.
Asbestos—Ambient air is drawn through a membrane filter, and the filter is
transformed for optical analysis (56). The method is the test method in the U.S.
Public Health Service criteria document on occupational exposure to asbestos (57)
and is listed in the 1974 Annual Book of ASTM Standards (58).
The method with suitable sampling periods has application in atmospheres con-
taining concentrations of asbestos and asbestos-like fibers over the range of 1 to 20
fibers/m3 (.028 to .567 fibers/ft3). Fibers longer than 5 mm (1.97x10- in.) are
counted.
Meteorological Conditions
Monitoring of meteorological conditions is critical for assessing the environ-
mental impact of new source emissions. It is essential that meteorological data be
representative of source conditions and primary receptor areas. The degree to
which the data are representative depends on the complexity of the terrain, ex-
posure of the sensors, and the period of data collection. Although onsite data are
preferred, offsite data may be adequate for some applications (59). A minimum of
1 year of meteorological data is required. If available, 5 years of data should be
used to minimize year-to-year variations.
Most meteorological variables can be measured using standard National
Weather Service (NWS) equipment or its equivalent, and data values should meet
NWS standards for accuracy. The parameters measured depend on previous data
available for the area, representativeness of that data, and its intended application.
Extensive information exists on required meteorological inputs for standard com-
puter air monitoring models and guidelines on meteorological siting and instru-
ment exposure. Data-averaging over time periods shorter than 1 hr may be required
by certain complex terrain models.
Visibility
The Clean Air Act Amendments of 1977 declared the protection of visibility in
mandatory Class I Federal areas as a national goal (60). The NAAQS and PSD
standards require that a means of maintaining visibility in such areas be developed.
In October 1979, EPA submitted a report to Congress (61) defining visibility,
monitoring methods, modeling data requirements, and permit review re-
quirements. This report provided the guidelines required to establish future regula-
tions.
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At this time, no universally accepted definition of visibility or visibility monitor-
ing methodology exists (8), but four methods are commonly used for assessing
visibility-related parameters: (1) Photography, (2) telephotometry, (3)
nephelometry, and (4) transmissometry (62). These methods of visibility monitor-
ing are described in Appendix B.
WATER
Wesley Kinney and Leslie McMillion
Surface Water Monitoring Methodology
The objectives of water quality monitoring programs with respect to oil shale
development are to provide:
1. A record of changes from conditions existing before development operations,
as established by baseline studies and evaluation;
2. A continuing check on compliance with all applicable Federal, State, and
local pollution control laws, regulations, and lease requirements;
3. Predictive capability or timely notice of conditions or developing potential
problems that would require correction to prevent environmental damage;
4. Determinations of the effectiveness of mitigating procedures implemented in
regard to item (3) above;
5. Observations and calculations on effects in the biological realms resulting
from changes in water quality and quantity.
From a water-quality standpoint, surface water and groundwater are closely
related in most of the western oil shale regions. As exemplified by conditions in the
Piceance Creek Basin, a significant portion of the surface water results from
natural groundwater discharges. The quality of the streams likewise reflects the
contributions from groundwater. Thus, a total monitoring program must consider
both. However, because the methods for sampling and hydrologically investigating
the two differ considerably, they are treated separately in the following.
Surface Water Impacts—
It is anticipated that surface water impacts will be attributable to one or more of
the following situations, singly or in combination:
1. Point source discharges, such as wastewater outfalls or cooling system
discharges;
2. Nonpoint source discharges, such as runoff from stored solids, erosion of
construction areas, or overland transport of airborne fallout materials;
3. Accidental discharges such as spills from trucks, leaks in pipelines, or failure
of containment structures or embankments around holding ponds or solid
waste disposal piles;
4. Flow reductions through consumptive uses and mine dewatering.
Point Sources—Point source discharges from extraction or processing opera-
tions are not currently anticipated to contribute substantially to the degradation of
surface water quality. Most excess mine waters, water from spent shale piles, and
process water will be collected and routed to evaporation ponds or utilized. Slurry
waters, if used to transport spent shale, will also be recovered and rerouted to con-
tainment ponds or utilized (63).
Because of the diffuse and episodic nature of probable sources of surface water
pollution, point source monitoring is not expected to be a major component of the
overall monitoring effort. However, if direct discharges to surface water occur,
such discharges will be subject to the requirements of the NPDES Permit Program,
including self monitoring of the effluents by the discharger. Monitoring re-
quirements with respect to parameters, frequency, sample, and data handling and
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analytical procedures will be specified by the regulatory agency issuing the
discharge permits. Required monitoring would most likely include measurements
of volume, sampling and analysis for selected chemical constituents, suspended
solids, temperature, and pH. The frequency, duration, and methods of sampling
should be such that a calculated average constituent loading ± 50 percent will en-
compass the true average loading over any period of time.
Nonpoint Sources—It appears that the greatest potential for surface water qual-
ity degradation is from nonpoint sources rather than point sources. Thus, in the
design of monitoring programs emphasis should be on nonpoint source pollutants,
which generally will include: (a) sediments and associated sorbed materials eroded
from shale piles, construction sites, access roads, etc, (b) dissolved salts leached
from shale disposal sites, unlined catchment, and evaporation ponds, and
discharge of saline groundwaters, (c) trace substances, both inorganic and organic,
resulting from leaching of solid waste disposal piles or overland transport of air-
borne fallout materials during periods of high runoff (64,65).
The nonpoint source surface water monitoring effort will focus on instream
monitoring networks that incorporate sufficient sensitivity to detect very subtle
changes in water quality and flow patterns. The monitoring networks will include
stations on permanent streams as well as on all major tributaries draining areas of
mining and processing activities, disposal piles, evaporation ponds, and catchment
basins. This network includes washes and ephemeral streams that may transport
wastes during periods of heavy runoff, as well as intermittent and perennial
tributaries that may be receiving wastes from groundwater seepage or atmospheric
rainout, or whose flow patterns may be altered by consumptive water uses or mine
dewatering processes. Significant springs and seeps should also be included in the
monitoring network to determine if the quality or quantity of their flow is altered.
Because of the well defined drainage patterns in most of the oil shale region,
establishment of monitoring stations should be straightforward. Sampling stations
on potentially impacted tributaries will make it possible to identify the sources of
any changes detected in mainstreams. However, where large drainage areas are in-
volved, a rationale must be developed for placing the stations in specific locations.
Accidental Discharges—The major potential sources of accidental discharges to
surface water include failure of shale disposal piles or embankments around catch-
ment basins or evaporation ponds, and spills associated with the transport of
materials via pipeline, truck, or rail.
An integral component of the total monitoring program should include an early-
alert system for the detection of potentially stressed or faulty containment struc-
tures (ponds, dikes, embankments) or transport systems in the case of spills or
leaks. Such a system would signal the need for activation of appropriate monitor-
ing sites and provide sufficient lead-time for the implementation of contingency
measures to control, contain, or abate spills and accidental discharges.
Flow Reductions—Possibly of even greater concern than degradation of surface
water quality through the introduction of waste materials are the reductions in
flows that will undoubtedly accompany development. The industry will require
substantial quantities of water for processing, upgrading, dust suppression, irriga-
tion, and a host of associated activities. Since both surface and sub-surface waters
will be used, depending on the particular operation (the technology utilized and
water sources available), alterations of the hydrological regime are to be expected,
becoming more pronounced as the industry matures. Drawdown of the water table
as a result of mine dewatering will decrease the rate of recharge to streams. Diver-
sions, impoundments, and consumptive uses of surface waters will alter the
hydrology of surface drainages. It is impossible to forecast at this time what the
long-term impact of a maturing industry will be on the regional surface and
groundwater hydrological regimes because of the many unknowns associated with
the development of this new industry. Development of new technologies could
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substantially alter current projections of water requirements. However, assuming
current projected requirements are reasonably accurate, the developers should be
encouraged to return high quality water to aquifers and/or streams to minimize the
impacts of withdrawal.
Monitoring Approaches—
Monitoring approaches and procedures most suitable for application in surface
waters potentially affected by oil shale development and associated activities are
not well defined. Traditional surface water quality monitoring methods success-
fully applied in industrialized and urbanized areas of humid regions of the country
are not necessarily well suited for application in streams of semiarid regions, where
oil shale development is occurring. The many unknowns relating to the nature,
release potential, transport rates, and pathways of potential pollutants complicate
monitoring approaches and reduce the utility of conventional techniques. The
monitoring problem is further complicated by the high natural variability in water
quality and discharge inherent to surface drainages of the oil shale area.
The surface water monitoring design must be developed in close coordination
with the groundwater, terrestrial, and air monitoring networks. And a free ex-
change of information must be maintained throughout the existence of the pro-
gram. Since groundwater and surface water hydrological regimes are closely inter-
twined, a two-way exchange of information is essential to provide a total assess-
ment of qualitative and quantitative changes in the systems and to relate such
changes to causative factors. Similarly, meteorological data that provide informa-
tion on the nature, transport and fallout of airborne particulates are essential to
determine the distribution of such materials in the terrestrial environment and
subsequent transport to surface water.
Selection of monitoring components for application in surface waters of the oil
shale area must be based on the specific requirements and characteristics of the
drainages subject to impact. Network design consideration must include station
siting requirements, appropriate sampling frequencies, parameters of major and
secondary interest, sample collection, handling and in situ measurement
methodologies most appropriate for a particular situation, laboratory and field
analytical techniques that produce the required level of accuracy and precision,
data management procedures, and quality assurance safeguards for all phases of
the monitoring program. Aspects relating to sample collection, handling and
analyses, data management, and quality assurance are addressed in other sections
of this report. The remaining network design considerations are addressed below.
Station Locations—The distribution of sampling stations within a monitoring
network should reflect the particular objectives of the monitoring program. For ex-
ample, trend monitoring networks designed to detect changes in water quality or
flow for an entire drainage basin generally have stations located in the lower
reaches of major tributaries, on the mainstream (downstream from principal
sources of input), and in tributaries. Trend monitoring stations established to
detect spatial and temporal changes in water quality and in the stream hydrograph
should not be expected to identify the causes of such changes. Such monitoring
programs must rely on other work to identify pollution sources and associate in-
stream changes to causative factors (66).
For purposes of assessing and quantifying the contribution of surface water
pollutants generated by oil shale development activities, station siting requirements
are somewhat different from those of a traditional trend monitoring network.
Permanent stations should be established on major streams both upstream and
downstream from the confluences of potentially impacted perennial tributaries, as
well as on the tributaries themselves. In addition, permanent stations should be
established in washes and gulches that are designated as disposal sites for shale or
overburden or that are otherwise potentially impacted. Meteorological and ground-
water data should aid in the selection of stations upstream from the development
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sites in unimpacted stream reaches as well as in reaches potentially impacted by at-
mospheric fallout or by groundwater withdrawals.
Sampling Frequencies—All permanent stations established need not be sampled
at the same frequencies. Sampling of ephemeral tributaries and washes can, in
many instances, be restricted to periods of events such as rainstorms or sudden
snow melt, when transport potential is greatest. Optimally, mainstream stations
would be sampled at similar intervals and frequencies to assure the statistical valid-
ity and comparability of the data; however, it is not necessary to measure all
parameters during each sampling. For example, measurements such as
temperature, flow, pH, and conductivity, which lend themselves to in situ monitor-
ing with automated instruments, would be recorded continuously at mainstream
stations.
Sampling frequencies for such parameters as dissolved oxygen, selected
nutrients, major anions and cations, and inorganic and organic trace constituents
that require treatment in the field and/or analyses in a laboratory should be
established based on the natural variability in water quality, intensity of activities in
the area, and the stream hydrograph. Ideally, sampling frequencies for these
parameters would be greatest during periods of maximum variability in water
quality with less frequent sampling during more stable periods. In the semiarid oil
shale area, maximum variability in water quality is not necessarily coincident with
periods of maximum discharge; in fact, quite the opposite may be true. The periods
of greatest variability in water quality frequently occur during the late summer low-
flow period, when the assimilative capacity of the stream is minimal and when there
is a high frequency and intensity of localized thunderstorms, with subsequent
runoff and transport of easily credible and highly soluble substances to permanent
streams through washes and tributaries. In terms of total loading, the contribution
of such events may be relatively minor, but in terms of water quality criteria for
beneficial uses, the effects are frequently highly detrimental, particularly with
respect to biological impacts. Since much of the flow during the periods of peak
discharge is derived from snow-pack melt in the upper watershed, the concentra-
tion of potentially harmful substances is relatively low during this period, even
though the total stream burden is high. Bank and streambed scour, however, is
often greatest during the peak flow period, and enormous sediment loads, both
suspended and bedload, are characteristic of streams throughout the area during
peak flows. The combined effects of streambed deposition, scouring, and fre-
quently, rechannelization, are temporarily devastating to the bottom dwelling
macroinvertebrates and attached periphyton. Sampling of these communities
would ideally be conducted before peak discharge and again after communities
have re-established following a reduction in flow rates.
Daily suspended sediment measurements should be made at key stations during
the period of maximum discharge. Techniques are available for obtaining sus-
pended sediment from varying depths with fixed samplers as the hydrograph rises
and falls.
Methods for optimizing sampling frequencies for chemical and physical
parameters have been proposed by several workers (67-69). In each case, a large
amount of a priori knowledge is required to apply the sophisticated techniques used
to determine when to sample. A basic problem with the stratified sampling ap-
proach is that the highest variability in parameter concentration occurs at different
times for different parameters and at different stations. The practical considera-
tions of sampling logistics require either considerable compromise, large resources,
or both.
Stratified sampling is based on one other assumption—that parameter concen-
tration variability will continue to follow pre-established patterns. Pollutants
generated by oil shale development activities may or may not follow historical
distribution patterns. The environmental disturbances may be expected to follow
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more closely the level of mining or processing activity than hydrographic cycles. In
addition, stream flows may be subjected to manipulation through operation of
dams, diversions, discharges, etc. These manipulations impose additional elements
into the naturally occurring flow regimes and parameter concentration patterns.
Data may not presently be adequate to determine optimum sampling times ex-
cept for a few parameters such as temperature and conductivity. The method of
Sanders and Adrian (68) requires an extensive period of daily parameter records in
order to determine the harmonic components of variability. Such records are
generally unavailable, but an argument may be advanced for using conductivity to
estimate the variability of ionic constituents (66).
In view of the foregoing considerations, it is recommended that sampling initially
be conducted at fixed-time intervals until sufficient data have been compiled to
establish a statistically sound stratified sampling schedule. A fixed sampling inter-
val greatly simplifies logistics. The selection of an interval without a seven-day
component would help assure that the weekly work schedule of personnel will not
lead to biased data. (In addition, the time of sampling should not be consistently
the same; ideally it should be randomly distributed over the 24-hr period.) A samp-
ling frequency of 8 to 13 days would provide 25 to 50 samples per year for analyses
of chemical and physical parameters and should provide sufficient information to
allow the development of time-stratified sampling programs.
Selecting Parameters and Setting Priorities—Because of the numerous Federal,
State, and local water pollution control laws, regulations and associated monitor-
ing requirements applicable to the oil shale industry (Section 1 and Appendix D), it
is impossible to develop a single list of parameters for across-the-board application
to all potentially impacted surface waters. The following provides the rationale for
identification of parameters of concern along with prioritized listings of chemical,
physical, and biological parameters recommended for inclusion in surface water
monitoring programs.
Water quality parameters should be selected based on an analysis of the possible
pollutants and their toxicity, persistence, concentration, ease of analysis and iden-
tification, release potential, and present levels in receiving waters.
Special Problems and Concerns in Parameter Measurement. Detection of some
pollutants presents no problem and requires only a straightforward approach. For
example, suspended sediments, total dissolved solids, and turbidity will be clearly
indicated by major changes in solids loading of streamflow as a result of increased
erosion or runoff from raw or spent shale piles. Normal analyses for oil and grease
and for dissolved and suspended organic carbon can be used to detect spills and
leaks of oil and other organic materials. Fractionation of the dissolved organic car-
bon can be used to identify classes or origins of pollutants.
However, knowledge of organic compounds associated with oil shale and subject
to release to surface water as a result of industrial development is incomplete. The
extreme difficulty in conducting organic analyses has discouraged most researchers
and has largely limited monitoring efforts to measurement of organic carbon,
phenols, oils and grease and a few similar analyses. Thomas (66) summarized the
results of a study by Pellizzari (70) that reported organic substances found in proc-
ess water from oil shale based on analyses of six samples. Thomas listed maximum
concentrations of those compounds that occurred at an arbitrary level of 100 ppb
or greater (Table 3-22 in Section 3).
Pellizzari's methods provided for the analysis of volatile and semivolatile com-
pounds to ppb levels. The procedure was quantitative for volatile compounds with
solubilities of less than 2 percent in water and a boiling point of less than 220 °C
(428 °F), and for semi-polar compounds with solubilities equal to 10 percent and
boiling points equal to 150°C (302 °F). The technique was not quantitative for
highly water soluble compounds (e.g., acetonitrile, formaldehyde, etc.). The pro-
cedure for semivolatile compounds gave quantitative recoveries for organic acids,
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neutral compounds, and bases for compounds with boiling points greater than
60°C (140 °F) and less than 270 °C (518°F). Compounds with zwitterions (dipolar
ions) were not recovered and analyzed, nor were compounds with boiling points
greater than 275 °C (527 °F).
Of the compounds identified, phenols, dimethyl phenol isomer, cresole isomers,
acetone, benzene, and toluene are of specific concern. All are suspected carcino-
gens that have been identified as high priority EPA point source effluent toxic
pollutants. The cresole and phenols are of particular concern, since they have toxic
as well as carcinogenic properties and may occur in high concentrations.
Analyses for trace elements should be designed in accordance with possible
sources that can be defined. The elements fluorine and arsenic are of special
significance in large areas of the Piceance Basin. Fluoride is present in high concen-
trations in the deep aquifers; thus any surface water changes resulting from mine
inflow water reaching the surface through leakage from well reinjection systems,
holding reservoirs, etc., will be immediately apparent as an increase in fluoride
levels.
Arsenic is expected to volatilize in the oil shale retort and become enriched in the
shale oil. It must be removed from the crude shale oil before hydro-treating, but it
may become an air emission during the refining process (60). A number of in-
organic trace elements known to be associated with oil shale at varying levels are
listed in Table 3-19, Section 3.
Chemical and physical parameters. It is convenient to think of water quality
parameters as belonging to one of two broad categories: (a) specific constituents,
and (b) indicator parameters.
The first category is made up of those constituents that in themselves are poten-
tial pollutants and are directly measurable in waters. This group is represented by
substances identified as components of raw or retorted oil shale, overburden,
groundwaters, industrial or urban wastes, etc. that may be subject to mobilization
and release to surface waters. Examples of parameters in this group include (a)
dissolved, suspended, and settleable residues, both inorganic and organic, (b)
radioactive isotopes, (c) specific cations and anions, (d) pesticides, and (e) oil and
grease.
The second category includes those parameters that in themselves are not
pollutants, but whose measurement either provides a measure of pollution or en-
vironmental disturbance or are required for the interpretation of other water qual-
ity data. Examples of parameters in this group include dissolved oxygen, pH,
specific conductance, hardness, alkalinity, turbidity, temperature, and volume of
flow (discharge).
To identify and set priorities for those parameters most appropriate for monitor-
ing, potential pollutants were evaluated for their projected impacts on ambient
water quality, and on beneficial water uses in particular. Also included were those
indicator parameters whose ambient levels are a function or product of pollution or
environmental disturbance, or whose measurements are required to interpret water
quality data.
The following criteria were used to categorize and assign priorities to the
chemical and physical parameters. These criteria relate a given parameter to pro-
jected water quality in the Colorado River System and to specific beneficial water
uses. All recommended limits except those for radioactive substances are based on
National Academy of Sciences Drinking Water Standards (72). Radioactivity
criteria are based on EPA Drinking Water Regulations (73).
Criteria for priority A parameters:
1. The pollutant has (a) been reported in surface waters of the Colorado River
Basin at levels equaling or exceeding acceptable limits for beneficial water
uses and (b) is likely to have altered ambient levels in surface waters as a result
of activities associated with the development and operation of an oil shale in-
199
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dustry, to the point where further impairment of beneficial water uses will
result; or
2. The pollutant is (a) one for which water quality criteria must be established
for particular receiving waters based on tolerance levels of important, sen-
sitive species in those waters, and (b) one that is likely to have as a result of oil
shale development and operation activities, altered ambient levels in receiving
waters to the point where the biota may be adversely impacted; or
3. The pollutant is one whose measurement is essential for interpreting other
water quality data.
Criteria for priority B parameters:
1. The pollutant has been reported at levels in the Colorado River Basin that are
generally within acceptable limits with respect to beneficial water uses, but its
ambient levels in surface water could be altered by activities associated with
the development and operation of the oil shale industry, to the point where
impairment of beneficial water uses could result; or
2. The pollutant is (a) one of recognized significance in the aquatic environ-
ment, but one for which no water quality criteria have been established with
respect to ambient levels and beneficial water uses, and (b) it is one whose am-
bient levels in surface waters could be altered by activities associated with the
development and operation of an oil shale industry, to the point where im-
pairment of beneficial water uses could result.
Criteria for priority C parameters:
1. The pollutant is one for which no water quality criteria are established and
whose significance in terms of beneficial use criteria is largely unknown; but
its ambient levels in surface waters could be altered by activities associated
with the development and operation of an oil shale industry, with unknown
consequences for beneficial water uses; or
2. The pollutant is one for which adequate surface water quality data are
unavailable to characterize ambient levels in the Colorado River Basin, but it
has been identified as a potential pollutant subject to release to surface waters
by activities associated with the development and operation of an oil shale in-
dustry.
Physical and chemical parameters recommended for monitoring are summarized
by category in Tables 5-6 through 5-8. The form of each recommended parameter
is based on the available knowledge of activities and fates of pollutants in the
aquatic environments.
TABLE 5-6. PRIORITY A CHEMICAL AND PHYSICAL PARAMETERS
RECOMMENDED FOR MONITORING IN SURFACE
WATERS8
Parameters
Aluminum
Ammonia
Bicarbonates
Boron, dissolved
Chlorides, dissolved
Conductivity
Form in which constituent
is reported
Aluminum (Al), dissolved
Aluminum (Al), total recoverable6
Nitrogen ammonia (NH3 - N)
Bicarbonate ion (HC03)
Boron (B), dissolved
Chloride ion (CD, dissolved
Specific conductance
Units
Ml/'
MI/I
mg/l
mg/l
MI/I
mg/l
^mhos/cm
at25°C
200
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TABLE 5-6. (continued)
Parameters
Form in which constituent
is reported
Units
Copper
Cyanides
Fluorides
Hardness
Iron
Lead
Magnesium
Manganese
Mercury, total
Molybdenum, dissolved
Nickel, dissolved
Nitrogen, nitrate
Oil and grease
Oxygen
Oxygen demand, chemical
Pesticides
Phenols
Potassium, dissolved
Sodium, dissolved
Silica
Solids, dissolved
Solids, suspended
Sulfates, dissolved
Temperature
Turbidity
Water volume
Zinc
Copper ion (Cu), dissolved
Copper (Cu), total recoverable6
Cyanide (CN), total recoverable
Fluoride (F), dissolved
Hardness, total as CaCo3
Iron ion (Fe), dissolved
Iron (Fe), total recoverable13
Lead ion (Pb), dissolved
Lead (Pb), total recoverable6
Magnesium ion (Mg), dissolved
Magnesium (Mg), total recoverable
Manganese ion (Mn), dissolved
Manganese (Mn), total recoverable
Mercury (Hg), total recoverable6
Molybdenum ion (Mo), dissolved
Nickel ion (Ni), dissolved
Nitrate nitrogen (N03 -N)
Visible oil
Emulsified oils
Dissolved oxygen
Chemical oxygen demand (COD)
Organochlorine pesticides6'0
Phenolic compounds
Potassium ion (K), dissolved
Sodium ion (Na), dissolved
Silica, dissolved (Si02)
Silica, total (Si02)
Total dissolved (filterable) residue
Fixed dissolved (filterable) residue
Total suspended (nonfilterable) residue
Fixed suspended (nonfilterable) residue
Sulfate ion (S04), dissolved
Temperature
Turbidity
Discharge
Zinc ion (Zn), dissolved
Zinc (Zn), total recoverable
M9/1
mg/l
mg/l
mg/l
M9/I
mg/l
mg/l
ng/\
M9/I
M9/I
mg/l
Severity
mg/l
mg/l
mg/l
pig/1
mg/l
mg/l
mg/l
mg/l
mg/l
mg/l
mg/l
mg/l
mg/l
°C
NTUd
m3/sec
Modified from Reference 65.
To be measured in streambed sediments also (|jg/kg).
° Applies to consent decree protocol pesticides.
Nephelometric turbidity units.
Priority A parameters require intensive monitoring because: (1) very slight
changes in their ambient levels would render water unacceptable for specified
designated beneficial water uses, (2) changes in ambient levels would be indicative
of potentially deleterious changes in water quality characteristics, (3) and data are
required for the interpretation of other water quality data.
Priority B parameters require routine monitoring of a lower intensity than do
those in the priority A category because slight changes in ambient levels can be
201
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tolerated without exceeding established limits for designated beneficial water uses.
The measurement of parameters in this category should be in addition to those in
the priority A category, but at reduced frequencies.
Priority C parameters require periodic monitoring in addition to those in the A
and B categories to characterize water quality with respect to ambient levels of par-
ticular constituents and designated beneficial water uses.
Biological Parameters—
Biological monitoring has long been recognized as an effective tool for
evaluating the stability and environmental quality of ecosystems. Biological in-
TABLE 5-7. PRIORITY B CHEMICAL AND PHYSICAL PARAMETERS
RECOMMENDED FOR MONITORING IN SURFACE
WATERS3
Parameters
Form in which constituent
is reported
Units
Acidity, total
Alkalinity, total
Alpha, gross
Arsenic
Barium, dissolved
Beryllium, dissolved
Beta, gross
Cadmium
Calcium
Carbonates
Carbon dioxide
Chromium
t
Cobalt, dissolved
Lithium, dissolved
Nitrogen, nitrite
Nitrogen, total
Oxygen demand,
biochemical
Pesticides
Phosphorus, total
Phthalate esters
PH
Polychlorinated biphenyls
Radium 226, 228
Sediments, streambed
Selenium
Silver
Strontium 89, 90
Acidity, total as CaC03
Alkalinity, total as CaC03
Total alpha activity
Arsenic ion (As), dissolved
Arsenic (As), total recoverable
Barium ion (Ba), dissolved
Beryllium ion (Be), dissolved
Total beta activity
Cadmium ion (Cd), dissolved
Cadmium (Cd), total recoverable11
Calcium ion (Ca), dissolved
Calcium (Ca), total recoverable
Carbonate ion (C03)
Carbon dioxide (C02), dissolved
Chromium ion (Cr)c, dissolved
Chromium (Cr), total recoverable13
Cobalt ion (Co), dissolved
Lithium ion (Li), dissolved
Nitrite nitrogen (NO2 - N)
Total nitrogen (N)
Biochemical oxygen demand (BOD)
Organophosphate pesticides lb' dl
Total phosphorus (P-Total)
Total phthalate esters
mg/l
mg/l
pCi/l
M9/I
Mfl/l
Mfl/l
Mfl/l
pCi/l
MI/I
Mfl/l
mg/l
mg/l
mg/l
MS/I
Mfl/l
MI/I
MO/I
MO/I
mg/l
mg/l
mg/l
Mfl/l
mg/l
Mfl/l
pH Standard units
Total polychlorinated biphenyls
Radium 226, 228, dissolved
Radium 226, 228, total
Streambed sediments
Selenium ion (Se), dissolved
Selenium (Se), total recoverable
Silver ion (Ag), dissolved
Silver (Ag), total recoverable
Strontium 89, 90, dissolved
Strontium 89, 90, total
Mfl/l
pCi/l
pCi/l
—
MS/I
MB/'
Mfl/l
Mfl/l
pCi/l
pCi/l
202
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TABLE 5-7. (continued)
Parameters
Tin
Titanium
Tungsten
Tritium
Vanadium, total
Form in which constituent
is reported
Tin (Sn), total
Titanium (Ti), total
Tungsten ion (W), dissolved
Tungsten (W), total
Tritium in water molecules
Tritium, dissolved
Tritium, total
Vanadium (V), total recoverable
Units
MI/I
Mi/'
Ml/'
MI/I
Hydrogen3 units
pCi/l
pCi/l
Mi/I
a Modified from Reference 65.
To be measured in streambed sediments; also ^
c Both trivalent and trivalent plus hexavalent forms should be measured.
° Applies only to specific organophosphate pesticides.
vestigations are of special significance in water quality monitoring programs
because they offer a means for identifying areas affected by pollution and for
assessing the degree of stress for a relatively small investment. In terms of time and
money invested, biological monitoring in many situations provides one of the most
efficient approaches in evaluating the nature and extent of pollution-related distur-
bances in aquatic ecosystems. Aquatic organisms act as natural monitors of water
quality in that they respond in a measurable and predictable manner to stress in-
duced by most types of pollution. Since the composition and structure of aquatic
plant and animal communities are the result of all biological, chemical, and
physical interactions within the system, communities reflect the summation of all
internal and external influences affecting the system including antagonistic and
synergistic actions.
Macrobenthic invertebrates are particularly useful natural monitors of en-
vironmental quality in lakes and streams because of their sensitivity to changes in
environmental conditions, their stationary nature,.and the relative ease with which
they are sampled. Since macroinvertebrates as a group are relatively immobile, they
cannot seek relief from unfavorable conditions, even intermittent pollution input,
or other disturbances. This characteristic results in colonization by the more
tolerant or opportunistic forms, which, in the absence of competition and preda-
tion from more sensitive forms, may completely dominate the community.
Since aquatic organisms serve as continuous monitors of the environment, they
sometimes provide information that is not obtained by direct measurements of
water quality. Pollutants such as heavy metals and many organic compounds tend
to accumulate in the biota in far greater levels than are found in the water column
as a result of uptake and concentration both through the food chain and directly
from the water. Thus, an examination of tissue may reveal the presence of poten-
tially hazardous substances in the biota that were not detectable in the water. Resi-
dent fish species whose entire life cycle is spent in short stream reach or other
restricted habitats are especially useful for this purpose.
Biological monitoring should be incorporated into any monitoring program
designed to assess the impact of development and operation of an oil shale industry
on the freshwater ecosystem and water quality. Subtle changes in water quality
characteristics may be indicated by changes in the aquatic biota before they are
detected by physical/chemical monitoring procedures. Biological monitoring
should not be viewed as an alternative to physical/chemical monitoring, but rather
as a complementary tool for improving the efficacy of monitoring programs.
203
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TABLE 5-8. PRIORITY C CHEMICAL AND PHYSICAL PARAMETERS
RECOMMENDED FOR MONITORING IN SURFACE
WATERS8
Parameters
Acetone
Antimony
Benzene
Bismuth
Bromine
Carbon
Cerium
Cerium 144
Cesium
Cesium 137
Chlorine
Color
Cresole
Detergent builders
linear alkylate sulfonates
Dysprosium
Erbium
Europium
Gadolinium
Gallium
Germanium
Gold
Hafnium
Holmium
Iodine
Iridium
Lanthanum
Lutetium
Neodymium
Niobium
Nitrogen, Kjeldahl
Nitrogen, organic
Oils and grease
Osmium
Palladium
Pesticides
Form in which constituent
is reported
Acetone compounds
Antimony ion (Sb), dissolved
Antimony (Sb), total
Benzene compounds
Bismuth ion (Bi), dissolved
Bismuth (Bi), total
Bromine (Br)
Bromide ion (Br), dissolved
Organic carbon, dissolved
Organic carbon, total
Cerium ion (Ce), dissolved
Cerium (Ce), total
Cerium 144, total
Cesium ion (Cs), dissolved
Cesium (Cs), total
Cesium 137, dissolved
Cesium 137, total
Residual chlorine (CD, total
True color (platinum cobalt units)
Cresole compounds
LAS, total
Dysprosium (Dy), total
Erbium (Er), total
Europium (Eu), total
Gadolinium (Gd), dissolved
Gallium ion (Ga), dissolved
Gallium (Ga), total
Germanium ion (Ge), dissolved
Germanium (Ge), total
Gold(Au), Total
Hafnium (Ha), total
Holmium (Ho), total
Iodine ion (I), dissolved
Iridium (Ir), total
Lanthanum ion (La), dissolved
Lanthanum (La), total
Lutetium (Lu), total
Neodymium (Nd), total
Niobium (Nb), total
Kjeldahl nitrogen, total
Organic nitrogen, dissolved as N
Organic nitrogen, total as N
Hexane extractable substances6
Osmium (Os), total
Palladium (Pd), total
Miscellaneous pesticides0
Units
Mg/l
mg/l
mg/l
Mfl/l
Mg/l
Mfl/l
mg/l
mg/l
mg/l
mg/l
Mfl/l
Mfl/l
pCi/l
Mfl/l
Mfl/l
pCi/l
pCi/l
mg/l
PCU
MO/'
mg/l
Mfl/l
Mfl/l
Mfl/l
Mfl/l
MS/'
Mfl/l
MS/"
Mfl/l
Mfl/l
Mfl/l
MO/"
mg/l
Mfl/l
Mfl/l
Mfl/l
Mfl/l
MB/'
Mfl/l
mg/l
mg/l
mg/l
mg/kg
M9/1
M9/1
Mfl/l
204
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TABLE 5-8. (continued)
Parameters
Form in which constituent
is reported
Units
Phosphorus
Platinum
Plutonium 238, 239
Praseodymium
Rhenium
Rhodium
Rubidium
Ruthenium
Ruthenium 106
Samarium
Scandium
Strontium
Tantalum
Technetium
Tellurium
Terbium
Thallium
Thorium
Toluene
Uranium
Ytterbium
Yttrium
Zirconium
Phosphorus, total dissolved
Platinum (Pt), total
Plutonium 238, 239, dissolved
Praseodymium (Pr), total
Rhenium (Re), total
Rhodium (Rh), total
Rubidium ion (Rb), dissolved
Rubidium (Rb), total
Ruthenium (Ru), total
Ruthenium 106, total
Samarium (Sm), total
Scandium ion (Sc), dissolved
Scandium (Sc), total
Strontium ion (Sr), dissolved
Tantalum (Ta), total
Technetium (Tc), total
Tellurium (Te), total
Terbium (Tb), total
Thallium ion (Tl), dissolved
Thallium (Tl), total
Thorium (Th), total
Toluene compounds
Uranium ion (U), dissolved
Uranium (U), total
Ytterbium ion (Yb), dissolved
Ytterbium (Yb), total
Yttrium ion (Y), dissolved
Yttrium (Y), total
Zirconium ion (Zr), dissolved
Zirconium (Zr), total
Ml/'
Ml/'
pCi/l
M9/I
Ml/'
Ml/'
Ml/'
Ml/"
MI/I
pCi/l
M9/I
MI/I
MI/I
MI/I
Mi/I
Ml/'
MI/I
MI/I
Ml/"
M9/I
M9/I
M9/I
MI/I
MI/I
MI/I
Ml/'
Ml/'
Ml/I
Ml/'
MI/I
j; Modified from Reference 65.
To be measured in streambed sediments only.
c Applies only to specific pesticides.
Selecting and setting priorities for biological parameters were accomplished by
considering both the components of the aquatic community most responsive to
stress, and the measurement technique most appropriate for directly or indirectly
measuring such response. The following criteria were used to categorize and assign
priorities to the biological parameters.
Criteria for priority A parameters:
1. The variable exhibits a predictable and measurable response in the aquatic
community to the type of stress conditions anticipated as a result of expected
pollutants and habitat alteration associated with oil shale development ac-
tivities, and
2. The variable is one for which currently available analytical and measurement
techniques are adequate to provide useful information.
Criteria for priority B parameters:
1. The component is a member of the aquatic community associated with
205
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specific habitats that may be affected by particular conditions induced by
development of an oil shale industry and associated activities.
Priority A biological parameters are recommended for routine monitoring in any
basic water quality monitoring program designed to assess the impact of oil shale
and associated development on aquatic ecosystems. However, all priority A
parameters need not be monitored at the same frequencies.
Sampling to determine bioaccumulation of toxic and hazardous substances in
fish and macroinvertebrate tissue should be conducted annually at key mainstem
stations. Because uptake may vary considerably between species and age classes, at-
tempts should be made to obtain the same species and size classes of fish and
similar macroinvertebrate communities during each sampling. Fish and macro-
invertebrates selected for analyses should be representative of resident species in
the area.
Since the costs of such analyses are high, it is recommended that three or four
whole fish be homogenized and analyses made on composite samples. Similarly,
tissue analyses of macroinvertebrates should be conducted on homogenized com-
posites of several samples.
Annual collection of fish should be adequate for the analyses indicated in Table
5-9. In addition, several specimens of two or three common representative resident
nongame species (dace, darters, etc.) should be collected and preserved for future
analyses. It is hoped that techniques for identifying tumor development or other
evidence of carcinogenics will be developed in the near future. These samples
would provide a reference collection for these types of examinations and other
analyses.
Macroinvertebrate collection for community analyses should be made three
times yearly (spring, late summer, late fall) using standardized collection tech-
niques appropriate for each locale. To assure adequate characterization of bottom
fauna communities, a minimum of 1,000 organisms should be obtained at each sta-
tion during each collection period.
Periphyton samples should be collected two or three times yearly using standard-
ized techniques, including artificial substrates and natural rock scrapings. Analyses
should include dry and ash-free determination for biomass estimates, species iden-
tification and counts and chlorophyll analyses.
Priority B biological parameters need not be routinely monitored unless a
specific problem is encountered or suspected in a particular habitat. For example,
phytoplankton and macrophytes would not normally be monitored in western
streams, where primary productivity is attributable mainly to periphyton and
aquatic vascular plants are typically scarce. However, in impoundments, measure-
ment of both phytoplankton and aquatic macrophytes may be of considerable in-
terest because of eutrophication and associated problems.
Fecal coliform and fecal streptococci bacteria are useful indicators of domestic
or animal wastes entering waterways, but they would not normally be monitored in
a routine program unless the potential for such contamination is suspected. For ex-
ample, anticipated increases in human population densities in small towns,
establishment of temporary dwellings in rural areas, etc. would be sufficient reason
to initiate measurement of these parameters. In such instances probably seasonal
sampling would be sufficient to establish baseline data. But frequency may have to
be increased to monthly as the population increases.
Measurement of priority B parameters (Table 5-10) on fish would not normally
be performed unless a specific problem (stunted fish, tainting of flesh, etc.) were
detected. The intensity and duration of such investigations would need to be deter-
mined on the basis of the severitv of the problem and initial test results.
Groundwater Monitoring Methodology
Monitoring of groundwater quality should be an extension of the environmental
assessment and control technology evaluations performed as part of the original
206
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TABLE 5-9. PRIORITY A BIOLOGICAL PARAMETERS RECOMMENDED FOR MONITORING IN SURFACE WATERS3
Community
Parameter
Analysis
Units
Macroinvertebrates
Periphyton
Fish
Counts and identification
Biomass
Community composition and diversity
Toxic substances in tissue
Counts and identification
Biomass
Community composition and diversity
Chlorophyll a
Counts and identification
Biomass
Toxic substance in tissue
Community composition
Nb/unit substrate area or
unit sampling effort (time) or
unit sample
Total wt./unit substrate area
(ash-free) or
unit sampling effort
n°/taxon
Sd/N
Wt. substance/unit tissue wt.
N/unit substrate area
Diatom species proportional count
Total wt./unit substrate area
(ash-free)
n/taxon
Wt./substrate area
N/unit sampling effort
Total wt./unit sampling effort
(wet wt.)
Wt. substance/unit wt. tissue
Species list/sample
N/m2
N/min
N/sample
g/m2
g/min
n/ith taxon
S/N
M9/9
N/cm2
percent
mg/m2
n/ith taxon
jug/cm2
N/sample
g/sample
mg/g
f* Modified from Reference 65.
Total numbers.
c Number of individuals.
Number of taxa.
-------
TABLE 5-10. PRIORITY B BIOLOGICAL PARAMETERS RECOMMENDED FOR MONITORING IN SURFACE WATERS3
Community Parameter
Phytoplankton Counts and identification
Chlorophyll a
Community composition
and diversity
Fish Flesh tainting
Growth rate
Condition factor
1
00 Macrophytes Species identification
and community association
Bacteria Fecal streptococci
Fecal coliforms
Analysis
Nb/unit volume
Total wt./unit volume
n°/taxon
Sd/N
Taste test panel
Age/ length by species
Length/weight
Areal coverage and
community
N/unit volume
N/unit volume
Units
N/ml
^g/ liter
n/ith taxon
S/N
Rating scale
yr/mm
105 x wt(gm)
length (L)3
Map of species
association
N/100ml
N/100ml
^ Modified from Reference 65.
Total Numbers.
0 Number of Individuals.
Number of Taxa.
-------
planning and design of an oil shale facility. As such, it should provide for:
1. Detection and delineation of groundwater pollution before the pollution
reaches streams or points of groundwater use;
2. Detection of potential pollution from activities that by design are not sup-
posed to contribute to groundwater;
3. Definition of any possible pollution to groundwater systems before the
pollutants reach points of discharge into surface water;
4. Verification that injection well systems are functioning to prevent pollution to
sources of usable-quality groundwater or to surface water;
5. A data bank that can be used in the future assessment and revision of
technology control programs on environmental issues.
It should be emphasized that for a monitoring program to achieve the above ob-
jectives, the focus must be on identifying the pollution sources, specific pollutants,
and their respective mobilities in the subsurface environment. It should also be
recognized that the drilling and sampling of observation wells will be needed to
field verify the conclusions drawn from indirect monitoring activities, to provide
for compliance activities, to determine long-term trends in water quality and
changes in water levels, and to ascertain the effectiveness of operational programs
such as subsurface waste injection and grouting programs for abandoned in situ oil
shale chambers.
A groundwater monitoring methodology should fulfill the following require-
ments when properly applied in an oil shale area (74):
Identification of potential pollutants
Definition of hydrogeology and groundwater use
Study of existing groundwater quality
Evaluation of infiltration potential of wastes at the land surface
Evaluation of mobility and attenuation of pollutants in the unsaturated and
saturated zones
Priority ranking of sources and causes of pollution, based on:
a. Mass of waste, persistence, toxicity, and concentration
b. Potential mobility
c. Known or anticipated harm to water users
Selection and implementation of the monitoring program
Monitoring guidance for solid wastes in oil shale areas is presented in the follow-
ing subsection on solid waste monitoring. The reader is encouraged to examine this
section, because a similar approach can be taken for developing monitoring for
liquid-holding reservoirs, storage ponds, and other installations that could result in
infiltration of pollutants into the subsurface (75).
Near-Surface Aquifers—
As mentioned, monitoring wells will be needed to supply verification data.
Guidelines for monitoring methodology published by EPA (74,76) describe how
the wells should be located, but because the subject is most important to ground-
water quality monitoring with respect to oil shale, some key recommendations are
presented here.
Because of the longer time scale involved in groundwater movements (weeks or
months may be required to move relatively short distances), the location of
monitoring sites is much more critical than for surface waters if a pollutant is to be
detected before a significant buildup occurs in the system. Site selection must be
based on a general knowledge of the area hydrology as well as on an analysis of the
possible pollution sources. Haphazard location of monitoring wells is certain to
result in excessive costs and inadequate coverage. Monitoring wells to be effective
must be placed down the groundwater hydraulic gradient of possible pollution
209
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sources. Within local valleys, wells completed in alluvium should be placed
downstream of sources. Determining the number of wells required is not as simple
as determining the number of stream gauging stations. Because of its small lateral
dimensions, a stream may be considered well mixed, so that only a single sampling
point is needed. Water in an alluvial aquifer is far from well mixed, and samples
may be necessary at more than one point along a line perpendicular to the direction
of flow. The further downstream the wells are placed from a suspected source, the
fewer wells are required. However, greater downstream distances imply longer time
intervals before pollution can be detected. As a general guideline, one shallow
monitoring well should be placed within 30.5 m (100 ft) down-gradient of each
reinjection well. Monitoring wells will also be placed a short distance downstream
from each reservoir, raw shale pile, and spent shale pile. These locations should be
as near as possible to the center of the groundwater drainage pattern, and they
should be no farther downstream than the intersection with the next larger
tributary branch. For wide sources, more than one well should be planned. Well
construction should be such as to allow sampling from different depths within the
saturated interval.
The preceding discussion relates to horizontal variations of water quality in a
shallow aquifer. Many of the same factors that cause horizontal variations act to
cause vertical variations in the water quality of an aquifer. Where significant ver-
tical variations have been determined or may be strongly suspected as being likely
to occur, monitoring wells should be constructed so that samples can be withdrawn
from different parts of the vertical section. This should mean that wells will be con-
structed at different depths in an aquifer. Some would produce from the upper part
while others produce from the lower part. Of course, such well completion would
depend on the thickness of the saturated zone of an aquifer.
Sample collection from monitoring wells should be performed by pumping to
produce a sample that is representative of the aquifer water in the vicinity of the
well. Whenever possible the amount of water pumped (or removed if sampling is by
a method other than pumping) from the well prior to actual sample collection
should be about three times the volume of water estimated to be standing in the
well prior to start of pumping.
Selection of chemical parameters to monitor should be based on hydrological
and geochemical considerations as well as the nature of the potential pollution. The
same general considerations apply as for surface water. Sediment, of course, will
not be a factor in groundwater.
Deep Aquifers—
Determinations of water quality in deep aquifers of the Green River Formation
should be made in the vicinity of dewatering activities related to underground oil
shale mines and in situ retorting, as well as in the areas of influence of injection
wells. Monitoring of dewatering activities should be performed routinely. In most
cases, the necessity of drilling special monitor wells can be greatly reduced by
monitoring for water quality and water-level fluctuations in existing dewatering
wells and in wells that have been drilled for future dewatering (to take care of
dewatering needs as mining operations expand).
In mine dewatering, the sampling should emphasize the determination of salinity
and total dissolved solids. Once the sampling program is established, samples
should be collected about once monthly, or perhaps quarterly, depending on the
continuity of the dewatering activities. Considerable water should be removed
from inactive dewatering wells and wells that serve only for monitoring just before
samples are collected. Continuous water level records should be obtained from key
nonpumping wells so that relationships among changes in hydraulic gradients,
pumping depths, and water quality can be established.
Monitoring of in situ retorting operations (especially the modified in situ opera-
tions) will be similar in some respects to monitoring of deep mines. However, the
210
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situation will be more complex from certain standpoints. For example:
The subsurface leaching of spent shale in the retort chambers must be addressed;
Rates and pathways of movement of dissolved pollutants in aquifer zones af-
fected by the retorting must be considered;
Changes in hydraulic characteristics of the subsurface must be factored into the
monitoring program;
Impacts of related possible occurrences (such as subsidence) should be ad-
dressed.
Establishment of a monitoring program should consider these issues in view of
the existing hydrogeologic framework. It appears that monitoring designs will be
on a case-by-case basis until more experience is obtained. However, considerable
guidance on the inorganic and organic constituents to be analyzed can be gained
from the laboratory studies concerning leaching of retorted shales.'This matter is
discussed in considerable depth later in this section under the subsection on
monitoring of solid wastes.
Monitoring of groundwater quality in the Green River Formation is very difficult
because groundwater flow (direction and rate of movement) is controlled by frac-
ture and fault systems. These systems produce a physical setting of heterogeneous
porosity. As a consequence, attempts to apply conventional concepts of monitor-
well siting, well construction, and sampling procedures are likely to be less than
completely successful. Most conventional concepts were developed for application
to sand aquifers, which have hydraulic conditions approaching homogeneity and
which have, as a result, a groundwater flow that is perpendicular to the equipoten-
tial lines of measured head in the aquifers. Because this matter appears to be of ma-
jor significance to monitoring the environmental impacts of development of the
Green River Formation, the following discussion (76) is included to aid the reader
in understanding the situation and to provide suggestions for appropriate monitor-
ing approaches. Because the conditions in the Piceance Creek Basin are thought to
be generally typical of the entire Green River Formation, this area is used as the set-
ting for the discussion.
Groundwater flow in the Piceance Creek Basin occurs in several complex systems
of fractures and faults (77). The evaluation of a fractured-rock flow system is
generally much more complicated than assessment of a granular, porous media
type of aquifer system. In fractured-rock systems, even defining the direction of
flow may not be straightforward. Generally, the direction of flow and the flow gra-
dient in groundwater systems are identified by measuring the head (or water level)
in a set of wells and estimating lines of equal head. Flow, then, is perpendicular to
these equipotential lines (Figure 5-2). However, flow in fractured rock is along
fractures, and these flow paths can provide a flow direction that is nearly perpen-
dicular to that which may be estimated from simple observation of head levels
(Figure 5-3). Using this illustration (Figure 5-3), placing a well at Point B to
monitor the effects of an injection well or other waste source at Point A would
clearly fail to produce data that address the defined information requirements. The
need for detailed hydrogeologic evaluation is thus an integral part of the monitor-
ing design methodology.
The aquifer systems in the Piceance Basin include a series of horizontal fracture
sets very irregularly interconnected by vertical fractures and faults. The system has
commonly been portrayed as including two aquifers separated by the rich oil shale
beds of the Mahogany Zone. In actuality, the irregular spacing of both vertical and
horizontal fractures, the appreciable variability of hydraulic properties among
these fracture sets and the varying degrees to which halite and nahcolite minerals
have been leached from different zones create numerous distinct aquifer units.
Where wells are located and where they are perforated (open to water-bearing
zones) have a significant influence on the data collected. This is true for data on
both aquifer characteristics and groundwater quality.
211
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400
395
HEAD ELEVATION
390 385 380 375
— EQUIPOTENTIAL
— FLOW (ORTHOGONAL)
N)
N>
Figure 5-2. Groundwater flow net in homogenous aquifer.
(Source: Reference 76)
-------
INFERRED DIRECTION
FLOW DIRECTION
FRACTURES
GROUND WATER CONTOURS
B— MONITORING WELL
A— INJECTION WELL
Figure 5-3
(Source: Reference 78)
between true direction °f
drawing
-------
An example is two wells that are located close together and that are perforated
over exactly the same interval. The perforated interval contains two fractured
strata of equal hydraulic conductivity (Figure 5-4). One strata contains abundant
saline minerals, and the other has few. One well intersects a fracture in the upper
strata but none in the lower (saline) strata, whereas the other intersects a fracture
only in the lower strata. Water sampled from these two wells provides drastically
different water quality data in spite of their proximity and construction similarity.
This situation may be further complicated by varying permeabilities of different
strata. Some fine-grained, high-organic-content strata are resistant to fracturing
and may form effective aquitards. This situation can result in different head levels
between layers and mixing of highly different quality waters in interconnections
such as well bores. As an example of how well completion (and recompletion) can
affect water quality data, consider the data reported in Table 5-11 for Tract C-b
(79).
These wells had initially encountered and been open to a highly saline water zone
that apparently had a higher hydrostatic head than the less saline overlying aquifer
zones. Thus, water collected from these overlying zones was affected by the inter-
connection. Recompletions were undertaken to isolate these different water quality
zones.
Also, the intervals of completion and perforation may affect water level data.
For example, on Tract C-b, an apparent mound of water in the center of the tract
may be due to data from a well (SG-6) completed over a small segment of the
aquifer zone. If this interval has a high head, then this well will show a greater head
level than other wells in the area that are perforated over a wider zone and thus ex-
hibit a more average head.
Injection Wells—
Indications are that injection wells will be used to a considerable extent for
disposal of wastewaters, especially the water from dewatering operations. Since
these wells most likely will be covered by permits from State-level regulatory agen-
cies, some monitoring requirements will be specified in the permits. However, the
adequacy of such specified monitoring should be evaluated in terms of the overall
monitoring needs in an area of development. For information on monitoring of in-
jection wells, the EPA report, Monitoring Disposal-Well Systems, (81) is recom-
mended. The following summarizes the contents of that report.
A prerequisite to the monitoring of injection wells is a knowledge of the
hydrogeologic framework of the area. An estimate of the characteristics of the sub-
surface environment can be made before drilling a well, based on projections of
data from outcrops, previously drilled wells, and possibly surface geophysical
studies. A much more accurate knowledge of the local subsurface environment is
obtained when a well is drilled and tested. Data obtained from a well are based on
rock and fluid samples, geophysical logs, and pumping or injection tests.
When the characteristics of the subsurface environment have been estimated or
determined, the response to wastewater injection can be predicted with reasonable
accuracy. Such predictions are essential to monitoring because they provide a
baseline of expected performance, including rate of pressure buildup and rate and
direction of travel of injected wastewater.
The principal means of injection well monitoring is by monitoring of the well
itself. The wells provide more protection than is commonly realized because the
well is, in most cases, the most likely source of escape for injected wastewater.
Periodic inspection and testing of injection well facilities complements continuous
monitoring of well performance and should prove helpful in detecting deteriora-
tion of these facilities before failure.
Monitoring wells can be used for several purposes; they may be constructed in
the injection aquifer, in or just above the confining beds, or in any aquifer that
could be impacted by the injection operation. Local geology and hydrology, the
214
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LOW TDS
WATER WELL
HIGH TDS
WATER WELL
GROUND SURFACE
UPPER FRACTURE STRATA,
SALINE MINERALS SCARCE
LOWER FRACTURE STRATA,
SALINE MINERALS PRESENT
Figure 5-4. Fractured rock aquifer system yielding water of varying quality, depending on location and perforation of wells.
(Source: Reference 80)
-------
TABLE 5-11. EFFECTS OF WELL RECOMPLETION ON WATER QUALITY
Original well
designation
SG-11, string 1
SG-10
SG-17, string 1
IDS before
recompletion
ppm
39.000
42,000
28,000
IDS after
recompletion
ppm
16,000
2,800
4,300
New well
designation
SG-11, string 1R
SG-10R
SG-17, string 1R
waste being injected, and economics are all factors in determining the need for and
location of monitor wells. The nature of the waste being injected will also deter-
mine the depth of monitoring needed and what analyses should be conducted on
collected samples.
Other types of monitoring include surface geophysics, sampling of springs,
streams, and lakes, and monitoring to record any seismic events that might be
related to operation of the injection well.
Quality Control and Assurance—
Quality control procedures are implemented as part of a monitoring program to
insure the reliability of the data collected. Since monitoring data are used as the
basis for various decisions (e.g., determining compliance with regulations or need
to implement environmental control measures), quality control procedures for
both field and laboratory segments of the monitoring programs are essential. In ad-
dition, quality assurance proceedings are implemented to provide documentation
of the quality control efforts.
Quality control activities included as part of the field monitoring and sample col-
lection include the following:
1. Instrument calibration (e.g., use of proper standards, proper number of stan-
dards, and appropriate frequency of recalibration);
2. Use of appropriate sample collection procedures (collection procedures for
the sampling of wells are presented earlier in this section):
a. Use of appropriate bottle type (e.g., clear glass, dark glass, sterile bottles,
PVC)
b. Measurement of conductivity, pH, etc., during pumping of wells for
sampling to obtain representative samples
c. Use of proper field processing and preservation method (e.g., filtration,
addition of chemical preservatives, and cooling)
d. Use of proper packing and shipping procedures when sending samples to
an analytical laboratory
3. Proper training of personnel involved in field activities, including actual data
collection activities and quality control and quality assurance procedures such
as the use of replicate and spiked samples.
Standard Water Analyses
The following is a list of surface water, groundwater, and process water quality
parameters for whose measurement EPA-recommended methods are emphasized
(82):
pH, biochemical oxygen demand (BOD), chemical oxygen demand (COD); total
suspended solids (TSS), hardness, acidity, alkalinity, CO2, dissolved oxygen
(DO), silica, phenols, carbon, and nitrogen as ammonia, ammonium, and
organic nitrogen.
216
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Cations: arsenic, aluminum, boron, barium, beryllium, cadmium, calcium, cop-
per, chromium, iron, lithium, mercury, magnesium, manganese, lead, nickel,
potassium, selenium, silver, sodium, strontium, vanadium, zinc.
Anions: chloride, cyanide, fluoride, iodide, sulfate, sulfide, bicarbonate, car-
bonate, phosphate.
Analytical Instrumentation—
Figure 5-5 shows the elements that several instruments can measure. See Quinby-
Hunt (83) for an additional comparison of instrumental analyses of metals in
water.
Presently, atomic absorption spectroscopy is the most accurate and cost-
effective analytical tool available for quantitative analysis of most elements. Con-
sequently, it is the most commonly used technique for elemental analysis and is the
EPA-approved method for analysis of metals in water. However, it has one very
important disadvantage: it can only be used to test for one element at a time. A
number of techniques provide data on several elements simultaneously and are
more rapid than AAS if data on a variety of elements in many samples are needed.
Some multielemental techniques are x-ray emission, spark-source mass spec-
trometry, neutron activation analysis, and inductively coupled plasma emission
spectrometry. As part of an evaluation of these multielement analysis techniques
applied to environmental analytical problems, the latter three techniques were used
to analyze effluent samples from pulp mills. The samples were characteristic of ef-
fluent samples having high organic carbon and high alkali content (similar to the
Omega-9 retort water samples used in an interlaboratory comparison study dis-
cussed later in this section). The pulp mill effluent sample analysis emphasized
comparison of the three techniques with AA analysis when applied to the 13 EPA
consent-decree elements (antimony, arsenic, beryllium, cadmium, chromium, cop-
per, lead, mercury, nickel, selenium, silver, thalium, and zinc). No single multiele-
ment technique was applicable for all of the consent-decree elements at the 1-mg/l
(8.34x10"' Ib/gal) level. Spark-source mass spectrometry (SSMS), however, was ap-
plicable at this level to all consent-decree elements except mercury. Mercury was
apparently best determined by cold-vapor AA at levels of less than 0.1 mg/1
(8.34x10"'° Ib/gal). In general, the SSMS results agree reasonably well with the
other techniques, considering the attendant problems of sample inhomogeneity
and variations in both sensitivity and sample handling from one technique to the
other (84).
Inductively coupled plasmas suffer from numerous chemical interferences. Low
pressure plasmas have been employed in an attempt to reduce these interferences;
however, they have poor reproducibility, produce varying degrees of ionization
through the plasma, and are susceptible to interferences (82). The technique is
highly sensitive, and practical application to total metal determinations requires
careful analytical work. Over 25 elements per water sample can be analyzed (see
Figure 5-5) at about a third of the cost for flame AAS. Quantitative data for
samples of complex matrices were in good agreement with flame AA spec-
trophotometric results for each element investigated (85).
A discussion of instrumental analysis of oil-shale-type waters is contained in Fox
et al. (86). The water was the Omega-9 water, from the 1976 Rock Springs Site 9
true in situ oil shale combustion experiment, conducted by the Laramie Energy
Technology Center. "The chemical composition of this sample is specific only to
itself and is not necessarily representative of in situ oil shale waters in general.
Nevertheless, the analytical problems encountered in the analysis of this sample are
typical of these waters" (86). Approximately 63 parts of ground water were mixed
with one part of combustion plus dehydration water. The chemistry of this specific
water is dominated by an alkaline pH and the presence of high levels of organic and
inorganic carbon, nitrogen, and sulfur as well as sodium and chloride. The high
levels of organic and inorganic carbon, nitrogen and sulfur are typical of oil shale
217
-------
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-------
process waters, whereas the high levels of sodium and chloride are atypical of the
waters and probably originated from groundwater intrusion. The neutron activa-
tion results for three out of four laboratories were consistently accurate. The x-ray
fluorescence (XRF) and neutron activation analysis (NAA) (excluding one labora-
tory's results) were the most consistent and accurate of the instrumental techniques
evaluated. Spark-source mass spectrometry (SSMS) detected more elements than
any other techniques evaluated and consistently had the lowest detection limit.
However, it had a high coefficient of variation (63 percent). The single element
techniques, AAS and proton-electron spin spectrometerry (PES) produced consis-
tent and accurate results. Atomic absorption spectroscopy was most frequently
used to measure As, Ca, Fe, Mg, K, Se, Na, and Zn.
Intercomparison studies of instrumental techniques and aqueous samples are
complicated by the problems of long-term sample stability and low elemental con-
centrations. Extensive sample preparation is often required. The preparation pro-
cedures can introduce uncertainties into the results in addition to the usual in-
strumental uncertainties. Some of these problems are discussed later in this section.
The elements measured with the best accuracy (CV F20 percent) in the Omega-9
study were Na, U, Br, Cl, F, W, V, and Zn. The elements measured poorly (CV
F50 percent) were Al, La, Li, Hg, Sn, Ti, P, Si, Cd, Co, and Se. The elements most
frequently detected were As, Ca, Fe, Mg, Se, Na, and Zn. A range was reported for
Al, La, Li, Hg, Sn, and Ti. These variations are probably due to matrix in-
terferences or sample handling and preparation methods. Since all of these
elements except La are environmentally significant, work should be directed at
discovering the source of the variability and correcting it. Those elements that were
looked for but not detected by more than one method were Be, C, Nd, Sm, Eu, Tb,
Dy, Yb, Lu, Ru, Rh, Pd, In, Os, Ir, Pt, Au, TI, Bi (86). Most of these elements oc-
cur at low levels in oil shale and, although processing may change solubilities,
should exist at very low levels in the process water or would be relatively insoluble
at pH 8. In addition, except for Bi and Be, none of these elements has previously
been of interest environmentally, and thus analytical techniques have not been
refined to detect low levels of them in complex aqueous matrices. Pb, Be, and Bi
were either below the detection limit of all techniques used or were detected only by
one participating lab. These elements are environmentally significant, and more
sensitive techniques should be developed to detect them in this type of matrix. The
instrumental methods are relatively free of interferences, with the exception of the
high sodium concentration. Spark-source mass spectrometry consistently produced
the lowest detection limits but had the poorest precision of all instrumental
methods evaluated. Both XRF and NAA produced precise and accurate results.
Atomic Absorption (AA) was successfully used to measure the elements Ca, Mg,
Fe, Na, Si, As, K, Se, and Zn (86).
Analytical Problems and Interferences—
The Omega-9 study demonstrated that standard analytical methods cannot be
used to determine most water quality parameters in complex waters such as oil
shale process waters. Methods specific to each type of water need to be developed
and published. Instrumental methods generally produce more accurate results, as
these encounter fewer interferences than chemical methods. However, significant
variation and error can result from differences in sample preparation and the fact
that most of these techniques produce precision data for a subset of the total set of
elements reported. Extensive experimental work is required to develop analytical
methods for the routine measurement of cyanide, COD, phenols, orthophosphate,
solids, and sulfide in this type of water. Existing methods for the measurement of
sulfate, inorganic carbon, ammonia, and some sulfur species may not be adequate
and may require additional laboratory testing (86).
Cyanide, if present, occurred at low levels in the samples. The primary sulfur
species identified to date are thiosulfate, sulfate, tetrathionate, and thiocyanate.
219
-------
From an analytical standpoint, sulfur species may interfere with other chemical
measurements, cause the precipitation of elemental sulfur on acidification, and
result in sample instabilities from bacterial growth. Environmentally, some of these
species are significant from a toxicity standpoint, and others may interefere with
wastewater treatment processes. Little work has been done on the organic nitrogen
and carbon species present in the Omega-9 water. However, the primary inorganic
carbon and nitrogen species are, respectively, HCOj and CO* and NHJ. The high
levels of these inorganic species result in low values for the measured TDS (see
Solids discussion) and present a difficult waste treatment problem.
Many of the analytical techniques investigated in the Omega-9 study were inade-
quate for the analysis of complex matrices such as oil shale process waters. Each
method should be evaluated on a case-by-case basis. Although many of the wet
chemical techniques evaluated gave reproducible results, the accuracy of measure-
ment is poor because of interferences. This is true for cyanides, phenols,
phosphorus, sulfide, sulfate, COD, solids, and COj.
The primary interferences for wet chemical measurements are high concentra-
tions of sulfur, carbon and nitrogen species, the presence of strong color and
emulsified oil and grease, and a diversity of organic compounds. Carbon, nitrogen,
and sulfur species combine with many of the reagents used, producing erroneous
results. The presence of color and oil and grease interfere with some colorimetric
and electrode measurements. This type of interference affects both the precision
and accuracy of measurement of F~, conductivity, pH, alkalinity, CO?, HCOj,
PO;, phenols, and CI~. The precision obtained for many of the water quality
parameters using the same method in different laboratories is poor and generally
outside of quoted precisions (82,87). This is true for COD, phenol, inorganic and
organic carbon, conductivity, ammonia, and sulfate, probably because of dif-
ferences in pretreatment selected by the individual laboratories to mitigate suspect
interferences, and because of the presence of color, oil, and grease, which interfere
with colorimetric and electrode methods. The determination of HCO;, COj, NHJ,
HS~, and other species depend on equilibrium calculations. The ionic strength is so
high that the usual assumption of infinite dilution is not valid. Laboratory
measurements of appropriate equilibrium constants need to be made so these
species can be accurately determined. A number of analytical problems are dis-
cussed below (86).
Chlorine—Typically, instrumental methods measure total chlorine and chemical
methods measure the chloride ion. The mercuric nitrate method is recommended in
Standard Methods (55) and by EPA (82) for the analysis of chloride in waters.
However, in the presence of other constituents that react with mercury, the method
gives high results.
Organic Carbon—The data indicate that there is an analytical problem
associated with the measurement of organic carbon in Omega-9 water. The low
values for the CO2 purge method could be due to the loss of volatile organics dur-
ing the N2 purge. This problem needs to be investigated experimentally.
Solids—Total, total dissolved, and fixed solids were measured with good preci-
sion. However, the significance of these measurements for waters similar to
Omega-9 is questionable. TDS, as defined in Standard Methods (87), is the residue
remaining after a sample has been filtered and dried at 103° to 150 °C (217° to
302 °F). This parameter is intended to be a good indicator of total dissolved salts, as
these are not significantly lost on heating. However, this parameter is a poor in-
dicator of the dissolved salts in waters similar to dissolved salts in waters similar to
Omega-9. The species CO;, HCOj, NH3, and NHt constitute over 65 percent by
weight of the dissolved salts present in Omega-9. On heating to 103 ° to 150 °C (217°
to 302 °F), these species are lost from solution through the formation of volatile
salts or by stripping out dissolved gases. Therefore, the TDS determination gives a
low, nonrepresentative value for the dissolved salts present. The same considera-
220
-------
tions apply to total solids (86).
Alkalinity, Bicarbonate, and Carbonate—Conventionally, HCOj and CO" are
determined from alkalinity and pH measurements. However, this method is not
valid for oil shale process waters because of the presence of buffering components
other than the carbonate system (ammonia, borate, silicate, organic bases) and the
high ionic strength of the water. The presence of these species results in an over-
estimation of the COj. This method is discussed by Stumm and Morgan (86).
Sample Quality Control—
The treatment of the sample from the time it is collected through analysis is of
primary importance in determining the analytical result. Sample preservation and
storage is important for these waters, because bacteria may grow in them and affect
the organic contents as well as turbidity, etc. An additional concern with aqueous
samples is the loss of constituents by adsorption onto container walls or precipita-
tion reactions. These effects are usually minimized by acidifying the sample to a pH
of less than 2 with concentrated HNO3, although this step might itself cause
chemical reactions to occur. Filtration and sample preservation at 4 °C (39 °F) has
minimized some of these problems.
Alternative Test Procedures—
The EPA has provided a mechanism for establishing the equivalency of alter-
native procedures to those promulgated as standard procedures. The specifications
for the comparability data necessary to demonstrate equivalence are summarized in
the following paragraphs and as outlined below:
Nationwide Use Approval of Alternative Test Procedures:
Five industrial (discharge) sources identified by Standard Industrial
Classification (SIC) Code or five drinking water sources.
Six samples from each source.
Four replicate analyses each by proposed and approved methods.
Total tests:
5 (sources) x 6 (samples) x 4 (replicates) x 2 (methods) = 240 tests.
Limited Use (State or Regional) Approval of Alternative Test Procedure:
Five sources.
Three samples from each source.
Four replicate analyses each by proposed and approved methods.
Total tests:
5 (sources) X 3 (samples) x 4(replicates) x 2 (methods) = 120 tests.
Use by Single Permit Holder or Drinking Water System:
One source.
Three samples from source.
Four replicate analyses each by proposed and approved methods.
Total tests:
1 (source) x 3 (samples) X 4 (replicates) X 2 (methods) = 24 tests.
Statistical Protocol
1. Calculate basic statistics of mean and standard deviation.
2. Test for outliers.
3. Apply Cochran's test for equality among within-sample standard deviation.
4. Apply F-test for equality of pooled within-sample variances.
5. Apply T-test for equality of method means.
Background—On December 1, 1976, the Guidelines Establishing Test Pro-
cedures for the Analysis of Pollutants (88) was amended to allow applications for
221
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approval of alternative test procedures for nationwide use. Such applications were
required to include comparability data between the proposed alternative test pro-
cedure and an approved procedure. This system is intended to test the equivalency
of two methods using very specific comparability data. Application information
and EPA contacts are listed in this Federal Register reference.
Specifications for Comparability Data—for applications requesting approval of
an alternative test procedure for use by a single permit holder, comparability data
should obviously be generated for samples from all the types of discharges covered
under the permit. A similar requirement for applications requesting nationwide use
is impractical considering the vast number of discharge types usually implied.
However, it does seem reasonable to require comparability data on samples from
the five (5) types of discharges that are likely to have the greatest impact on the
NPDES Permit Program. Therefore, of the discharge types identified by primary
1972 SIC code or point source subcategory that might require use of the alternative
test procedure, comparability data should be required on samples from the five in-
volving the most permits or the largest amount of total discharge. EPA should be
able to specify these discharge types for each application, or possibly for each
parameter. In addition, samples from other types of discharges might be required
at the discretion of EPA.
Methods and Materials Standardization—
Reliable chemical characterizations have been difficult to obtain because of the
lack of adequate standards and limitations of many available analytical methods,
including very low or very high levels of most constituents and chemical interfer-
ences. These problems have been identified by many researchers faced with making
chemical measurements. They were first nationally acknowledged when the ASTM
Committee D-19 (Water), formed Subcommittee D-19.33 (Water Associated with
Synthetic Fuel Production) to address analytical problems specific to alternate
fossil energy process waters. Eight samples of three different fossil energy-related
waters are now available for laboratories wishing to participate in interlaboratory
studies. Parameters currently tested are phenol, arsenic, and total organic carbon.
Participants must use ASTM procedures; additional results from other procedures
are welcomed for comparison. The Subcommittee Chairman is Larry Jackson at
the Laramie Energy Technology Center.
The National Bureau of Standards (NBS) has a Surrogate Standards Program
for oil shale materials. The Bureau has conducted several interlaboratory studies
with a standardized shale oil. By May 1980 NBS will have issued reports of the
results and descriptions of the methods used. The shale oil material, certified for 6
polynuclear aromatic compounds and phenols, should also be available then. Dr.
Harry Hertz at NBS, Washington, D.C., is in charge of this program.
Analysis of Organic Pollutants in Surface Water and Groundwater
Introduction—
Until adequate information is available to determine what harmful organic com-
pounds are released to surface water and groundwater from oil shale processing ac-
tivities, monitoring must be construed as survey analysis to determine, insofar as is
feasible, the identities and amounts of all compounds released. Currently available
analytical techniques can provide identifications and concentration estimates for
organic compounds that will pass through a gas chromatograph. The remaining
sample components, which have been estimated to constitute 50 to 80 percent (by
weight) of the total organic carbon content of a water sample, are largely un-
characterized, and much work is needed to develop techniques for analysis of com-
pounds that cannot be characterized by gas chromatography.
For gas compounds that will pass through a chromatograph, the most powerful
analytical technique currently available is the combination of gas chromatography
and mass spectrometry (GC/MS). This technique can provide qualitative informa-
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tion with only a few nanograms (10~'g) of a sample component. The usefulness of
this technique for organic water pollutant analysis has been amply demonstrated by
many laboratories during the past few years, but some aspects of current analytical
procedures need improvement. These aspects include development of quality con-
trol guidelines, standard reference materials, internal reference compounds, sam-
ple preservation procedures, recovery information, and improved separation
techniques.
Quality control guidelines must begin with sampling procedures and cover all
analytical techniques through sample component concentration calculations. Stan-
dard reference materials are needed for trace-level organics in matrices similar to
those that will be analyzed, because the sample matrix cannot be completely
destroyed to release organic pollutants. Internal reference compounds are needed
to permit accurate concentration calculations after organic pollutants are iden-
tified. Adequate sample preservation techniques are necessary to insure that iden-
tified contaminants were really sample components and not the result of sample
composition changes. (Current expressed desires for sample archives depend on
adequate sample preservation.) Recovery information is necessary to inform the
analyst of what percentage of a given organic pollutant can be observed with the
analytical extraction, separation, and detection procedures used. Improved separa-
tion procedures might permit development of materials for reversible sorption and
desorption of specific classes of organic compounds (89).
Identification and measurement of specific organic components of wastes and
effluents from oil shale processing is necessary to determine the nature of organic
pollution generated, to develop adequate treatment facilities and pollution preven-
tion procedures, and to select appropriate monitoring techniques.
Two fundamentally different approaches to pollutant analysis exist. The analyst
can look for selected compounds, or he can attempt to detect and measure all com-
pounds present in a sample. In the first approach, specialized analytical procedures
to isolate, concentrate, and detect previously selected compounds are used. This
approach, however, assumes that the environmentally hazardous organic com-
pounds have been identified. Unfortunately, inadequate present information
makes it impossible to know which organic compounds should receive special at-
tention as water pollutants from oil shale processing and should, therefore, be
monitored in surface and groundwater.
To obtain adequate information upon which future monitoring requirements
can be based, the second approach, survey analysis, must be used in an attempt to
learn as much as possible about sample composition. Traditional and relatively
crude measurements of organic pollution—such as biochemical oxygen demand,
chemical oxygen demand, and total organic carbon—are not adequate, although
they should not be classified as useless. Such tests do not provide individual pollu-
tant information that is necessary to select and develop effective environmental
monitoring techniques. Although many analytical problems remain to be solved,
significant progress has been made during the past decade in the development of
organic pollutant survey techniques.
The following discussion is intended as an overview of currently available tech-
niques and of problem areas that require further attention.
Sampling—
The need for proper water sampling techniques cannot be overemphasized. Data
from expensive, time-consuming analyses of organic sample components will be
useless if collected samples are not representative of the sampled water or if
samples are contaminated or degraded during collection, shipping, storage, or
handling. Routine survey analysis to identify and measure all compounds that are
amenable to analysis by gas chromatography and GC/MS in one sample currently
costs between $2,000 and $3,500. When sample components are particularly dif-
ficult to identify, almost infinite amounts of time and, therefore, money can be ex-
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pended on one sample. Because analysts routinely attempt to identify components
at concentrations of greater than 1 mg/1 (1 ppb), a relatively small amount of con-
tamination is sufficient to mask sample components and distort analytical data.
Sampling techniques must be correlated with the type of water to be sampled, the
analytical method to be used, and the sample volume required to provide sufficient
material to be detected with the particular analytical method used. Usually, water
samples are either grab samples or composite samples. A single grab sample, which
is a relatively small water volume (frequently about 41 or 1 gal) taken at one time, is
usually not as representative as a composite sample that is collected over a longer
time period or intermittently (a series of grab samples).
General procedures for both grab and composite sampling include collection of
water samples in clean glass containers (washed with a diluted mineral acid, rinsed
with deionized/distilled water, and heated at 450 °C (842 °F) for 2 hours to remove
organic material) sealed with Teflon-lined caps. (Organic compounds can be
leached from plastic containers, and adhesives in regular screw caps can dissolve
and contaminate the sample.) To minimize the possibility of photodecomposition,
prevent loss of volatile components, and minimize composition changes, samples
should be stored in dark-colored bottles in a cold (F4 °C or 39 °F), dark place. Time
required for shipment from field sites to analytical laboratories should be mini-
mized.
Samples to be analyzed with the purge and trap technique for low-boiling
organics require special attention to ensure that sample bottles contain no head-
space, which permits equilibrium of volatile organics between vapor and dissolved
phases. Narrow mouth glass vials with greater than 50 ml (1.7 oz) capacity should
be filled to overflowing (to eliminate headspace) and sealed with screw caps lined
with Teflon-faced rubber septa (placed with the Teflon side toward the water sam-
ple).
Too little is known about the effects of storage conditions and time. Sample
composition can change through decomposition, vaporization, adsorption onto
sample container walls, microbial action, and chemical reactions. Adsorption ef-
fects are especially significant for components of dilute solutions. To detect con-
taminants introduced during shipping, storage, and handling, containers filled with
organic-free water can be transported to the sampling site and subsequently treated
as if they were samples (i.e., subjected to the same handling and analysis pro-
cedures).
Sampling aqueous media by sorption of organic components using activated car-
bon, macroreticular resins (such as Tenax GC and XAD-2) and other accumulator
materials provides a time-integrated and representative sample, but problems may
be encountered when sorbed materials must be desorbed for analysis (90-97). Little
information is currently available, however, about appropriate water flow rates,
sorbent capacity for different compound types, and optimum techniques to recover
sorbed materials. More than one accumulator material probably is necessary to col-
lect the wide variety of organic compounds found in surface and groundwater, and
more work is needed to determine appropriate sorbents and optimum techniques
for reversible sorption and desorption of specific classes of organic compounds.
A recently developed automatic sampler can collect up to 14 samples on ac-
cumulator columns (variable sizes) that are returned to the laboratory for desorp-
tion and analysis of nonpurgeable organic compounds (98). The water flow rate is
adjustable, and sample volume and collection time span can be programmed. Two
or more accumulator columns can be used to collect a sample in series. The sampler
also can collect up to 26 samples for later analysis of purgeable volatile compounds
that can be removed by bubbling an inert gas through the sample. The sampler is
refrigerated and can be operated in a laboratory or at a remote site and can func-
tion unattended for up to 7 days.
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Extraction —
For subsequent analytical procedures, organic contaminants must be removed
from the water sample and concentrated to permit detection and identification.
The variety of chemical and physical properties of organic water pollutants
preclude their removal and concentration with a single technique. Sample con-
tamination and loss of sample components are the analyst's constant concerns.
Volatile Compounds—Organic compounds having low boiling points (below
about 150°C or 302 °F) can be removed from water samples by purging with a pure
stream of an inert gas such as helium or nitrogen (99). Volatile organic sample
components dissolve in the inert gas and are carried with it into a cartridge contain-
ing a sorbent (such as Tenax-GC or XAD-2), which traps the organic compounds
but allows the gas to pass through. This technique is useful for compounds that
would be lost or obscured by the solvent used in liquid/liquid extraction pro-
cedures. For quantitative recovery, the analyst must be concerned with how much
of a given compound will be retained by the sorbent volume used, how long purg-
ing should be continued, what sample temperature must be maintained during
purging, and how long the component can be retained on the sorbent during pre-
analysis storage. Trapped compounds are usually thermally desorbed by flushing
with inert gas into a gas chromatograph or GC/MS for analysis.
A modified version of this method was used to measure volatile organic com-
pounds in a comprehensive EPA study of public water supplies in the United States
(100).
Semivolatile Compounds—Many compounds that cannot be removed by inert
gas purging can be removed by partitioning into an organic solvent. In this pro-
cedure, an aliquot of the water sample is shaken with a nonwater-soluble organic
solvent in a separatory funnel. Organic compounds that are more soluble in the sol-
vent than in water will be partitioned into the solvent. Partitioning, however, is not
complete, and extraction efficiency varies with individual compounds. To separate
components into basic, neutral, and acidic fractions, analysts frequently perform
three extractions—one after each of three sample pH adjustments (55). To concen-
trate extracts for analysis, the organic solvent layer is removed from the separatory
funnel and placed in a Kuderna-Danish evaporator (a device that is specially
designed to minimize loss of organic components during solvent evaporation) and
heated to reduce the extract volume. (Many of the volatile compounds that can be
removed by inert gas purging are lost during the solvent evaporation step in this
procedure.)
Relatively large volumes of solvent (such as 600 ml solvent/1 or 76.8 oz/gal of
water sample) are used in the extraction procedure. When this volume is reduced to
permit detection of extracted sample components, semi volatile impurities in the
solvent also are concentrated for later detection along with sample components.
Solvent blanks are obtained by evaporating the same volume of solvent as that used
in the extraction to the final sample extract volume and analyzing this solvent
residue by means of the same analytical techniques used for the sample extract.
Compounds observed in the solvent residue are assumed to be solvent impurities or
procedural contaminants, either of which should also appear in sample extracts.
An impurity in methylene chloride, a commonly used solvent, has been shown to
react with residual free chlorine contained in some chlorinated samples. This reac-
tion produced many chlorinated hydrocarbons in significant concentrations
relative to other detected compounds (private communication with O. J. Logsdon,
U.S. Environmental Protection Agency, Denver, Colo.).
The volume of water to be extracted depends on the desired level of detection of
sample components. The analyst knows the detection limit of the analytical method
and can calculate how much sample must be used to provide sufficient material to
detect organic compounds at a given concentration. Because contaminant extrac-
tion efficiency is less than 100 percent, complete recovery is not feasible and should
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not be expected. Much effort has been expended to determine the best solvent con-
centrations and to calculate recovery rates for particular organic compounds, but
much more information is needed (101,102).
Continuous Extractors—Sample foaming and emulsion formation frequently
hinder, if not prevent, sample extraction with separatory funnel shakeouts. For
samples presenting these problems, a promising apparatus for continuous liquid/li-
quid extraction is commercially available (Aldrich Chemical Co., Milwaukee,
Wise., Cat. No. Z10.157-5; and Ace Glass Co., Vineland, N.J., Part No. 6841-10).
It involves a Soxhlet-type cyclic distillation, agitated liquid/liquid contact, and
return of solvent containing dissolved organic sample components to a solvent
reservoir. Continuous extractors are available for use with solvents that are either
heavier or lighter than water. This method has the advantage of requiring relatively
small solvent volumes, but it requires long extraction periods (such as 24 hours per
fraction) compared to separatory funnel procedures requiring only about 30 min
per fraction.
Bioassay Fractionation—To determine whether biological effects of complex
mixtures are caused by the whole substance or by low concentrations of active com-
pounds, the mixture is subdivided into fractions, which are then individually tested
for biological effects (103). Fractions exhibiting high biological activity can be sub-
fractionated and tested again. Each active fraction can be analyzed chemically to
identify individual components.
Comparison of relative toxicities (to the zooplankton Daphnia pulex) of un-
treated oil shale process water fractions indicated that the ether-soluble weak acid
fraction was approximately 20 times more toxic than the ether-soluble strong acid
fraction and approximately 30 times more toxic than the water-soluble strong acid
fraction (104). The weak acid fraction contains phenols, which are toxic but con-
sidered to be relatively easy to remove through appropriate effluent treatment.
Separation and Identification—
Gas Chromatography—ln most cases, detection of organic water pollutants re-
quires that sample components be separated through chromatographic techniques.
The static atmosphere over a water sample in a closed container can be sampled
directly and analyzed with gas chromatography (105). Although rapid, this qualita-
tive detection procedure is limited by the solute gas/liquid partition equilibrium
and by the limited volume of headspace gas that can be conveniently sampled and
analyzed. Compounds that are volatile but too water soluble for extraction, sorp-
tion, or inert gas sparging may be analyzed by direct aqueous injection into a gas
chromatograph or a combined GC/MS system (106). Because of the relatively high
minimum detection limits of this method (approximately 1 to 50 ppm), more sen-
sitive methods usually are required for water pollutant analysis. A common pro-
cedure for analyzing smaller concentrations of organics is injection of an aliquot of
a concentrated sample extract; the injection volume depends on component con-
centrations, column capacity, and detector sensitivity.
Volatile and semivolatile compounds travel through a GC column at different
rates, depending on their affinities for the column packing material. Compound
retention times can be modified by varying packing materials, column
temperatures, carrier gas flow rates, and column sizes. Various detectors may be
used to observe eluting sample components. For comprehensive survey analyses,
the most commonly used detectors are flame ionization detectors and mass spec-
trometers. (Other GC detectors permit observation of compounds containing
specific atoms such as sulfur, phosphorous, nitrogen and halogens.)
A common identification method involves comparison of the GC retention time
of the sample component with that of a standard sample, when both are analyzed
with identical chromatographic conditions and more than one column packing
material. This method is not feasible, however, when samples contain more than a
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few components. Because several compounds may co-elute, more definitive infor-
mation is needed and can be obtained by MS or by spectroscopic techniques (such
as infrared and nuclear magnetic resonance). The best identification technique cur-
rently available for survey analysis is GC/MS, because it is sensitive and
compound-specific, and computerized systems provide automated analysis and
identification. This technique is discussed in more detail in a later section. Spec-
troscopic techniques frequently require more sample than is usually available,
although GC-Fourier transform infrared (FTIR) has been shown to be feasible,
and a commercial system is now available. Although this technique currently lacks
the sensitivity available with GC/MS systems, it can be used for some samples and
holds great promise for the future. With present GC-FTIR systems, identifiable in-
frared spectra can be obtained from 0.2 mg (3.09x10'' grains) of an organic com-
pound (107). The use of GC-FTIR for analysis of components of water from an in
situ coal gasification process has been reported (55). When sufficient sample is
available, this technique can provide information that will permit identification of
compounds that could not be identified unequivocally using GC/MS techniques,
or it can provide information supporting tentative identifications from mass spec-
tral data.
Liquid Chromatography—Some compounds that are extractable or sorbable are
not amenable to gas chromatographic analysis. Although derivitization techniques
can be used to convert some of these compounds into volatile derivatives that are
gas chromatographable, the exact nature of the reactions in complex mixtures is
frequently uncertain. The most promising technique for these compounds appears
to be liquid chromatography (LC), which can be used to separate organic com-
pounds that are thermally labile (and decompose in GC injection ports) or too
polar or insufficiently volatile to pass through a GC. Recent advances in LC
technology have made this technique useful for environmental sample analysis.
Because GC and LC are suitable for different compound classes, these techniques
complement each other.
The need for more sensitive and compound-specific LC detectors has limited the
use of LC for environmental pollutant identification. Presently, the most promis-
ing approaches to selectivity include multiwavelength, ultraviolet-visible absorp-
tion, fluorescence detection, and electrochemical detection (108). Ultraviolet (UV)
absorption detectors are sensitive to UV-absorbing compounds but are of limited
value for providing the molecular structure of an unknown compound.
Fluorescence emission detectors are useful for certain classes of compounds (such
as many polynuclear aromatic hydrocarbons and heterocyclic analogues). A
combination absorbance-fluorescence detector can be used (109). Tentative com-
pound identifications can be based on fluorescence emission spectra and
chromatographic retention data, but further information is required for specific
compound identification. Progress has been made in development of LC/MS and
LC/IR interfaces (110,111). Both systems will provide specific information needed
for identification of compounds eluting from an LC.
The usefulness of UV and fluorescence detectors can be extended by making
fluorescent or UV-absorbing derivatives of compounds either before or after
chromatographic separation (pre-column or post-column derivatization) (112).
Other chemical modification techniques can be used to make LC effluents
amenable to detection by chemiluminescence, AAS, and polarography (113-115).
Eluting compounds or groups of compounds can be collected from an LC and
analyzed by solid probe mass spectrometry, or (if amenable to GC) by GC/MS.
Organic sample components that interfere with GC/MS analysis of water extracts
can be reduced or eliminated by selective LC fractionation (116). A promising
technique combines LC and MS. A commercially available LC-MS system permits
continuous introduction of LC effluent into the MS by using an endless steel con-
veyor band as the interface (110).
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Mass Spectrometers as Chromatographic Detectors—As an organic compound
enters an electron impact mass spectrometer, it is bombarded with electrons and
broken up into fragments; charged fragments are detected and recorded. A plot of
detected charged fragments versus relative abundances is the compound's mass
spectrum, which provides composition information about the compound. En-
vironmental samples may contain hundreds of organic compounds at concentra-
tions greater than 1 mg/1 (8.34x10"' Ibs/gal); these will pass through a GC column
and are detectable with a mass spectrometer. A computer-controlled mass spec-
trometer connected to the GC or LC permits continuous repetitive acquisition and
storage of mass spectra of sample components eluting from the chromatographic
column. Appropriate software permits the analyst to plot spectrum number (time)
versus summed ion intensities (or selected-ion intensity summations) for each mass
spectrum; this provides a chart similar to a gas or liquid chromatogram. Using this
total ion current profile (sometimes called a reconstructed gas chromatogram), the
analyst (or, with appropriate software, the computer) can select mass spectra of in-
terest and plot them for examination. Subtraction of ions produced by extraneous
organic molecules (from traces of air, water, vacuum pump oil, column packing
materials, and sample components not completely separated from the component
of interest) leaves a sample component mass spectrum that can be plotted for visual
inspection and retained for future use.
A mass spectrum provides a chemical fingerprint that is characteristic of an
organic compound and can be interpreted to obtain the compound structure. Spec-
tra interpretation, which requires experience and knowledge of organic ion decom-
position mechanisms, can be rapid (seconds or minutes) or can require several
hours. Indexed compilations of mass spectra can be searched manually to compare
the spectrum of a sample component with that of a known compound spectrum. In
the past few years, a computerized mass spectral search system (MSSS) has been
developed and is commercially available as part of the National Institute of Health-
EPA Chemical Information System (117). The data base now contains approx-
imately 32,000 mass spectra of different compounds. A four-volume collection
(118) of 25,560 of these spectra was published in late 1978 or early 1979. A supple-
ment of 6,053 spectra that were recently added to the file will be published in 1979.
The computer matching program provides an indication of how well the stored
mass spectrum matches the unknown mass spectrum, but a reasonably good match
should be considered only suggestive of a probable identification. Because some
compounds are not uniquely characterized by their mass spectra, identifications
based on comparison of integer mass spectra are not unequivocal and should be
considered as tentative. Confirmatory information can be obtained by comparison
of the GC retention time and mass spectrum of the sample component with
analogous data obtained using a standard pure compound analyzed under the same
conditions used for the sample. Standards are not always readily available, and the
confirmation process is expensive and laborious for samples containing a hundred
or more observable components. Understandably, many reported identifications
have not been confirmed. Despite these obvious drawbacks, GC/MS is currently
the most powerful and widely used technique for identification of specific organic
compounds as environmental pollutants. Literature reviews of environmental ap-
plications of mass spectrometry from 1969 through 1976 cited 922 reports concern-
ing organic compound analyses (119-121).
Electron impact (El) mass spectra may not contain one important piece of infor-
mation—compound molecular weight. A chemical-ionization (CI) mass spec-
trometer coupled to a GC frequently provides this information, however. The main
difference between chemical ionization MS and electron impact MS is the method
of ionization of the sample component; but the resulting spectra are quite dif-
ferent. In some cases, CI/MS can distinguish isomers that produce similar El spec-
tra but different CI spectra.
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In CI/MS, a reagent gas is present in large amounts relative to the sample com-
ponent. (A reagent gas to sample ratio of approximately 1000:1 is common.)
Reagent gas ions are formed by electron bombardment of the reagent gas, and
these ions react with sample molecules to form ions that are characteristic of both
sample and reagent gases. The characteristics of the CI mass spectrum depend on
the nature of the reagent gas and the type of ion/molecule reaction that ionizes the
sample. The most commonly used reagent gases are methane and isobutane. Dif-
ferent structural information can be obtained with different reagent gases, and the
use of more than one reagent gas provides complementary structural information
(122). The reagent gas can be the GC carrier gas or can be added to column effluent
before it enters the mass spectrometer. Molecular weight information can be ob-
tained from sample quantities comparable to those used in EI/MS. Because
relatively little fragmentation occurs in CI/MS, much of the structural information
available from EI/MS cannot be obtained from CI spectra. Few collections of CI
mass spectra are currently available for comparison of sample component spectra
with known compound spectra, but CI/MS systems are commercially available and
are widely used. Some mass spectrometers can be operated in either El or CI
modes.
Some confusion may result from references to analysis by high resolution
GC/MS and by GC/high resolution MS. The former involves the use of GC col-
umns that are usually relatively long (approximately 20 to 50 m or 65 to 164 ft) and
relatively small in diameter (approximately 0.25 mm or 10~3 in. I.D.). Although
these capillary columns have relatively small sample capacity, they have the advan-
tage of increased capability to separate organic compounds. High resolution mass
spectrometry, on the other hand, refers to the use of a mass spectrometer that will
provide mass-to-charge ratios accurate enough to permit calculation of an em-
pirical formula for that fragment. All possible combinations of specified atoms
that would produce the detected ion can be calculated using available computer
software. Low resolution mass spectra provide only nominal mass-to-charge ratios
that do not differentiate between many possible combinations of atoms.
Relatively few laboratories have high resolution mass spectrometers, which are
more expensive and difficult to operate and maintain than low resolution in-
struments. A further limitation of high resolution spectrometers is that sensitivity
must be sacrificed to obtain higher accuracy.
Quantitation —
Determination of the amount of an organic compound present as a water pollu-
tant requires relating a detector response to a quantity of that particular com-
pound. This is usually accomplished by using an internal standard that is added to
the sample and subjected to the same analytical procedures as the sample. The con-
centration of the unknown sample component is calculated after measuring the
detector responses for the sample component and a known amount of the internal
standard. This calculation is valid only if the internal standard closely resembles the
sample component in chemical and physical properties.
In environmental samples containing hundreds of organic compounds, the many
different compound classes present will produce different detector responses
relative to the amount of compound present. The impossibility of using an internal
standard for each sample component has led to the use of calculated response fac-
tors (55). Using solutions of standard compounds, the analyst can calculate the
relative detector response for sample components and internal standards. This
technique, however, is laborious and time consuming, because the analyst needs a
standard sample for each sample component and information about the detector
response to varying concentrations of each compound. For these reasons, quantita-
tive calculations in survey analyses usually are only approximations. When only a
few compounds are being analyzed, quantitative data can be more accurately deter-
mined than is feasible when the analyst is attempting to identify and measure every
organic pollutant present.
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Internal standards need to be compounds that will not be found in environmen-
tal samples. For this reason, isotopically labeled compounds are useful internal
standards.
When an analyst knows the percentage of a particular compound that is
recovered with the analytical procedures used, the amount that was present in the
original sample can be calculated from the detected quantity. Because the
recovered amount varies significantly, correction factors are important for ac-
curate concentration calculations. For example, with the inert gas purging tech-
nique, one investigator reported approximately 10 percent recovery of acetonitrile
and more than 80 percent recovery of benzene and toluene (55).
More work is needed to improve present quantitation techniques for organic
water pollutant analysis.
Consent Decree Compounds—
The technique currently being used to detect organic Consent Decree priority
pollutants in industrial effluents illustrates the use of computerized GC/MS
systems to detect specified pollutants in water and wastewater samples (123). This
technique is based on the appearance of a significant, sufficiently unique ion that is
characteristic of a particular compound at the appropriate GC retention time in a
reconstructed gas chromatogram. These two pieces of information indicate the
presence of a compound in an extract even when the compound's full mass spec-
trum is distorted or obscured by interfering compounds.
Using standard samples of each compound to be detected, the analyst must
determine the compound's GC retention time with the particular column to be used
for analysis. The compound's mass spectrum must be inspected to select ions suffi-
ciently unique (when used with GC retention time) to be characteristic of the com-
pound. When feasible, the use of more than one characteristic ion and the relative
intensity of each provides more definitive information.
Concentrations of detected compounds are calculated by using relative response
factors calculated by GC/MS analysis of one or more standard solutions contain-
ing standards of the organic Consent Decree compounds.
SOLID WASTE
Monitoring Methodology
The handling and disposal of solid wastes are expected to create some of the ma-
jor environmental problems associated with commercial development of oil shale.
The solid wastes include spent oil shale, raw oil shale, spent catalysts from
upgrading processes, construction debris, garbage, and sewage and water treat-
ment plant sludges. Studies to date (124,125) have concluded that the main en-
vironmental problems pertaining to solid wastes will consist of the surface erosion
of spent shale piles and the leaching of soluble salts and organic compounds from
the spent shale piles. In addition to spent shale, the spent shale piles will normally
include raw shale fines, spent catalysts, sludges, and process wastewaters. Raw
shale, such as that removed from underground in preparation for modified in situ
operations, will most likely be stored separately on the surface to await crushing
and retorting.
Spent shale piles will be subject to surface erosion during periods of runoff. Dur-
ing these periods, soluble substances such as organic salts can be dissolved from the
spent shale and become part of the runoff water along with suspended materials.
(The quality of surface runoff from spent shale piles is discussed in Section 3.)
About 10 kg/kkg (20 Ib/ton) of salt is water soluble in freshly retorted shales, and
additional soluble substances will be available in the spent shale piles from the
process wastewaters and spent catalysts that will be disposed therein. If spent shale
piles were to erode at a rate equal to that of natural erosion in the Piceance Creek
Basin, the average annual rate of suspended sediment would be about 6,725 kg/ha
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(3 tons/acre) (124). It can be anticipated that with the best control measures, some
disposal piles will erode at rates greater than this average. The latter condition
could result from the high erodibility of some fine-grained spent shales such as
TOSCO II, unsuccessful attempts at revegetation, or instability of slopes and im-
pounding structures.
Monitoring Surface Waters for Impacts of Oil Shale Solid Waste Disposal—
Surface water monitoring should include sampling for chemical analysis and
quantification of streamflow throughout the region subject to oil shale develop-
ment. The monitoring results should provide an assessment of water quality in the
Colorado River, and they should also provide sufficient detail to evaluate properly
the effects of the individual oil shale operations within the watershed. To date,
much of streamflow monitoring has been performed by the USGS, which main-
tains 50 streamflow stations in the oil shale area on the Colorado River and its ma-
jor tributaries. An additional 21 stations are monitored within the Piceance Creek
Basin by the USGS, with assistance from industrial concerns. Streamflows at
another nine gauging stations are measured continuously by oil shale companies in
the Parachute Creek watershed. Sampling for chemical analysis and sediment
loading is performed regularly at all of the stations by the USGS and the oil shale
companies. Crawford et al. (124) concluded that, given maintenance of the present
surface water gauging stations, it appears that adequate background data will be
available for determining the effects of direct discharges of most oil shale develop-
ment activities on surface water.
The present monitoring of solid waste disposal with respect to surface water con-
siderations seems drastically lacking in provisions for regular inspection of spent
shale piles and catchment structures to determine the probability of mass
movements in the disposal piles or sudden failure of the catchment structures.
Since no large disposal piles have thus far been constructed, knowledge about their
stability or how to inspect for their stability seems inadequate. A monitoring pro-
gram should, however, be developed based on the best opinions available and
should be updated as research results and operational experiences become
available.
Monitoring Groundwater for Impacts of Oil Shale Solid Waste Disposal—
Monitoring for impacts on groundwater quality of solid waste disposal in the oil
shale industry is much more difficult than measuring the direct effects of such
disposal on surface waters. However, an evaluation of the total, long-term effects
on surface water must include the contributions of groundwaters that have been
altered by the leaching of substances from oil shale solid wastes. Consequently,
water quality monitoring must address the issue of possible groundwater changes.
A large number of test holes and water wells have been drilled in the oil shale
region of Colorado, Utah, and Wyoming. These have provided very useful data
about the geology, hydrology, and quality of the area's groundwater. Some of the
wells are being measured for water-level changes on a routine basis, and some are
being sampled regularly for water quality considerations. The evaluations of these
results will be necessary in understanding the ranges of natural changes in
hydrology and water quality. With these evaluations, long-term changes resulting
from impacts of the oil shale industry can also be assessed. The measurements will,
however, have limited usefulness in the close-up, short-term evaluation of impacts
from solid waste disposal, particularly with respect to the leaching of the disposed
materials.
For the reasons discussed above, a study was initiated by EPA to develop a
preferred groundwater-quality monitoring program for the proposed oil shale
developments in Federal Prototype Lease Tracts U-a and U-b in northeast Utah.
The study followed methodology described in the preceding section concerning
groundwater monitoring methods. The oil shale developments that were proposed
231
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for the tracts consisted of underground mining of the shale and surface retorting by
TOSCO II and Paraho processes. Since the solid wastes, including spent shale,
were to have been disposed of on the surface in a spent shale pile, the development
represents an environmental situation that is similar to most oil shale developments
that (1) will use surface retorting facilities and dispose of spent shale and other
wastes above ground, or (2) will store on the land surface the raw shale that is
removed from underground to make way for modified in situ operations.
Briefly stated, the methodology used includes the following operations:
Identification of potential pollution sources and their significant pollutants
Priority ranking of the pollutant sources
Assessment of existing or proposed monitoring programs
Identification of alternative approaches for addressing perceived monitoring
deficiencies
Selection of recommended monitoring approaches
Included under the broad topic of the monitoring plan are recommendations for
developing background data bases on pollutant source characteristics, the
hydrogeologic framework of the study area, existing water quality, and infiltration
information, as well as recommendations for monitoring pollutant mobility.
Hence, needs for baseline characterization are identified and evaluated in addition
to direct operational monitoring needs.
Efforts to identify the potential pollution sources in the solid waste category and
their respective pollutants resulted in the data summarized in Table 5-12. Shown
are eight potential causes of water pollution. Data on the pollutants and their possi-
ble concentrations (such as in leachates) will be used in the next step concerning
priority ranking of the sources and in efforts to design the recommended monitor-
ing program.
TABLE 5-12. SUMMARY OF SOLID WASTE POLLUTANTS AND
POLLUTANT SOURCES3
Pollution source
or cause
Surface disturbance
Construction debris
Raw oil shale
Spent oil shale
Disposal
methods
Some stockpiles,
revegetation use
Landfill
Stockpiled or placed
on spent shale pile
Spent shale pile
Potential
pollutants
Salts-CaS04
Nitrates
Sulfides
Trace Metals
— See discussion
Major inorganics:
TDS
Sodium
Calcium
Magnesium
Potassium
Sulfates
Chlorides
Fluoride
Trace elements:
Mercury
Lead
Cadmium
Arsenic
Possible
concentration
Uncertain
Uncertain
of spent shale—
(mg/l)
140,000
35,000
3,000
4,700
600
90,000
3,000
17
(mg/l)
0.005
0.004
0.006
0.2
232
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TABLE 5-12. (continued)
Pollution source Disposal Potential
or cause methods pollutants
Copper
Zinc
Selenium
Iron
Boron
Organics:
Oil and grease
Phenols
TOC
Benzene extracts
Carcinogens
(PCM, PAH)
Sulfur byproducts Sale or disposal in Sulfur compounds
Possible
concentration
0.2
3
2
2
10
Unknown
Unknown
3 to 5 percent
by weight
2,500 ppm possibly
Unknown
50 percent
Oil upgrading
catalysts:
HDN (naphtha,
hydrotreater)
spent shale pile
Spent shale pile
(landfill) or recycle
elemental S
Unknown (solubility
characteristics of
spent catalysts
are unknown)
Nickel, arsenic
Miscellaneous
catalysts
Spent filters
(carbon and
diatomaceous
earth
Miscellaneous
Landfill (gar-
bage, etc.)
Sewage sludge
Water treatment
plant sludges
Landfilled or put in
spent shale pile
Soil amendment
for revegetation
Spent shale
disposal pile
Iron, copper,
nickel, zinc ox-
ides and sulfides,
cobalt molybdate
Adsorbed
Nutrients
Sulfides
Organics
Organics
Nutrients
TDS
Unknown (nature
and solubility of
these organics
are uncertain)
Uncertain
Uncertain
Uncertain
Source: Reference 126.
The priority ranking of pollutant sources and pollutants (Table 5-13) is based on.
a sequence of data compilation and evaluation steps. These steps include (a) iden-
tification of the potential pollution sources mentioned above, methods of waste
disposal, and potential pollutants associated with the various waste sources, and
(b) an assessment of the potential for infiltration and subsequent mobility of these
pollutants in the subsurface. The three basic criteria used to develop the ranking of
pollutant sources are:
Mass of waste, persistence, toxicity, and concentration
Potential mobility
Known or anticipated harm to water use
With respect to the potential sources of pollutants in the solid waste category,
and indeed for all sources on the oil shale tracts, the principal source of ground-
233
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TABLE 5-13. PRELIMINARY PRIORITY RANKING OF POLLUTANT SOURCES AND POLLUTANTS
FOR OIL SHALE TRACTS U-a and U-ba
Source
priority
ranking
Highest
Intermediate
Lowest
Potential
pollution
source
Spent shale
High IDS wastewater
Sour water
Retort water
Spent catalysts
Stormwater runoff
Water treatment plant
sludges
Miscellaneous landfill
materials
Sulfur byproducts
Oily waste waters
Spent filters
Sewage sludge
Mine water
Sanitary waste water
Surface disturbance
Potential pollutant ranking
Highest
IDS, Na, S04, As, B, Se, F,
organics (PAH, carcinogensb)
TDS
Ammonia, phenols
As, Cl, S, organics, (POM
carboxylic acids, phenols)
As, Mo
TDS, organics, As, Se
TDS
Organics
Sulfides, sulfates
Organics
Organics, As
Organics
TDS, oil and grease
Organics
Calcium salts, TDS
Intermediate
Ca, Mg, Zn, Cd, Hg,
organics (phenols, etc.)
—
Organics
TDS, organics (amines.
etc.)
Zn, Ni
Na, Ca, S0«, HC03/
organics
Major macroinorganics
—
—
Trace metals
Trace metals
Nutrients
Trace metals, organics
Nutrients
Macroinorganics
Lowest
Pb, Cu, Fe
—
—
Carbonates,
P04, N03
Fe, Cu, Co
Zn, Cd, Hg
Trace metals
—
—
—
—
Macroinorganics
Macroinorganics
—
a Source: Reference 126.
Suspected carcinogens such as benztajanthracene, benzo(a)pyrene, 7, 12-dimethylbenz( a) anthracene, dibenz(a,j)acridine, and 3-methylcholanthrene.
-------
water contamination was determined to be spent shale. Particular contaminants in
spent shale include an extremely high salt concentration (possibly as high as
140,000 mg/1 or 1.17 Ibs/gal TDS) and a high loading of organics. The mobility of
salts will be limited mainly by precipitation reactions, which could remove calcium
and magnesium carbonates, and gypsum. Some sorption of organics may occur.
Mobility of organics will be enhanced by the high TDS, and leaching of both types
of contaminants (organics and inorganics) will occur together. Organic concentra-
tions may be diminished by precipitation at higher pH values, by surface reactions,
by auto-oxidation, and by microbial decomposition. Trace metal mobility will be
affected by pH, complexing with organics, sorption on organics, precipitation as
sulfides, etc. Microorganism levels probably will be limited by the high TDS.
The spent shale pile will contain a fabricated vadose (water unsaturated) region
overlying the indigenous vadose zone. Movement of water and pollutants in the
fabricated vadose zone may be reduced by the presence of indurated layers formed
by the precipitation of calcite and gypsum. However, estimated leachate values of
exchange sodium percentage, sodium adsorption ratio, and total dissolved solids
are such that the hydraulic conductivity will remain high.
Attenuation of pollutant movement in underlying geologic formations may
result mainly from precipitation of salts, because sorptive effects will be limited
(except possibly to organics).
The above discussion suggests that pollutants in spent shale leachate may be at-
tenuated by a variety of physical/chemical processes. However, because of the in-
itially high concentrations of the major inorganic constituents, the overall salinity
level will remain high in leachate. In fact, if leachate were somehow to penetrate
shallow alluvial aquifers or other freshwater aquifers, serious quality impairment
would occur.
Monitoring Spent Shale Disposal—
In the following discussion, considerations that should be included in a recom-
mended groundwater quality monitoring program for a spent shale disposal situa-
tion are presented. The monitoring steps addressed are pollutant source
characterization, water use, hydrogeologic framework and existing water quality,
infiltration potential, and pollutant mobility.
Pollutant Source Characterization—During the development and operation of
the oil shale facilities, on-site inspection of disposal procedures is recommended on
a regular basis. Observations should be made of the following activities:
1. Preparation of disposal area before disposal (removal of soils, storage of
removed materials, etc.)
2. Procedures for transport, spreading, contouring, and compaction of spent
shale
3. Placement of other solid and liquid wastes in or on the spent shale pile
4. Surface sealing of spent shale pile
5. Construction of revegetation trenches
6. Irrigation or imposed leaching activities
The frequency of these on-site surveys will vary according to the intensity of ac-
tivities. For example, during project initiation, weekly or biweekly surveys should
be made. As operations reach a steady state (during each development phase),
survey frequency can be extended to perhaps monthly or even quarterly observa-
tions. As revegetation activities are initiated, more frequent (again perhaps weekly)
observation is required.
Knowledge of the chemical characteristics of liquid wastes to be disposed into the
spent shale pile and of the soluble components of solid wastes is essential to the
monitoring program. Development of the monitoring program should include
analyses of liquid wastes and solid waste saturated extracts for the chemical
235
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characteristics outlined in Table 5-14. Waste products to be included are (in
decreasing order of priority):
1. Processed shale (saturated extract)
2. High TDS wastewater
3. Sour water
4. Spent catalysts (saturated extract)
5. Water treatment plant sludges (saturated extract)
6. Sulfur by-products (saturated extract)
7. Oily wastewaters
8. Spent filters (saturated extract)
9. Mine water
TABLE 5-14. OUTLINE OF PRELIMINARY CHEMICAL ANALYSIS
PROGRAM FOR MONITORING PROCESSED SHALE
DISPOSAL AREA8
Priority for
Priority for monitoring constituents
analysis
category
Highest
Mnaiysis
category
General parameters
Major inorganics
Trace elements
Highest
pH, e.c.. Eh
Na, SO,,
a, F
As, Se,
Mo, B
Intermediate
TDS
Ca, Mg, K
HC03
C03
Sulfides
NH3
Zn, Cd, Hg
Ni
Lowest
N03
Pb, Cu, Fe
Organics
Intermediate Radiological
Lowest Bacteriological
DOC
Gross A activity
Gross B activity.
TPC
Ra-226, 228
TC
DOC fractiona-
tion, phenolics,
specific com-
pounds (BaP)
U, Th
FC
Source: Reference 126.
Water Use—Data should be obtained from the State and Federal agencies that
are concerned with water resources and economic development.
The Hydrogeologic Framework and Existing Water Quality—The hydrogeologic
framework and existing water quality in the vicinity of a disposal site should be
adequately described to measure the changes in water quality that might occur as a
result of the oil shale activities. Recommended approaches for a more or less
typical situation are presented in the following paragraphs.
Characterization of Alluvium. Recommended activities for monitoring program
development are as follows:
1. Test drilling and geophysical surveys to define the characteristics and bound-
ary condition for the alluvial system (i.e., thickness, subsurface extent)
2. Sampling of water quality of alluvial aquifer
3. Pump testing of saturated zones identified to determine hydraulic
characteristics
236
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Formation Fracturing. Fracturing in the bedrock formations that are in contact
with the spent shale may create pathways for the movement of pollutants from the
disposal area to surface waters or to deep aquifers. Identification of the density and
character of this fracturing is thus the key to evaluating pollutant mobility and
development of the monitoring program. As the materials in the alluvial channels
and canyon slopes are cleared for construction of the processed shale pile, visual
surveys should be made of the surface of the bedrock formation. Fracturing should
be mapped, and the maps used for locating monitoring sites for following mobility
in the processed shale disposal area.
Testing Green River Formation. Testing recommended for the aquifers in the
Green River Formation includes:
1. Evaluation of water quality sampling procedures at existing and proposed
wells to establish suitable sampling methods and sampling frequency
2. Evaluation of existing pumping test data and performance of additional
pump testing at existing wells
3. Installation, pump testing, and water quality sampling of new wells where
hydrologic assessments indicate they are needed
Infiltration Potential—Infiltration potential is to be evaluated to examine the
water-balance for the processed shale pile and to provide a basis for monitoring
pollutant mobility in the processed shale disposal area. The two areas where in-
filtration should be assessed are the surface of the disposal pile itself and the sur-
face of the underlying formation (i.e., in fractures). For these assessments, it is
recommended that double-ring infiltrometers be used as follows:
1. At various stages of the construction of the processed shale pile including:
a. As shale is spread before compaction
b. After compaction
c. After surface is sealed
d. During revegetation (i.e., in revegetation trenches)
2. At the surface of cleared areas where the underlying formation is exposed
In conjunction with these infiltration tests, monitoring of subsurface mobility
should also be employed as presented in the following discussions. Such monitor-
ing offers the opportunity to provide the infiltration assessments, provide estimates
of subsurface hydraulic conductivity, test various monitoring equipment (e.g.,
moisture blocks, suction cup lysimeters, and neutron probes), and (via sample col-
lection) provide an analysis of leachate formation and composition.
Pollutant Mobility—Pollutant mobility monitoring needs in the processed shale
disposal area include monitoring (a) in the processed shale pile itself, (b) in
alluvium that may be present in the disposal area, and (c) in the bedrock forma-
tions.
Monitoring in the Processed Shale Pile. Monitoring in the processed shale
disposal pile includes the sensing of changes in moisture content (thus potentially
inferring movement of water and solute materials) and the collection and
characterization of these solute materials. The monitoring program should be in-
itiated with the infiltration evaluations presented above. Infiltration test sites
should be instrumented as follows:
1. Water content (or "soil"-water pressure) sensing:
a. Access well for neutron moisture logging
b. Soil moisture blocks (at various depths)
2. Suction cup lysimeters for water quality sampling (tensiometers should be
used to appropriate suction levels)
As indicated above, a sequence of infiltration tests during the various stages of
pile construction is recommended. The initial testing of spent shale before and after
237
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compaction forms the basis of initial monitoring of the shale pile. The test sites
should be maintained as long as possible during pile construction. As benches are
formed in the disposal pile, permanent monitoring sites should be established on
them with access (neutron logging) tubes, tensiometers, or other sensors
demonstrated to be applicable during infiltration testing.
Monitoring installations in completed segments of the processed shale pile would
include (1) selected infiltration test sites as described above; (2) selected sites
associated with revegetation trenches such as those depicted in Figure 5-6. These
trench sites are appropriate because water harvesting efforts make these the most
likely initial locations of infiltrating water. Access tubes for neutron logging, ten-
siometers, suction cup lysimeters, or other monitoring devices shown to be suitable
during the infiltration testing would extend below the trenches into the processed
shale pile itself. Should appreciable pollutant movement be indicated by monitor-
ing within the processed shale pile, monitoring in the natural hydrogeologic realm
would be indicated.
-------
Along with the revegetation trenches, an intensive sampling program should also
be conducted in the vicinity of the toe of the completed spent shale pile. Lower
reaches of the pile may become saturated as a result of leaching for salinity control,
or because of subsurface movement of water from trenches. Leachate produced by
saturated conditions may flow out of the pile into downstream alluvium, or
downward into underlying formations. A possible array of monitoring facilities in
the toe of a spent shale pile is illustrated in Figure 5-7.
Monitoring in the Alluvium. Monitoring wells should be drilled in the alluvium
in locations where pollution from the spent shale pile is most likely to occur, such
as near the toe of the pile. Recommended procedures for constructing these
monitoring wells include drilling a 20- to 30-cm (8- to 12-in.) hole to the base of the
alluvium. A 10- to 15-cm (4- to 6-in.) diameter PVC casing should be installed to
the bottom of the hole. The casing should be perforated opposite the interval from
a few meters (several feet) below the static water level to the bottom. Clean pea
gravel of known composition should be used to gravel pack the well. The upper few
meters (several feet) should be filled with cement to form an annular seal. The wells
should be logged by a geologist during drilling and developed by airlifting and/or
pumping upon completion. A locking cap should be installed along with a suitable
barrier to prevent destruction.
Water samples should be retrieved by installation of suitable submersible pumps
for the reasons previously discussed. After well development, a submersible pump
should be installed and field tests performed during continuous pumping for
several hours or days. Temperature, electrical conductivity, and pH of the
discharged water could be measured. After completion of this phase, a determina-
tion should be made as to the length of pumping necessary before collection of a
water sample. At least two or three well volumes should be pumped before sample
collection. This procedure will allow collection of water samples typical of the
alluvium near the monitor well.
Sample collection should include field measurement of pH, specific conductance
and Eh. Water samples should be filtered and preserved at the time of collection
(127).
Appropriate sampling frequencies should be developed during the initial sam-
pling program. Initially, depth to water and field measurement of pH, specific con-
ductance, and Eh (or DO) should be monitored on a monthly basis. More detailed
chemical analyses (Table 5-14) should be performed on a quarterly basis unless ap-
preciable water quality changes are noted during the monthly sampling. Sampling
frequency should be reevaluated after each sampling year.
Analytical Methods for Leachates from Oil Shale-
Paul Mills and Ann Alford
This discussion will consider the generation of a leachate material for use in
testing for organic and inorganic parameters. When the leachate is generated, the
methods described in the preceding subsections on standard water analyses and
analysis of organic pollutants can be used (i.e., the leachate can be treated as a
water sample). At present, there is no standard method for extracting a leachate
from a solid material. EPA has proposed one under Section 3001 of the Solid
Waste Disposal Act as amended by the Resource Conservation and Recovery Act
of 1976 (128). This acetic acid extraction procedure is used to determine whether a
waste is to be classified as "hazardous" or not. EPA is also considering a "rain
leach" test to be applied to the materials classified as hazardous; the test simulates
rainfall leaching, and would be used to determine if a waste can be put in a
monofill, or should be placed in a hazardous waste disposal site.
Relevant Parameters—
To critically evaluate laboratory leachate generation methods, it is first necessary
239
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PSYCHROMETER ^X
ACCESS WELL
PIEZOMETER
SUCTION CUP LYSIMETER
OBSERVATION WELl
/
O
o o c
° 0
X
0
o
X
—
X
0
o
x
/
SPENT SHALE
0 0 0 ° 0 ° 0
00
ALLUVIUM O ° O
O ° 0 o n 0 o _
-? — r-H. ° 0 j— :' . ' — 7-°7—
BEDROCK
Figure 5-7. Possible monitoring facilities at the toe of the spent shale pile.
(Source: Reference 126)
-------
to consider leaching under natural conditions. Leachate is liquid that has contacted
solid material and has extracted and/or suspended constituents from it. The
character of the leachate depends on both the composition of the material and on
environmental factors, including pH, the redox potential, the chemical composi-
tion of the leachate, and temperature. Factors that primarily affect leachate
transport include the flow rate of the eluant and the surface area, porosity, and
permeability of the material leached. Factors that could affect the leaching of salts
are shale texture, retorting process, soluble salt concentration of the shale, degree
of compaction, seasonal precipitation patterns and surface infiltration, amounts
and types of vegetative cover, aspect, slope, and elevation of the surface of the
disposal pile, and degree of cementation in the disposal pile (129).
An ideal leaching test should control all these parameters and be quick and inex-
pensive. A principal concern of any test procedure is that of reproducibility; also
related to this is the comparability of test results from different wastes. Existing
laboratory tests fall into two main categories: Batch (shake) tests and column tests.
Shake tests consist of placing a sample of the material to be leached in a container
with a suitable eluant, agitating the mixture for a specific period of time, and
analyzing the resulting leachate. Shake tests are quick, simple, require minimal
equipment, are inexpensive, and reproducible. But the conditions chosen for the
shake test variables may be difficult to relate to environmental conditions, and the
results may be difficult to interpret. Column tests, in which the waste is packed in a
column and the leaching solution passed through, simulates the waste/leachate
migration found in disposal piles. The column test is good for predicting release
patterns over time. However, the column tests are limited by: problems from chan-
neling, nonuniform packing, unnatural clogging and biological effects, edge ef-
fects, longtime requirements, and difficulty in obtaining reproducible results.
Several factors affecting the parameter's concentration in the leaching tests are
discussed below.
Leachate Composition—The use of distilled water or other mild leaching solu-
tions allows the waste to create its own leaching environment, whereas a synthetic
leachate or strong chemical solution essentially controls the leaching environment.
Solid/Liquid Ratio—With a high solid/liquid ratio, many elutions will be
necessary to collect sufficient leachate for analysis of the leachable fraction of the
component. But a low solid/liquid ratio can produce low concentrations of the
parameters of interest and difficult analytical problems.
Time per Elution—Though the time per elution is arbitrary, the test should be
long enough to allow rapidly equilibrating species to approach equilibrium, yet
short enough to minimize biological growth, secondary effects, and consistent
saturation of the species of interest. The time should also be convenient to person-
nel if possible.
Temperature—Generally, leaching tests have been conducted at room temper-
ature, and the effects of temperature on the leaching pattern of the waste within the
range of average laboratory temperatures may not be great enough to justify
specially controlled temperature conditions. Temperature should be measured and
reported, however.
Agitation Technique—An agitation technique for shake tests is needed that pro-
motes mixing without causing waste particle or container abrasion. Methods such
as reciprocal shaking, wrist action snaking, or circular shaking are suitable pro-
vided they produce well mixed systems and are slow enough to avoid promoting
abrasion.
Surface Area Contact Between Waste and Leachate—For some wastes, the
amount of surface area in contact with the leaching solution can be important in
controlling parameter concentrations in the leachate. The surface area of a waste
may be controlled initially during sample preparation before the test by grinding,
cutting, etc., or by the agitation technique.
241
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Interpretation of Tests—
Caution must be exercised in data interpretation, since test data cannot always be
transposed directly to practice. It may be possible to correlate test conditions with
concentrations by running extensive verification tests correlating the behavior of a
waste in the test with the behavior of the same waste in a carefully monitored
disposal pile. Correlation coefficients could then be developed for parameters and
conditions similar to those in the verification study, and the tests results could be
used to estimate concentrations. A short leaching test cannot completely duplicate
the long-term leaching characteristics of a waste. The short test might completely
miss a parameter having exponential release, or it might over-estimate the release of
a parameter showing a concentration maximum. These patterns could be seen in a
long-term study, but they are difficult to determine in a short test. Shake tests are
designed to yield equilibria rather than kinetic data. Leachate generation under
natural conditions, by contrast, is a highly dynamic process rather than a static
one. Furthermore, the specific character of leachate, in terms of both quality and
quantity, will be site-specific. A recent publication summarizes a number of
leachate studies (130) and includes a discussion of leaching mechanisms and
leachate compositions.
Inorganic Analysis—
Leachate samples will present numerous difficulties in flame atomic absorption
analysis for heavy metals such as Cr, Ni, Fe, Pb, Cu, and Zn because of the
presence of complex matrices (as discussed for water samples in the preceding
subsection on standard water analyses). Detailed specific interferences for heavy
metals are given in References 131 and 132. Nonspecific interferences such as acids
or salts hinder the evaporation of the solution or the solvent and generally result in
a depression of the absorbance during metal determinations. Spectral or line in-
terference can often be avoided by judicious choice of an analyte resonance line
and by using a narrow band-width as close as possible to the width of the selected
line emitted by the hollow cathode tube. Element-specific interference effects are
expected to cause complications in leachate analyses. Alkali and alkaline earth
elements such as Na and K are subject to a wide range of interferences, but this can
be corrected by the addition of a more easily ionized element such as Cs at a con-
centration level considerably higher than that of the analyte atome. Ca and Mg are
interfered with by a number of common cations and anions, such as SOj, PO;,
CO?, HCOl, Na+, K+, and AL"*. An inorganic releasing agent, lanthanum, has been
found effective in suppressing interferences and in preventing formation of oxides
in the flame.
The COD/TOC ratio can be used to determine the reliability of either the COD
or TOC measurements. If the results of the analysis of a given leachate sample yield
a ratio of COD/TOC greater than the theoretical maximum value of 4.0, either the
COD or the TOC value is in question.
Organic Analysis—
Spent shale composition depends on the type of retorting process used and retort
conditions, with some spent shale containing up to 5 percent organic carbon. The
organic portion contains PAH's, some of which have carcinogenic and mutagenic
properties. The identity and solubility of specific organic components of spent
shale leachate should be determined. Techniques used to analyze organic com-
pounds in water are also used to analyze organic compounds in spent shale
leachates.
Researchers at the Denver Research Institute (133) have reported that some
potentially harmful organic compounds may be leached from spent shale by water.
Benzene extractions of several spent shale samples showed that 0.24 percent
(average) of the spent shale was benzene-soluble organic material, and wet shale (15
to 20 percent moisture) yielded more benzene soluble material than dry shale.
242
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When spent shale that had been extracted with water was extracted with benzene,
that spent shale benzene extract contained 0.13 percent soluble organic material,
indicating that 0.11 percent of the soluble organic material in the original sample
had dissolved in water. The benzene extract of this water extract contained only
about 20 percent (by weight) as much material as the shale benzene extract, but
some components were identified as azarenes and PAH such as benzo(a)pyfene
and 7,12-dimethylbenzanthracene.
A variety of analytical techniques were used in this study, but techniques to
detect PAH were emphasized. Leachate components were isolated from thin layer
chromatography plates after two-dimensional development with two solvent
systems and fluorescence detection. Fluorescence spots scraped from the TLC
plates were analyzed using mass spectrometry and liquid chromatography. Analysis
with nuclear magnetic resonance and infrared spectroscopy indicated low
aromaticity and surprisingly high alkane content of the extract mixture.
Analysis by gas chromatography (15.24-m or 50-ft Corasil SCOT column)
showed that the spent shale extract contained volatile (eluting in the 65 ° to 100 °C
or 149 ° to 212 °F temperature range) and semivolatile (eluting in the 100 ° to 300 °C
or 212° to 572 °F temperature range) components that appeared to be C,0 to C2S
hydrocarbons and some higher molecular weight compounds. Planned future
analysis by combined GC/MS should help identify specific extractable com-
ponents. Preliminary results indicated that LC (with ultraviolet and fluorescence
detection) and gel permeation chromatography are useful techniques to separate
extracts into fractions for further characterization by mass spectrometry or com-
bined GC/MS.
This work indicates the valuable information that can be obtained using
available analytical techniques. Spent shale leachates should be analyzed with
techniques designed to permit identification and measurement of as many organic
components as possible (133).
Solid Inorganics—Paul Mills
For a summary of existing trace element composition data for shale and its prod-
ucts and an evaluation of these data and related studies, refer to the EPA publica-
tion, Trace Elements Associated with Oil Shale and Its Processing (134). Although
some uncertainties and data gaps exist at present, a number of general conclusions
have been deduced from the available trace element data and studies.
For many elements, wide ranges of concentrations have been reported for oil
shale and its products. These ranges reflect natural geographic and vertical pro-
file variations in the shale, differences in retorting methods, and uncertainties
associated with various sampling and analytical techniques.
Compared to average rocks, oil shale contains much higher levels of Se and As,
moderately higher levels of Mo, Hg, Sb, and B, and lower levels of Co, Ni, Cr,
Zr, and Mn. Other elements are present in concentrations typical of common
rocks.
Most elements are not converted to volatile or oil soluble substances during
retorting and are consequently retained by processed shale. However, up to 30
percent of Hg, 15 percent of As, and 8 percent of Se in raw shale can be found in
shale oil, retort gases, and retort waters.
Most metals contained in retorted shale are not readily water soluble. However,
elements that form anionic species (Ca, Na, Mg, B, F, Mo, Se) can be leached
from retorted shales by percolating water.
Trace Elements in Oil Shale—
In recent years, considerable data on the minor element composition of oil shales
have accumulated. For many of the selected elements, reported levels vary by one
order of magnitude, and for a few elements, by two orders of magnitude. The
243
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ranges reflect at least three factors: (a) natural variations in oil shale samples in a
vertical profile, depending on mineral and organic matter composition, (b) natural
geographic variations, and (c) variations in measurements as a result of different
sampling, preparation, and analytical techniques. In most cases, it is difficult to
distinguish the relative importance of these three factors. For example, variations
between laboratories for shale from the same area are often as great as geographic
variations determined by the same laboratory with the same sampling method and
sample preparation (135).
Samples of overburden and spoils can be collected and prepared by many
methods, which vary with available resources, time, and purposes. In selecting a
method, care must be exercised that the chemical properties of the samples are not
altered during sampling and before analysis. No simple answers exist to the prob-
lem of collecting or to the question of sampling frequency. Good judgment and ex-
perience are required.
The types of analyses performed on solid samples are highly dependent on the
types of material samples. For solid piles or streams, the nature of the analytical
method rarely affects the sampling methods used, but the handling and preserva-
tion methods are affected.
Sampling methods for solids use two general techniques—grab sampling and
grab-and-composite sampling. Grab sampling is the general sampling technique
used where low precision is required. Grab-and-composite sampling is the more
precise technique. In most cases, the difference between the two is only a matter of
degree, since the sample collecting methods are identical. In the second method,
grab samples are collected periodically over the duration of the test and then com-
posited to form a single sample. The following sampling methods, although they
pertain mostly to coal, are readily adaptable to other solid streams:
ASTM Method D 2013-72: Sample Handling
ASTM Method D 2234-74: Gross Sampling Collection
ASTM Method E 300-73: Sample Handling and Collection
Caution should be exercised in transporting and processing samples for
laboratory analyses. Polyethylene plastic bags are recommended for transporting
samples from the field. Canvas (unless lined) and ordinary paper bags are not
recommended because these materials may absorb soluble salts from wet samples,
and the glue in the paper bag may interfere with accurate analysis for boron.
Galvanized equipment should be avoided if zinc is to be analyzed. Samples to be
analyzed for nitrate-nitrogen cannot be stored moist under warm conditions. Moist
or wet samples should be immediately frozen or spread to dry on waxed paper or
similar water-proof material, ground to 2-mm (3.94xlO~2 in.) size, and stored in
closed, water-resistant containers until analyzed. Knowledge of potential sources
of contamination and chemical transformations that may occur in samples is re-
quired. The principles of sampling are discussed in (136).
Sampling by drilling methods that involves a circulating fluid may potentially af-
fect the composition of soluble constituents in the sample, either by leaching out
salts or by impregnating the sample with contaminants from the circulating fluid.
This problem is particularly acute in sampling overburden and spoils in the western
United States. The drilling method affects the chemical composition of overburden
samples (137). Drilling fluids that used saline water or sodium bentonite, or both,
as the drilling mud, increased salinity and adsorbed sodium in samples, whereas
drilling with air or using water of relatively low salinity did not appreciably change
the sample composition. The use of an organic polymer developed for drilling fluid
use did not appreciably change sample composition.
Sample Preparation—
The first step in the preparation of solid samples is to ensure homogeneity. This
is accomplished by mixing (quartering and riffling) the sample and grinding it to
244
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less than 200 mesh. Drying with concurrent gravimetric determination of moisture
content is often required. The drying temperature must be selected to avoid loss of
volatile components. For very high moisture contents, drying may be necessary to
allow mixing, grinding, and sieving.
Elemental analysis by some techniques requires conversion of the element to the
liquid phase. For major constituents in coal ash, this is accomplished by a LiBO2
fusion and HNO3 acid dissolution (138). For minor or trace elements, LiBO2 fusion
may result in a loss of volatile elements because of the high temperature required
(138,139). The use of acid dissolution, although time consuming, alleviates this
problem. Several acid digestion techniques have been reported (69,140-142). Each
of these is appropriate for a limited number of elements.
Duplication of effort can be eliminated with the use of a perchloric acid digestion
(PAD) technique applicable to a large number of elements. A PAD technique has
been developed by the National Bureau of Standards (143). This technique includes
a slow digestion with nitric acid followed by an acid mixture (HC1, HNO3, HF),
then perchloric acid. Solid samples with low organic content may be digested
directly. Samples with high organic content, such as coal, must be ashed before
digestion. Ashing without loss of volatile elements can be accomplished with a low
temperature oxygen plasma asher.
Sample Analysis—
Once the samples have been treated and dissolved in appropriate reagents, in-
strumental and chemical methods can be used to measure their constituents. Such
instruments as AA, XRF, NAA, and ion electrodes may be used, similar to the
discussion for standard water parameters in the preceding subsection on standard
water analyses. Additional descriptions of the use of these techniques for solid
samples are found in Fruchter et al. (144) and Fox et al. (145).
Organics in Solid Samples—Ann Alford
Techniques used to analyze organic compounds in surface water and ground-
water are also used to analyze organic compounds in solid samples, such as
sediments, soils, and solid wastes. Special requirements to be considered for solid
samples are sampling techniques and extraction of organic components from the
solid sample.
Sampling—
The main objective in sampling is to obtain and preserve homogeneous,
representative samples with minimum contamination. To obtain representative
samples of carbonaceous spent shale, the quartering and riffling technique can be
used (124). To obtain homogeneous soil samples, large soil particles can be ground
and sieved until a uniform particle is obtained (124). Oil shale can be crushed to an
approximate size of 2 to 3 mm (.08 to . 12 in.) (146). When volatile components are
to be analyzed, however, grinding and crushing should not be used.
Sediments can be collected by inserting a sediment corer and using a clean
spatula to dig around the corer until the spatula can be inserted beneath the corer
(147). The sediment sample should be transferred to a clean glass sample bottle
with a screw cap lined with aluminum foil. The samples should be frozen,
transported in ice, and stored at temperatures below 0°C (32 °F).
Extraction—
Soxhlet Extraction—The most commonly used technique for removing organic
components from solid samples is solvent extraction in a Soxhlet apparatus, after
the sample holder (thimble) and apparatus have been extracted (with the same sol-
vent that is to be used for the sample) to remove any organic contaminants. Spent
shale samples have been extracted with double distilled benzene with the Soxhlet
apparatus surrounded with black shields to prevent sample component composi-
245
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tion changes induced by fluorescent light (124). Benzene/methanol mixtures are
also common solvents for sediment extraction, but no one solvent or mixture is
universally recommended and accepted (146,148).
Headspace Sampling Followed by Soxhlet Extraction—After addition of pure
water and an internal standard, sediments can be sampled for volatile components
with dynamic headspace sampling with a stream of purified nitrogen and trapping
of volatile organic components on Tenax-GC (147,149,150). While the sample is
agitated with a magnetic stirrer, headspace sampling is performed at room
temperature for 2 hrs and at 70 °C (158 °F) for 2 additional hrs. The residual solids
are then extracted in a Soxhlet apparatus with methanol followed by methylene
chloride (149). The methanol extraction step is necessary to change from an
aqueous to an organic solvent. To remove organics remaining in the water from the
headspace sampling step, liquid/liquid extraction techniques are used.
Compounds not usually considered to be volatile (such as pyrene, naphthalene,
and substituted naphthalenes) can be removed from the sample by headspace
sampling. This technique is especially suited for the series of one to three con-
densed ring aromatic hydrocarbons (147). Compounds more volatile than phenan-
threne are substantially removed, and 20 percent of the total amount of phenan-
threne in a standard solution was removed during headspace sampling (144).
Headspace Sampling Followed by Liquid Chromatography—An alternative
technique employs dynamic headspace sampling for volatile components followed
by coupled-column LC for nonvolatile components (147,150). This technique re-
quires minimal sample handling, and organic-free water is the only solvent needed
for sample preparation.
After headspace sampling, water remaining in the sample container is pumped
through a liquid chromatograph pre-column packed with Bondapak CIS. This pre-
column is then attached to a gradient elution liquid chromatograph, and sorbed
compounds are eluted with methanol/water, beginning with 30 percent methanol
and increasing to 100 percent methanol in 40 min. Components can be observed
with ultraviolet and fluorescent detectors, and fractions can be collected for subse-
quent analysis by spectroscopic and mass spectrometric techniques.
Because the liquid chromatographic technique becomes more effective as the
headspace sampling technique becomes less efficient, the two procedures comple-
ment each other very well. These procedures were used to detect petroleum-derived
hydrocarbons in sediment taken from the site of an oil spill that had occurred 10
years before samples were collected (150).
Sonication—Ultrasonic energy has been used to extract organic residues from
soil, and the method is reported to be rapid, reliable, and sensitive (151). Compar-
ison of extraction efficiency with 30-sec ultrasonification and 8-hr Soxhlet extrac-
tion showed only small differences in recoveries of organochlorine insecticides
added to soil (151). With sonication, recoveries of eight insecticides exceeded 95
percent when 10 to 100 g (154 to 1,540 grains) of each compound was added to 50 g
(770 grains) of oven-dried soil. Soxhlet extraction of soil after sonication extraction
produced only negligible amounts (F 1 percent) of standards that had been added
to the soils. Extraction of organochlorine compounds was affected by the solvent,
soil sample moisture content, and soil type. With one clay soil, best recovery was
achieved when the soil sample was saturated with moisture; but soil moisture did
not seem to be a critical factor for good recovery. No evidence of breakdown or
structure alteration during extraction was observed in the four organochlorine in-
secticides (heptachlor, heptachlor epoxide, dieldrin, and aldrin) tested. Acetone
was recommended as the extracting solvent to be used.
To remove organic compounds (hydrocarbons, phthalates, polycyclic aromatic
hydrocarbons, fatty alcohols, sterols and stanols) from an estuarine tidal mud,
solids from centrifuged mud were extracted with a heptane and isopropanol mix-
ture (1:4) and sonication (152).
246
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To determine the best technique for extraction of petroleum-derived compounds
in estuarine and marine sediments, benzene extraction with a Soxhlet apparatus,
sonication, and reciprocal shaking were performed (153). The largest amount of
extracted material was recovered with the reciprocal shaker. Comparison of
benzene, hexane, and chloroform as extracting solvent showed that the largest
quantity of material was recovered with benzene.
Steam Distillation—An apparatus for steam distillation of pesticides and in-
dustrial chemicals from sediments and tissue is commercially available (151).
Because solvent extraction techniques remove lipids, waxes, and related natural
products along with pesticides and industrial chemicals, chromatographic separa-
tion procedures may be necessary to remove interfering compounds before extracts
can be analyzed. The distillate extract, however, can usually be analyzed by GC
without further cleanup procedures. A sediment sample blended in water is placed
in a distilling flask. When the mixture is boiled, steam distillate condenses on inner
walls of the cooling jacket. Condensate passes through a solvent (such as isooctane
or toluene) that traps organic compounds. Analysis of Hudson River sediments
contaminated with polychlorinated biphenyls (PCB) showed that 78 percent of the
PCB were steam-distilled within 60 min (154).
Sulfur Removal from Extracts—Some sediment extracts contain substantial
amounts of elemental sulfur, which interferes with analysis. Sulfur can be re-
moved, however, by percolation of the sample extract through active copper
powder (155).
Conclusion—
Before analytical techniques are selected for survey analyses and monitoring of
the environmental effects of oil shale processing, more work is needed to determine
optimum sampling and extraction procedures for solid samples.
HEALTH TESTING APPROACH AND METHODS
David Coffin
The prime purpose of testing as applied to the oil shale industry is to determine
potential health hazards to persons employed in the industry and to persons han-
dling products, as well as persons in the general population who come in contact
with airborne or waterborne effluents from the industry or from combustion of
fuels in power sources. It is prudent that in the de novo approach to such a problem
all points be covered where human contact with a product or effluent and the like is
possible. Additionally, it is axiomatic that whole animal testing should be carried
out by the specific route by which human contact would occur. For example, mine
dust and fumes from products should be tested by inhalation exposure, oily prod-
ucts by skin bioassay, and contamination of water by ingestion either directly or
through the food chain route. If a product might exist as both a liquid and a fume,
skin bioassay and inhalation exposure should be employed.
A second order of testing is concerned with characterization of the biological and
chemical profiles of products and emissions to gain an identification of the toxic
chemical to obtain a better understanding of the relationship of the technological
process to the biological effects. A possible extension of the latter (which will only
come with time and a coordinated approach along with prime safety testing) is that
some of the short term tests may become predictive of direct health parameters,
thus gaining a saving of time and funds in the general health testing of synfuels.
This is one of the objectives of the Interagency Matrix Approach mentioned under
Health Effects. An example of the value of such short-term testing already exists in
the Matrix Approach where combined Ames testing and chemical fractionation is
elucidating the presence of reactive organics not found in analogous petroleum
products which may well explain basic differences in toxicity between the synthetic
fuels and petroleum. By such means it is also possible to follow the effects of
247
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TABLE 5-15. HEALTH TESTING IN PROGRESS IN THE OIL SHALE INDUSTRY
Technology step
Mining and rock
crushing
Retorting
Retort product
Refinery feed
stock
Refinery
Refined
products
Combustion
products
Potential toxicant Possible route of contact
Shale rock dust
Retorted shale dust
Gaseous emissions
Retort waste water
emissions
Raw shale crude
(retort tar)
Upgraded retort
product (shale
crude)
Various airborne
effluents
Diesel fuel, jet fuels,
gasoline fuel oil,
residual oil, etc.
Gaseous and
particulate emissions
Inhalation
Inhalation
Skin contact
Inhalation
Ingestion
Skin contact
Skin contact
Inhalation
Skin contact,
inhalation of fumes;
Ingestion via food
chain
Inhalation
Prime health testing
Inhalation exposure
of animals
Inhalation exposure of
animals
Skin carcinogenic
bioassay in animals
Ingestion in animals
Skin carcinogenic
bioassay in animals
Toxicity by skin contact
Skin carcinogenic
bioassay in animals
Toxicity by skin contact
Extrapolation from other data
on basis of chemistry
Skin carcinogenic bioassay
Toxicity by skin contact
Inhalation exposure of animals
Food chain testing
Gases - extrapolation from other
data on basis of chemistry
Second order testing
Ames testing and other
mutagenic tests, in
vitro toxicity testing
Ames testing, other mutagenic
tests on fractions; Short-
term carcinogenic testing
Ames testing, other mutagenic
testing on fractions
Short-term carcinogenic testing
Ames tests and as above
Ames testing and as above
Ames tests and as above
on particulate emissions
-------
hydrotreating, influence of boiling point and secondary treatment of products in
the reduction of mutagenicity. If such mutagenicity can be shown to be directly
related to carcinogenicity in a given class of materials, then it is possible that such a
test could eventually successfully supplant a more time consuming, expensive
whole skin bioassay for example.
We may expect that a high order o.f health safety measures will be built into the
developing oil shale industry. This will be accomplished by the use of closed
systems for retorting or refinery streams wherever possible and by the application
of stringent control measures for effluents. Thus, in most instances, carcinogenic
or otherwise toxic material will be handled in a manner so as to minimize human
contact.
Because of the possibility of equipment malfunction, a no-risk situation can
never be absolutely assured. Thus, it is important to have an understanding of the
toxic potential of internal refinery streams and the like so that appropriate
measures may be taken in the case of emergency. While it is known from the ex-
perience with petroleum that carcinogenicity is generally a function of boiling
point, this information may not be directly relatable to synthetic fuels where car-
cinogenic compounds not found in petroleum, and with possibly different boiling
point distribution, are known to exist.
While effluents from retorts or refinery are predictably well controlled, even
minimal amounts gaining entrance to air or water might be a significant contribu-
tion to ambient concentrations of certain toxicants if an industry of the magnitude
of certain current predictions develops.
Application of tests to various industrial technological steps is summarized in
Table 5-15.
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SECTION 6
ENVIRONMENTAL GUIDELINES
This section presents suggested interim environmental goals applicable to an oil
shale industry. The basis for past air and water permit decisions is discussed. These
goals/guidelines should be considered as a starting point for detailed discussions on
specific project environmental control requirements. Variations depending upon
project location, process technology, and size of project are expected.
This section also contains a summary of EPA policies and procedures related to
an oil shale project. This discussion is meant to provide oil shale developers and the
public with an understanding of the logic and process which EPA uses in the
evaluation of an oil shale project. Finally, this section presents the oil shale in-
dustry position on environmental impacts and regulatory policies.
CRITERIA FOR ENVIRONMENTAL GOALS
The existing legislative and regulatory framework for the oil shale industry is
described in Section 1. Section 2 describes a regulatory approach to defining en-
vironmental standards that should be met by any oil shale facility and by an oil
shale industry. The environmental goal applicable to the oil shale industry should
be the minimization of environmental impacts. Minimization must be defined in
terms of potential environmental harm, economics, energy penalty, and intermedia
tradeoffs. A "no significant degradation" policy has been quantified for a few air
pollutants (SO2 and particulate), and it has been qualitatively stated for water
quality. Protection of minimum stream flows for aquatic life, provision of ade-
quate water quality for applicable water use, protection of health- and welfare-
related air quality aspects, minimization of detrimental land disturbance in order to
preserve adequate wildlife habitat, and protection of valuable socioeconomic,
cultural, historical, and aesthetic values are environmental criteria that constitute
the basis for defining specific environmental standards.
SUGGESTED INTERIM ENVIRONMENTAL GOALS
The source standards and ambient standards discussed in Section 1 apply to in-
dividual oil shale facilities and to an oil shale industry. The ambient standards will
have the more direct impact on the industry (rather than on any individual facility)
because the Piceance Basin and the Uinta Basin (and Colorado River Basin) have
finite carrying capacities for air pollutants and water pollutants/water use. At-
tempts to define the size of an oil shale industry that could fit into these finite
carrying capacities have been limited by inadequacy of data and comprehensive
predictive techniques. Facility siting is an obvious major factor in determining the
ultimate size of an oil shale industry.
The framework for appropriate environmental guidelines consists of existing
legislative requirements, environmental standards, and source regulations. Deci-
sions made as to what constitutes Best Available Control Technology (BACT) and
best practical technology (BPT) in permits issued for oil shale and related facilities
also provide precedent criteria for requirements to be applied to future oil shale
projects.
The goals discussed below should be considered starting points for detailed
discussions on specific project environmental control requirements.
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Air
Air emissions result from the construction, mining, retorting, and upgrading
phases of an oil shale facility. Control requirements for certain pollutants are in-
cluded in Prevention of Significant Deterioration (PSD) regulations, which dictate
that these emissions be controlled by the use of BACT. Controlled emissions are
then used as input to computer air quality diffusion techniques in order to predict
the estimated maximum ambient air quality concentrations that may occur as the
result of operation of the facility. These predicted concentrations are then com-
pared with applicable PSD increments, State ambient air quality standards, and the
National Ambient Air Quality Standards. If BACT is provided and all ambient
standards are met, a permit may be issued.
A future regulatory constraint with which an oil shale industry will have to com-
ply is the protection of visibility in nearby Class I areas. The Flat Tops Wilderness
Area is the closest Class I area to oil shale country at the present time. The National
Park Service is considering requesting Class I status for Dinosaur and Colorado
National Monuments. Also, there are wilderness study areas located on the edges
of Piceance Basin, which, if they were designated as wilderness and also
redesignated to a Class I status, would receive visibility and PSD increment protec-
tion under Section 165 of the Act. Final regulations regarding visibility are ex-
pected in late 1980. Although it is premature to estimate the exact constraints these
regulations may impose, it is reasonable to assume that SO2 and NOX, which
transform to SO4 and NO3, and primary fine particulates will have to be mini-
mized, since they are the key contributors to visibility degradation.
In order to provide guidance for future oil shale developers, PSD requirements
for four permitted facilities are summarized below. Additional guidance may be ex-
tracted from air NSPS for "similar" facilities as listed in Appendix D.
1. Colony development operation (46,000 BP) (1)
Construction
Paved access roads
Routine application of dust suppressant to all disturbed areas
Gravel or oil service roads
Mining and solids handling
Wet suppression techniques used in mine
Primary crushing
Baghouse collectors on crushing, conveying and transfer points; 99.7 per-
cent collection efficiency
Traveling stacker with water spray
Underfeed reclaim
Covered conveyors
Retorting/upgrading (TOSCO II)
Particulate scrubbers on preheat system (99.8 percent control at 762 mm or
30 in. W P water), elutriators (99.8 percent control at 1,016 mm or 40 in. W
P), and processed shale moisturizer (99.0 percent control at 508 mm or 20
in. minimum W P)
Incineration of hydrocarbons in preheat system to less than 100 ppm weight
carbon
Treatment of raw process sour gas to less than 228.84 mg H2S per scmd
(0.10 grain H2S per scfd) of fuel gas (457.68 mg per scmd or 0.20 grain per
scfd total S)
A combined 99.6 percent SO2 removal efficiency on acid gas via a three
stage Claus plus tail gas cleanup
20 percent opacity
258
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Fuel gas combustion limits for particulate and nitrogen oxides of 2.29 and
17.17 kg per million Cal (0.02 and 0.15 pound per million BTU), respec-
tively
Product/waste handling
Application of chemical dust suppressant on processed shale pile
Rapid revegetation of processed shale pile
Double seals on floating roof storage tanks containing "high" vapor
pressure liquid
Routine maintenance on pumps, valves, compressors and seals
2. Union Oil Company (9000 BPD module) (2)
Construction
Chip and seal construction roads
Routine application of dust suppressant to parking lot and high volume
roads
Mining and solids handling
Routine wetting/dust suppression techniques during mining
Primary and secondary crushing underground
Baghouse collectors on crushing, conveying, and some fugitive handling
emissions; 99.5 percent collection efficiency
Baghouse collectors on "finish feed" screening; collection efficiency 99.8
percent
Underfeed reclaim
Covered conveyors
Retorting (Union B)
Treatment of raw process sour gas via the Stretford process to a concentra-
tion of 137.30 mg H2S per scmd (0.06 grain H2S per scfd) of fuel gas
(1098.41 mg scmd or 0.48 grain per scfd total S)
Stretford efficiencies of 99.77 percent for H2S and 97.9 percent overall
sulfur
20 percent opacity
Fuel gas NOX combustion limits of 34.35 kg per million Cal (0.30 pound
per million BTU) for recycle heater and 22.90 kg per million Cal (0.20
pound per million) for steam boilers
Product/waste handling
Vapor recovery on tank truck loading
Routine maintenance on pumps, compressors, valves, flanges
Application of chemical dust suppressant on processed shale pile
Rapid vegetation of processed shale
3. C-b shale oil venture
Construction
Routine application of chemical dust suppressants to disturbed areas
Mining and solids handling
20 percent opacity on mine vent
Use of low sulfur fuel oil in ANFO
Retorting (modified in situ)
Treatment of retort off-gas via a Stretford unit to 99.0 percent overall
sulfur recovery and a H2S concentration in off-gas of less than 15 ppm
Fuel oil combustion limits for steam generation of 11.45 and 91.60 kg per
259
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million Cal (0.10 and 0.80 pound per million BTU) for particulate and SO,,
respectively
Product/waste handling
Rapid revegetation of run-of-mine shale
4. Rio Blanco Oil Shale, Inc. (1000 BP) (3)
Construction
Routine application of chemical dust suppressants to disturbed areas
Mining and solids handling
20 percent opacity on mine vent
Retorting (modified in situ)
Treatment of retort off-gas via an SO2 scrubber to a 90.0 percent overall
sulfur recovery and no greater than 250 ppm SO2 in the off-gas
Fuel oil combustion limits of 11.45 and 91.60 kg per million Cal (0.10 and
0.80 pound per million BTU) for particulate and SO2, respectively
Product/waste handling
Rapid revegetation of run-of-mine shale
In addition to the control technology requirements listed above, the PSD permits
have included requirements for stack and ambient monitoring. Primary emphasis
for "first generation" plants will continue to be on source characterization.
Water
A no-discharge-of-pollutant concept is a desirable goal for oil shale facilities. To
accomplish this goal, maximum recycle/reuse strategies will have to be employed.
Treatment of internal streams for reuse and treatment of streams discharged to sur-
face water or groundwater will be necessary. Consumptive use of water should be
minimized, since this practice provides the double benefit of minimizing water
quality degradation (due to concentration effect) and conserving water for other
users in a water short area. Primary sources of potential wastewater streams may be
categorized into three principal sources: (1) mine dewater; (2) process water; (3)
leachate. Treatment of any potential discharge must comply with best available
technology economically achievable (BATEA) and best management practices
(BMPs) as defined by the NPDES permitting authority. Water quality criteria and
applicable stream standards must also be met. These standards are discussed in
more detail in Appendix D. Also, Colorado and Utah have adopted antidegrada-
tion policy statements in their water quality planning processes.
In order to provide guidance for future oil shale developers, NPDES permit re-
quirements for three permitted in situ facilities are summarized below. See also Ap-
pendix D.
1. Rio Blanco Oil Shale, Inc. (CO-0034045) (4)
This permit is for the pump testing and mine dewatering phase only. No
discharge of process water is allowed under this permit.
Parameter Limit
Flow N/A
Total suspended solids 30 mg/1 30 day average
45 mg/1 7 day average
Total dissolved solids 3000 mg/1 daily max
Fluoride 3.0 mg/1 daily max
Boron 5.0 mg/1 daily max
Oil and grease 10 mg/1 grab sample
PH 6.0 to 9.0
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This permit has been proposed (5) for revision to extend through December 31,
1980. Limits are as shown below.
30 day Daily max
Flow N/A N/A
TSS 30 mg/1 45 mg/1
TDS 1200 1800
Fluoride 2.0 3.0
Boron 1.0 1.5
NH3 as N N/A N/A
Phenol N/A N/A
Oil and grease N/A 10
pH 6.0 to 9.0 N/A
2. C-b shale oil venture (CO-003961) (6)
This permit is for the pump testing and mine dewatering phase only. The permit
allows discharge of treated mine water and runoff; no discharge of process water is
allowed. Limits are shown below.
Parameter 30 day average Daily max
Flow —
10% of Piceance Creek 10% of Piceance Creek 10% of Piceance Creek
TSS 30 mg/1 45 mg/1
TDS 1200 mg/1 1800 mg/1
F — 9.0 mg/1
B — 3.5 mg/1
NH3asN — 1.3 mg/1
Cl — 0.02 mg/1
Phenol — 0.2 mg/1
Al-dissolved — 1.1 mg/1
Fe 3.5 mg/1 7.0 mg/1
Cd — —
Cu — 0.24 mg/1
Hg — 0.00005 mg/1
Ag — 0.00025 mg/1
Zn — —
Oil and grease — 10 mg/1
pH — 6.0 - 9.0
Note: All parameters are total unless noted as dissolved.
3. Occidental Oil Shale Inc. (CO-0029947) (7)
Process water is collected in a sump and sent to a steam boiler for steam genera-
tion. Boiler blowdown goes back to the mine. Therefore, no discharge of process
water occurs. Excess mine water may be discharged onto waste shale and is limited
as shown below.
30 day average Daily max
TSS 30 mg/1 45 mg/1
Fe 3.5 mg/1 7.0
Oil and grease — 10.0
pH — 6.0 to 9.0
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Since no permits for oil shale processing have been issued, other than a no-
discharge-of-process-water concept, little guidance from past decisions is available.
Qualitative guidance to help define BAT and BMP is presented below. This
"crystal ball" guidance should be considered as a starting point for detailed discus-
sions on specific projects.
No discharge of retort water
No discharge of oily process water
Reinjection of mine water into similar quality aquifers
Diversion of surface runoff from process areas
Collection of runoff from disturbed areas in sedimentation ponds
Collection and containment of processed shale pile leachate and runoff
No discharge of TDS wherever practicable unless total discharge is less than 0.9
tonne (1 ton) per day of salt
Treatment of process water prior to disposal on processed shale pile whenever
practicable
In addition to the effluent limits established in the permits issued to date, source
monitoring requirements have been defined. These have included routine (i.e.
monthly grab samples) samples for the permitted parameters, plus characterization
of a suite of parameters at high and low flows during the year.
Solid Waste
The types of solid waste to be handled from an oil shale project include pro-
cessed shale, raw shale fines, spent catalysts, and sludge. The largest volume
material is processed shale. Unlike for air and water, no Federal permits have been
required of oil shale developers for solid waste disposal. Regulations required by
the Resource Conservation and Recovery Act promulgated in February, May, and
October of 1980 defined hazardous waste characteristics and safe treatment,
storage, and disposal practices for hazardous wastes. Spent catalysts and sludge are
likely to be found hazardous but processed shale is likely to be treated as a solid
waste. Requirements at 40 CFR 257 govern solid waste disposal. Requirements at
40 CFR 260 will include characterization of wastes, groundwater monitoring, and
disposal practices defined as Best Engineering Judgment on a case-by-case basis by
the permit writer.
In lieu of definitive past permit requirements, the "crystal ball" concepts and
practices listed below may be used as a starting point for detailed discussions on
specific projects if a solid/hazardous waste permit is found to be necessary.
Isolation and containment of hazardous wastes such as spent catalysts
Record keeping and reporting of all hazardous wastes
Provision of an impermeable layer at the bottom of the processed shale pile in
order to prevent potential leachate from entering the groundwater system
Provision of an interface of soil-like material (about 30 cm or one foot) on top of
processed shale to provide the establishment of vegetation
Facilities that treat, store, or dispose of hazardous wastes should not be located
in the 100-year flood plain, in wetlands, in critical wildlife habitat, or in recharge
areas for sole source aquifers
Because there is no experience with disposal and management of massive
amounts of processed shale (about 18 million tonnes or 20 million tons per year for
a 50,000 BPD surface retorting operation), proper disposal techniques and proper
monitoring of compactive efforts, pile moisture profile, and pile movement must
be developed and experienced with the first generation projects. Thus experience
will, in return, provide information for development of better disposal practices
for second generation projects and for the development of subsequent regulations
specific to the industry.
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EPA Policies and Procedures
Oil shale developers have requested further guidance from EPA in a number of
policy/procedural areas. This section responds in a summary fashion to those re-
quests. Topics addressed include:
PSD increment consumption
NAAQS policies
Air modelling responsibilities
Wilderness areas
PSD monitoring
Permit basis, i.e. BACT, BMP/costs
Permit lifetimes
Consolidated permits
Consolidated hearings
Completed permit application
Permit enforcement procedure
Regulation certainty
Stream classifications
Salinity
TSCA applicability to shale oil
Program delegations
Additional information and clarification may be obtained via discussions with
appropriate Regional and Headquarters EPA officials. The following discussions
assume the reader's familiarity with the issue.
PSD Increment Consumption—
The nearest Class I area to oil shale country is Flat Tops Wilderness Area. It is
managed by the United States Forestry Service (USFS). Potential oil shale project
distances from the nearest point of Flat Tops are as follows: Colony (60 km or 36
mi), C-b (60 km or 36 mi), C-a (85 km or 51 mi), Union (55 km or 33 mi), Superior
(65 km or 39 mi), Chevron (65 or 90 km, 39 or 54 mi), Exxon (70 km or 42 mi), U-a,
U-b (.150 km or .90 mi), Geokinetics (.175 km or .105 mi), TOSCO-Sand Wash
(.175 km or .105 mi), and Paraho (.150 km or .90 mi). It is commonly believed that
the PSD Class I increments constitute the limiting constraint to the size of an oil
shale industry. PSD Class II increments will determine how large an individual
facility may be and how closely spaced separate oil shale projects may be located.
Accurate estimates of the ultimate size of the industry or its spacing cannot be
developed until accurate emissions data, better knowledge of air dispersion pat-
terns in an area of relatively complex terrain, and a refined analytical tool to better
estimate impacts are developed. Based upon preliminary screening studies,
however, Class I increments may limit the industry to a size of 200,000 to 400,000
BPD (private communication from Joseph, EPA Region VIII, to T. Thoem, EPA
Region VIII, April 1976; memo from T. Thoem, EPA Region VIII, to EPA File
3-1-7-1-9, April 1979). This estimate has caused concern for several potential
developers who feel that there may be no increment left when they are ready to
develop.
The Environmental Protection Agency has a policy of processing PSD permit
applications on a "first come, first served" basis. The time point is determined by
the date at which an application is determined by EPA to be "complete." The
Agency has sought comment on other allocation systems for the consumption of
PSD increments, but no other systems stand out as being more equitable or attrac-
tive at the present time. EPA believes strongly that it should not place value
judgements on types of oil shale projects to receive priority treatment. When the
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States take over the PSD program, they may wish to prescribe value judgements
based upon State priorities and objectives.
When the PSD Class I increment is consumed, four options are available. First,
all future permits may be denied (8,9). Second, future applicants may provide off-
sets for their project emissions by improving control of existing facilities. Third,
the project proponent has the opportunity to demonstrate to the Federal Land
Manager that air quality related values (including visibility) will not be adversely
impacted, notwithstanding violations of the Class I increments. If the Federal Land
Manager concurs and so certifies to the PSD permitting authority, the permit may
(not shall) be issued. A fourth option would necessitate a Congressional redesigna-
tion of the Class I area to Class II.
By linearly adding cumulative impacts from each source, EPA is tracking incre-
ment consumption. This approach will continue even though it would physically re-
quire the winds to blow from different directions at the same time, until the incre-
ment is consumed. The Agency also will continue working on modification to a flat
terrain regional model (10) which has been developed. This may be applied to
assess cumulative impacts. The ultimate need is the development of a regional com-
plex terrain model.
National Ambient Air Quality Standards Policies—
Federal lease tracts C-a and C-b received a one-year lease suspension in part
because of measured concentrations of particulate, hydrocarbons, and ozone
which exceeded the NAAQS. Correspondence between EPA and DOI (private
communications from Kleppe, Department of Interior, to Train, U.S. En-
vironmental Protection Agency, June 1976; from Train, EPA, to Kleppe, DOI,
July 1976; from Farrand, DOI, to Quarles, EPA, February 1977; from Costle,
EPA, to Farrand, DOI, March 1977; from Green, EPA, to Rutledge, Area Oil
Shale Supervisor, July 1977), existing regulations (40 CFR 51.18), interpretative
rulings (12/21/76), and guidance from EPA Headquarters to the Regions (private
communication from Tuerk, EPA, to Regional Administrators) have established
EPA policy on this issue. The policy is summarized as follows. Concentrations of
particulate matter attributable to native soil undisturbed by man may be dis-
regarded. The hydrocarbon "standard" is not an enforceable standard; rather, it is
a guide to show achievement of the ozone standard. The ozone standard has been
revised from its previous level of 160 mg/m3 to 240 mg/m3 (6.99xlO"s grains/ft3 to
1.05x10-" grains/ft3). No valid concentrations above about 170 mg/m3 (7.43xlQ-!
grains/ft3) have been recorded. Further, much of the contribution to the elevated
concentrations must be considered naturally caused, and hence subject to 40 CFR
51.18 discounting.
Air Modelling Responsibilities—
The project proponent must demonstrate that emissions from the proposed pro-
ject will not violate any applicable ambient standards. EPA has published guidance
on acceptable air quality models (11,12). It is necessary for a project proponent to
demonstrate the equivalency of a proposed substitute model. Opportunity must be
made for a public hearing. EPA feels at this time that the development, application
and validation of other than guideline models is the responsibility of the project
proponent for single source site specific impacts (within 50 km or 30 mi). The
Agency is trying to develop multi-agency interest in the development of an "oil
shale country" regional complex terrain model.
Wilderness Areas—
Several areas in and near oil shale country have been designated for further study
for possible wilderness classification. These areas, if so designated by the BLM or
USFS, do not receive automatic Class I designation. Redesignation may occur only
via Congressional or State action.
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The National Park Service has made a preliminary finding that Colorado Na-
tional Monument and Dinosaur National Monument deserve redesignation to
Class I status (13). Congressional or State action is necessary for this to occur.
PSD Monitoring—
As provided at 40 CFR 52.21 (n), ambient monitoring may be required by EPA
for the source to establish baseline air quality (up to 1 year preceding permit ap-
plication) and to determine the impact of the operation of the source. The
Alabama Power vs EPA decision has expanded the number of pollutants for which
monitoring may be required. EPA revised regulations implementing the Alabama
Power decision are due to be promulgated by June 2, 1980.
It has been the past practice of EPA Region VIII to allow potential oil shale
developers the opportunity to demonstrate that air quality data collected near their
proposed site are transferable and representative. The extensive air quality
monitoring performed at Federal lease tracts C-a, C-b, and U-a, U-b have
characterized the air quality in oil shale country for several pollutants. Concentra-
tions of SO2, NOX, H2S, and CO have been detected at the minimum detection
limits of the instrument. In the absence of a major new source of these pollutants
becoming operational prior to another developer's PSD application, those data
should be representative of the area. EPA has recommended that no nonmethane
hydrocarbon monitoring be performed (9). Therefore, the parameters to be con-
sidered for a baseline monitoring program would include ozone, visibility, fine par-
ticulates (including chemical characterization for SO4 and NO,), and certain trace
elements which are regulated by the Act and which may be emitted by an oil shale
facility, e.g. mercury.
Meteorological data should be obtained at the project site. Both low level and
upper air data should be collected. The methodology used, the duration, and the
frequency must be dictated by how the data will be used. If data will be collected
for model development/refinement, short term intensive upper air data may be col-
lected under representative conditions. If data are being collected to characterize
general annual wind patterns, tower data may be suitable. If low level drainage
must be defined for modelling purposes, surface winds may be representative.
PSD permits issued to date have required a minimum amount of operational am-
bient monitoring. Emphasis had been placed upon extensive source monitoring in
order to characterize all potential emission streams. As we gain more confidence in
estimated emissions data and as (if) the industry grows, a shift will probably occur
toward less source monitoring and more ambient monitoring. All monitoring must
observe proper quality assurance procedures which have been defined by EPA (14).
Permit Basis—
The logic behind the evaluation of any permit application for a prospective oil
shale developer is and will be as follows. First, the proposed pollution control
equipment must represent best control technology as defined by EPA. Second,
controlled residuals must not cause or exacerbate ambient standards.
The concept of BACT for air emissions control has been defined (8,9) as the
maximum degree of reduction determined on a case-by-case basis taking into ac-
count energy, environmental, and economic impacts and other costs. Standards of
Performance for water effluent control must reflect the greatest degree of effluent
reduction achievable through application of the best available demonstrated con-
trol technology processes, operating methods, or other alternatives including
wherever practicable a standard permitting no discharge of pollutants. In
establishing performance standards, EPA shall consider the cost of achieving the
effluent reduction, any nonwater quality environmental impact, and energy re-
quirements. Although disposal standard practices have not yet been defined for
solid waste disposal, it appears that the concept of Best Engineering Judgment will
be used. Factors associated with BACT and BAT will presumably help define BEJ.
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Because industry wide performance standards do not exist for oil shale, all per-
mit evaluations for BACT and BAT will be on a case-by-case basis. After applica-
tion of BACT and BAT, the permit writer will assess the residuals impact on am-
bient air and water. If it is predicted that applicable PSD increments or stream
standards will be violated, better control than prescribed by BACT or BAT must be
employed. This may be accomplished by Devaluating the economic and energy
costs associated with BACT or BAT. Since it appears that PSD Class I air quality
increments may be a limiting constraint to the ultimate size of the industry, EPA
Region VIII has encouraged potential oil shale developers to provide "better than
BACT" controls in order to maximize the amount of oil production from the area.
Guidance on NPDES permitting strategy and procedures has recently been pro-
vided at 40 CFR 121-125 as published in Federal Registers of June 7, 1979, and
June 14, 1979. It should be pointed out that critical definitions such'as navigable
waters appear in these revisions. In essence, navigable waters are defined as any
flowing waters, wetlands, or impoundments. It should also be pointed out that the
NPDES permit for new sources is now required prior to construction of the source.
A final NPDES permit may not be issued until a final EIS, if necessary, has been
issued. It has been past practice for EPA to encourage potential oil shale
developers to apply for NPDES permits even if they anticipate no discharge. The
developer will be in a more advantageous position in case of future enforcement ac-
tions.
Permit Lifetimes—
Concern has been expressed by oil shale developers over changing rules and
regulatory uncertainty. PSD permits issued by either EPA or the State are issued
for the life of the project. Situations which could affect the validity of a PSD per-
mit include (1) failure to commence construction within 18 months of receipt of the
permit; (2) violation of permit conditions; and (3) Congressional changes in the
Clean Air Act. NPDES permits are restricted to 5-year time periods by Section
402(b)(l)(B) of the Clean Water Act. Application must be made by the project pro-
ponent for permit renewal at least 180 days prior to its expiration. Hazardous waste
permits issued pursuant to RCRA are issued for an initial 10-year period with pro-
visions to review permit conditions at 5-year intervals. UIC permits are treated the
same as RCRA permits.
Factors considered by EPA in the renewal of permits include new information on
health or environmental risks, changes in the national standards, and changes in
the type or volume of waste.
Consolidated Permits—
Proposed regulations designed to consolidate various program and procedural
requirements under the RCRA, UIC, NPDES, and PSD programs were published
at 40 CFR 122, 123, and 124 on June 14, 1979. Promulgation occurred in May
1980. Draft consolidated permit application forms have been published. Final ap-
plication forms for all parts are due to be available by April 1981. This application
covers RCRA, UIC, and NPDES permit requirements. Consistent procedures
among five regulatory programs—RCRA, UIC, NPDES, 404, and PSD—are pro-
posed. In addition, the agency intends to move in the direction of issuing a single
consolidated permit. EPA is encouraging the States to consider similar action.
The promulgated regulations include instructions for completing the general,
RCRA, and NPDES portions of the application forms and include guidance on
NPDES sampling and analytical methodology.
Consolidated Hearings—
The promulgated consolidated permit regulations provide the opportunity for
joint EPA-State public hearings on any or all of the permits covered by the con-
solidated permit application. Special consideration may have to be afforded
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NPDES permits since the Clean Water Act requires evidentiary hearings rather
than the adjudicatory hearings specified for the other programs.
As a further mechanism of coordination, EPA and the Department of Interior
have discussed possibilities of at least sequential, if not joint, public hearings on
projects which need approval by both agencies. Further, the Colorado Joint
Review Process has identified opportunities for joint public hearings on similar
permits issued by the Federal and State agencies.
Completed Permit Application—
The requirements for type and detail of information to be included in permit ap-
plications is generally provided in the applicable statute and regulations. The pro-
posed consolidated permit application forms provide additional detail. These
forms are available for NPDES and RCRA permits at the present time and will be
available for UIC by April 1981. For PSD applications, EPA accepts data
presented on the applicable State new source permit application form in order to
avoid preparation of duplicative applications. These data must be complemented
by additional requirements unique to PSD (vs State new source review) as detailed
at 40 CFR 52.21.
Upon receipt of a permit application, EPA (or delegated State agency) will
review it for completeness and adequacy. If information gaps exist, the applicant
will be notified of the deficiencies. Upon receipt of adequate information to begin
review of the application on a substantive level, i.e. for BAT or BACT considera-
tions, the application will be deemed complete and so noted. This starts the clock
on the review timetable. EPA Region VIII has established the target of completing
all permit application processing within six months of receipt of a completed ap-
plication. The only statutory deadline which exists for any permit processing is a
one year requirement for PSD permits.
Permit Enforcement Procedures—
The objective of EPA enforcement is to achieve the highest degree of compliance
possible. This can be accomplished only to the extent that most of the regulated
parties comply with environmental requirements with a minimum amount of prod-
ding, surveillance, and formal enforcement actions.
Although the enforcement process differs slightly by media, the general flow of
an enforcement action is as follows.
Violation of permit
Issuance by EPA of notice of violation
Opportunity for enforcement conference
Issuance by EPA of an enforcement order
Gvil and/or criminal penalty sought by EPA
Issuance by Court of opinion
The above process may terminate at any point depending upon magnitude and
frequency of violation, violator's attempts to comply with requirement, out-of-
court settlement, and other factors.
Regulation Certainty—
Potential oil shale developers and industry in general have expressed concern
about the changing environmental regulations. This issue has been partially
discussed previously under the topic of permit lifetimes. Additional considerations
are discussed below.
The 1970's brought about new and revised environmental legislation. Each piece
of legislation dictated that implementing regulations be developed by EPA. Litiga-
tion on these regulations occurred on several major issues. The Court determina-
tions resulted in the requisite changes, additions, and/or deletions in EPA's regula-
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tions. Several pieces of legislation were instructive to EPA that the initial program
was to be developed and implemented by EPA. In parallel, EPA was to develop
guidance regulations in order to provide program delegation to the respective State.
Because of the number of Federal Acts and associated regulations, and legal
challenges to Federal and State regulation which occurred in the 1970's, it is little
wonder that environmental regulatory certainty was unavailable.
It appears that the 1980's will bring a stabilization of legislative and regulatory
activities in the environmental area. The basic framework now exists for essentially
all media. Changes in this framework will probably consist of fine tuning rather
than major overhauls. Changes in basic legislation and court determinations pur-
suant to legal challenges of implementing regulations are the two factors which af-
fect regulatory/permit condition certainty. These factors are beyond EPA and
State control.
Situations are limited in which a source that has received a permit will be re-
quired to provide retrofit technology. The situation is especially true for oil shale
developers, since there are essentially no commercial projects which have been per-
mitted and which are under construction. With the guidance on environmental
goals provided in this document, plus more detailed technology-based guidance to
be provided in a subsequent document in this oil shale series entitled Pollution
Control Guidance Document, prospective oil shale developers should not be con-
fronted with retrofit requirements. Information which demonstrates that health or
environmental problems are occurring as a result of the operation of an oil facility
may result in retrofit requirements.
Stream Classifications and Water Quality Standards—
The framework for the water quality requirements which must be met by oil
shale developers is presented in Section 1 of this document. Water quality criteria
(15) establish concentrations which have been found to be detrimental to human
health, to aquatic life, or to other water users. States adopt appropriate criteria as
water quality standards. States then designate all streams in the State according to
existing or desired use. States must review their water quality standards and stream
classifications at regular three-year intervals (16). These standards and stream
classifications must be submitted to and approved by EPA. The status of Utah and
Colorado standards and stream classifications is discussed in Section 1 and Appen-
dix D.
Salinity—
The salinity of the Colorado River and its tributaries is the subject of countless
studies, legislation, litigation, regulation, and policies. Details of the status of per-
tinent existing EPA and appropriate State salinity regulations are described in Ap-
pendix D. Agreements to reduce and control salinity levels in the Colorado River
Basin have been reached by the Colorado River Basin Salinity Forum and its
member States. Pertinent to oil shale developers, EPA Region VIII developed a
document entitled NPDES Permit Effluent Policy Incorporating Colorado River
Salinity Standards—dated November 22, 1976. This policy prescribed no discharge
of cooling tower blowdown and no discharge of process effluents to surface water
or groundwater when the average annual salinity of the discharge exceeds 879 mg/1
(7.33xlO"3 Ibs/gal). Opportunity was provided to the prospective discharger to
demonstrate that containment and/or treatment of the discharge of effluents
greater than 879 mg/1 (7.33xlQ-3 Ibs/gal) was not economically and/or technically
reasonable. Colorado, which now administers the NPDES, has superseded this
policy with a requirement that there shall be no discharge of salts wherever prac-
ticable. A discharger must show that containment and/or treatment of the
discharge of effluents greater than 879 mg/1 (7.33xlO'3 Ibs/gal) was not
economically and/or technically reasonable. A discharger must show that contain-
ment and/or treatment is not economically or technically achievable unless the
discharge contains less than .9 tonne (one ton) per day of salt.
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Region VIII EPA has and will continue to advocate improvement in salinity con-
centrations in the Basin. Portions of Region VIII's Energy and Water policies ad-
vocate maximum reuse and recycle in order to minimize the concentrating effect of
consumptive use of high quality water. Wherever practicable, lower quality water
should be treated for reuse in order to minimize consumptive use of high quality
water. Measures, perhaps dictated by BMPs, should be taken to prevent nonpoint
source discharges of saline water. Runoff from land disturbance and processing
areas, in addition to leachate and runoff from processed shale piles, should be con-
tained. Treatment to acceptable salinity levels may be necessary.
TSCA Applicability to Shale Oil—
Certain potential oil shale developers petitioned to have shale oil and its refined
products listed on the Toxic Substances Inventory. This inventory of existing
commercially-produced chemicals and compounds was published in June 1979.
The list included shale oils designated as number 68308-34-9. If a material has been
placed on this inventory, all manufacturers of this product are exempt from
premarket notification and testing requirements. However, this does not exempt
manufacturers, processors, or transporters of this product from any future con-
trol. If EPA finds that the manufacture, processing, distribution, use, or disposal
of this chemical presents an unreasonable risk of injury to health or the environ-
ment, it may take one of several regulatory actions. The chemical could be (1) pro-
hibited from being manufactured; (2) restricted as to type or amount of use; (3) re-
quire cautionary labeling, and/or (4) require certain record keeping and notifica-
tion procedures.
Program Delegations—
It is the stated intent of all environmental legislation to delegate the implementa-
tion of permit and regulatory programs to the States. A summary of the present
status of program delegation is provided in Section 1. Region VIII will operate the
program until the States develop the necessary legal, regulatory, and staffing
capability to administer the program. Upon delegation of the program, EPA's role
converts to an oversight/audit responsibility and a technical assistance capability.
The ability of EPA to effect an individual action such as issuance of a permit for
a particular project varies from program to program. The authority to veto in-
dividual permits issued by the State under the NPDES program if the permit is
found faulty on either procedural or substantive grounds lies with EPA. This
authority does not exist in the PSD program. The Agency may provide comments
on a proposed permit, but if a permit is issued against EPA's recommendation, the
only recourse is court relief.
INDUSTRY VIEW OF REGULATION
Editors' Note
The following discussion was prepared by the Rocky Mountain Oil and Gas
Association, at the invitation of EPA, for inclusion in this document. It is included
in the belief that readers of this document would be interested in the views of the
emerging oil shale industry regarding environmental regulation. The publication of
industry's views in this EPA document should not in any way be considered as
EPA acceptance or endorsement of these views.
Industry Position
This chapter of the Environmental Perspective document has been prepared by
members of the Environmental Subcommittee of the Rocky Mountain Oil and Gas
Association Shale Committee at the invitation of EPA. The positions stated in this
chapter represent broadly held views in the oil shale industry. In certain cases, in-
dividual company opinions may vary in some respects with the positions taken.
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The oil shale industry commends and supports EPA's effort to compile this
document which summarizes the current state of environmental knowledge about
oil shale development. This document will provide in a single volume, a convenient
and useful source of information on the environmental regulations, research
priorities and policies related to oil shale.
As shown by this volume, much is already known about the environmental
nature of oil shale and the impacts which will result from development of this
resource. As a potential resource of interest to developers and the government for
many decades, oil shale has been the subject of extensive and intensive environ-
mental study. The results of these studies are publicly available in published reports
of the industry and of government, and in the open files of the Department of In-
terior Prototype Oil Shale Leasing Program. As a result, the level of knowledge
concerning the impacts from development of this resource is far greater than has
ever been gathered for any other developing industry prior to construction of any
commercial operations.
The development of oil shale on a commercial basis will result in some significant
impacts within the oil shale region. The detailed evaluations of environmental con-
cerns which have been conducted make industry confident that such impacts can
and will be controlled within the limits of current regulatory standards. Further,
the environmental concerns regarding oil shale are the same in nature or risk as
those occurring in presently operating energy industries. As an industry which can
and will operate within strict standards protecting public health, safety and
welfare, the industry has confidence that adverse environmental impacts will be
well within publicly acceptable levels.
Although much is known about the environmental impacts of oil shale, there
are, on the other hand, environmental questions related to commercial sized opera-
tions which can only be answered finally by commercial field demonstration and
experience. The information and experience gained from the initial operation of oil
shale plants will provide data and information from which performance standards
can be set and reasonable and appropriate rules developed. Industry expects to
continue working in cooperation with EPA and other governmental units to assure
that development of an oil shale industry progresses in an environmentally accept-
able manner.
In developing an oil shale regulatory system, the industry believes certain general
principles should apply which will provide effective and fair rules. Those principles
include the following:
Regulation must provide a balance between environmental and economic costs.
The oil shale industry should be treated on an equal footing with other com-
parable industries.
In establishing rules, maximum flexibility should be provided to deal with a
variety of processes and projects which will operate under significantly different
circumstances.
Flexibility should be encouraged to allow for innovative technology, particularly
during the construction of first generation plants.
Permit and approval terms and conditions must be frozen during construction,
startup and initial operating phases to provide the necessary stability for private
investment decisions.
Regulatory decision making should be expeditious and within agreed upon time
schedules.
EPA should clearly differentiate between industry's obligation to demonstrate
operating compliance with established standards and government's obligation to
carry out general research and information gathering programs.
These principles should apply to all areas of environmental control and regula-
tion. The remainder of this chapter addresses specific areas of environmental in-
terest.
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Health Effects/Toxicology—
Oil shale products, by-products, and starting materials have been subjected to
extensive chemical and biological testing. The data from all programs conducted so
far, as well as from epidemiological studies of workers, indicate that occupational
risks and environmental health situations are no different from those in presently
existing fossil energy industries. No unique or unusual oil shale risks have been
demonstrated.
The cancer incidence associated with the Scottish oil shale experience is not cur-
rently significant for two important reasons. First, industrial hygiene practice was
nonexistent; and second, primitive refining methods in use at the time concentrated
the polycyclic aromatic hydrocarbon (PAH) in the fractions of shale oil used.
Under these conditions, the materials used were indeed carcinogenic to man. In
view of modern petroleum industry practices, which deal with virtually identical
compounds, the Scottish experience is only relevant from a historical standpoint.
This conclusion is reinforced in examining the Estonian oil shale industry, in which
the effectiveness of realistic industrial hygiene practices has been demonstrated by
a low cancer incidence.
Recent experiments which purport to compare the carcinogenicity of crude shale
oil with crude petroleum have been misdirected. The two materials are not com-
parable in the processing stream. To properly compare the carcinogenicity of crude
shale oil with that of a petroleum product or intermediate, the same stages in proc-
essing must be used. As shown in Figure 6-1, the first refining step in the processing
of crude petroleum and oil shale is to thermally treat the raw material. In both
cases, the temperature of treatment approaches 482° to 538°C (900° to 1000°F)
and during both these thermal processes PAH are formed. The next processing step
is to hydrotreat the materials created in the thermal processes. For shale oil, this
hydrogenation step has been proven to have two beneficial effects. It decreases the
PAH content and reduces carcinogenicity as determined by biological testing. The
preceding documented facts form the basis for industry's position on health effects
of oil shale processing. That is, a commercial oil shale retorting facility using
modern industrial hygiene practices and complying with the present Occupational
Safety and Health (OSHA) and Mine Safety and Health Administration (MSHA)
regulations will not expose workers or the environment to carcinogenic or toxic
risks that are not presently acceptable in other modern energy-related industries.
Control technology—
The control processes described in this document may be used for guidance pur-
poses when making an assessment of the best available control technology for
various applications. The descriptions provide a convenient reference to technolo-
gies that are currently available and might be applicable to the oil shale industry.
The selection of control equipment for oil shale development must be addressed
on a case-by-case basis. Each site and process will have different sets of economics
impacting the type of control equipment selected. The BACT selection process re-
quires consideration of practical engineering design coupled with an economic
analysis. Allowances must be made for the development of innovative control
technologies since the oil shale industry is developing innovative processing tech-
niques at this time.
Spent Shale Disposal/Leachate—
The discussion of leachate gives the impression that natural leaching in signifi-
cant quantities is inevitable at oil shale disposal piles. The following factors suggest
very strongly that leaching will probably not occur:
1. The oil shale region is a semiarid region. There is not an abundance of natural
water. The annual evaporation is typically greater than the annual precipita-
tion.
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Crude
Petroleum
Catalytic
or Thermal
Cracking
i (tec - 950°F) i
' (Fluid Coker-1000°F) '
Hydrogenation
Products
Oil Shale
Rock
Retorting
900°F
i i
i i
PNAs are
1 formed in these '
' 3 thermal processes '
i i
Hydrogenation
PNA content
is reduced in
these refining
processes
Products
Figure 6-1. Polycyclic aromatic hydrocarbon formation — a comparison of petroleum and shale oil.
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2. The retorted shale disposal area will be revegetated. Much experimental and
field demonstration work has shown the viability of revegetating retorted
shale disposal areas. The amount of vegetation presently occurring in the
region is determined by the availability of water. This will also be the case of
revegetated disposal areas. In other words, the plants will use all available
water.
3. Retorted shale has a large capacity to store water. Thus, on those infrequent
years when the precipitation exceeds the plant needs, there is storage capacity
for the excess water.
4. The disposal piles will be constructed to provide layers of shale with very low
permeability which will retard any water flow through the piles.
The Spent Shale Disposal section discusses some potentially serious problems
that could result from careless disposal of retorted shale. However, industry's cur-
rent plans for disposal of retorted shale show a careful and considered approach to
those potentialities. Properly planned and managed revegetation efforts should go
far in preventing harmful leaching.
Monitoring Methods—
Monitoring requirements as specified in the regulations should clearly state what
is required of industry. Frequently, that statement is not made and the differentia-
tion between the responsibilities of government and industry become blurred. It is
therefore useful to generally define three types of environmental analyses in order
to bring monitoring requirements into sharper focus. These environmental analyses
are screening, monitoring, and research as follows:
1. Screening - Programs which are designed, conducted, and reevaluated by the
developer to detect trends in unregulated baseline or indicator parameters.
Screening programs are performed before and after operations to assess
preexisting environmental conditions and the potential impacts of develop-
ment upon the environment. Subject to constant change, screening could lead
to either more or less intensive analysis than originally defined.
2. Monitoring - Programs which are defined and reevaluated by the EPA pur-
suant to law and regulation. The objective of monitoring programs is to
characterize the impacts of operations on the environment in terms of
regulated pollutants which are measured by known and proven methods. The
operator is responsible for conducting, monitoring and reporting the results
to demonstrate compliance with permit conditions. Monitoring programs
should be subject to periodic reevaluations.
3. Research Programs which may be defined by either the EPA or the
operator, but which are not regulatory requirements for monitoring. Suspect
pollutants and unproven methods for sampling or analysis may be within the
scope of research, but are not permit conditions. The funding of research
programs should be considered on a case-by-case basis. Research, such as the
determination of regional impacts of development, should be funded at least
in part by the EPA.
Screening, monitoring and research programs should be site specific and process
specific, to allow for the diversity in approach to development and to encourage in-
novation.
In addition, monitoring requirements should also be based on the following
quidelines:
Monitoring requirements should be cost-effective, have clearly defined objec-
tives, and specify what action may be taken as a result of monitoring findings.
Technically appropriate and accurate test methods for each prescribed parameter
need to be defined by regulation.
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Representative sampling should be defined, indicator variables should be
selected and the frequency of sampling should be specified. Where warranted,
the frequency of sampling should be reduced.
Air Impacts—
The size of the oil shale industry will most probably be determined by the PSD
regulations. The number and size of plants located in any given area will be deter-
mined by consumption of the local Class II increment. The total size of the industry
will be determined by consumption of the Class I increment in wilderness areas.
It is known that PSD increments will ultimately limit the size, siting, and the
number of oil shale plants. However, because of limited available techniques for
modeling and monitoring of air impacts, it is not known when this limit will be
reached. The industry endorses continuing research to improve and validate such
predictive methods, since the presently available methods are overly conservative.
However, it must be recognized that refinement of these methods will only allow a
more accurate prediction of when this limit of shale oil production will be met
under the current regulations. This limit will still exist and should be acknowl-
edged.
Research Needs—
The EPA oil shale research program should proceed from a written set of objec-
tives. These objectives should be based on EPA's statutory obligations and be
available for public review. Specific research needs should then be identified to
meet these objectives. The priority of these identified needs should be set so that
the greatest benefit can accrue from EPA's limited research budget. The priorities
should be set considering the following factors:
The statutory authority given to EPA to regulate the research subject.
The need for EPA to know the research results before developing or modifying
regulations concerning the research subject.
The availability of suitable facilities with which to perform the research.
The magnitude of the problem to be researched in comparison with the research
cost.
The timing of the need for the research results.
In order to maximize the benefit obtained from all research, EPA's program
should be coordinated with other Federal, State and industry programs. From an
industry viewpoint, in view of the constraints imposed by the PSD increments, the
single most important research need is development of a basinwide air quality
model.
Standards—
The industry recognizes that EPA is developing specific performance standards
for oil shale technologies. In so doing, EPA must recognize the following factors.
1. There are currently at least six generically different retorting processes under
development. As more advanced technologies are developed there will un-
doubtedly be more. Since processes differ, a control technology and
associated performance standard that might be appropriate for one may be
totally inappropriate for another. This fundamental fact must be recognized
when performance standards are set.
2. The control technologies being proposed for use on oil shale processes are
technologies that have been developed in other industries. There is a high pro-
bability that these technologies will also work when applied to oil shale proc-
esses. However, the removal efficiencies that can reasonably be expected of
these technologies when applied to oil shale have not been demonstrated. Un-
til these demonstrations are made, it would be inappropriate to set removal
efficiencies as performance standards.
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3. Performance standards that have been developed in other industries have
been based on well run plants operating under commercial conditions. No
such experience exists in the shale industry.
When these factors are considered, it is apparent that the conditions used to set
performance standards in other industries do not now exist in the oil shale industry.
Until those conditions do exist and commercial operating data have been gathered,
it will not be possible to set realistic performance standards for this emerging in-
dustry.
REFERENCES
1. PSD Permit issued to Colony on July 11, 1979 via Merson to Legatski letter.
2. PSD Permit issued to Union Oil Co. on July 31, 1979 via Duprey to Randle letter.
3. PSD Permit issued to Rio Blanco Oil Shale Project on December 15, 1977 via Merson to
Miller letter.
4. NPDES permit number CO-0034045 issued on October 2, 1977 to Rio Blanco Oil Shale,
Inc.
5. NPDES permit number CO-0035637 (pending) for Rio Blanco Oil Shale, Inc.
6. NPDES permit number CO-003961 issued to Occidental Oil Shale, Inc. (Tract C-b) on
March 28, 1979.
7. NPDES permit number CO-0029947 issued to Occidental Oil Shale, Inc. (Logan Wash)
on March 19, 1979.
8. Clean Air Act Amendments of 1977 (PL 95-11), Part C.
9. 40 CFR 52.21.
10. The Development of a Regional Air Pollution Model and Its Application to the Nor-
thern Great Plains, EPA-908/1-77-001, June 1977.
11. OAQPS Guideline Series, Guideline on Air Quality Models, EPA-450/2-78-027, April
1978.
12. OAQPS Guideline Series, Workbook for Comparison of Air Quality Models and Ap-
pendices, EPA-450/2-78-028 a and b, May 1978.
13. Federal Register 44:52581-52588, September 7, 1979.
14. 40 CFR 58.
15. Water Quality Criteria 1972, National Academy of Sciences Report for EPA, March
1973.
16. Clean Water Act of 1977, Section 303.
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SECTION 7
OIL SHALE TECHNOLOGY,
EMISSIONS, AND SOLID WASTES
The Pace Company Consultants and Engineers, Inc.
A Division of Jacobs Engineering Group
This section provides a summary of oil shale technology for surface, modified in
situ, and true in situ retorting methods. The major steps in producing oil from
shale (feed preparation, retorting, recovery of products, and disposal of wastes) are
briefly described.
Each of the major oil shale retorting processes is briefly described, with retort
cross sections and process flow diagrams provided to illustrate the process.
OVERVIEW OF SHALE TECHNOLOGY
Mining
Except for true in situ oil shale processing, some degree of mining is required
before retorting. In the case of modified in situ processes, this mining is limited to
the development of access drifts and the formation of underground cavities into
which the surrounding oil shale formation is explosively expanded. Surface retort-
ing processes require that all of the raw shale to be processed be removed from the
formation, crushed to the proper size, and transported to the retorting facility
before retorting. In the latter case, the large scale mining operation that would pro-
vide raw ojl shale to the retorting facility could be either an underground or surface
process, depending on the geology and hydrology of the site and other economic
factors.
Surface, or open pit mining, of Green River oil shale has never been attempted
on a commercial scale; however, it appears to be applicable in some areas of Col-
orado, Utah, and Wyoming. Open pit mining involves excavating the overlying
waste rock to expose the oil shale resource below. The oil shale and waste rock are
"benched" down to a depth dictated by the economic limits or cutoff grade of the
pit. The slope of the pit walls is determined by the stability of the rock being mined.
Open pit mining has the advantage of recovering almost the entire resource (except
the oil shale under the pit boundaries) as opposed to underground methods which
have resource losses in the sills and support pillars.
In the Piceance Creek Basin of Colorado, nearly 80 percent of the oil shale
resource is confined to the deposits in the deep central part of the basin. For this
reason, underground mining systems with high volume and low cost will have to be
used to mine the thick oil shale resource efficiently, unless the entire basin is mined
as one grand-scale open pit.
Commercial-sized underground room-and-pillar mining systems have been used
by the U.S. Bureau of Mines on the Naval Oil Shale Reserves by Union Oil at its
Long Ridge site and by Colony Development Operation at the site of the semi-
works retorting facility and at the Mobil Mine located adjacent to Anvil Points.
Using this process, the oil shale is recovered by excavating the ore from equal-sized
square openings approximately 18.3 by 18.3 m (60 by 60 ft), leaving columns or
pillars that support the roof of the excavated rooms. Variations of the basic room-
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and-pillar method can also be used effectively in oil shale. These include: advance
entry and pillar mining, and chamber and pillar mining. Figure 7-1 is a conceptual
multi-level room-and-pillar system that could be designed to mine the rich oil shale
layers and leave the lean layers. This system leaves much shale in place as support
pillars and is not appropriate for thicker shale deposits.
Figure 7-1. Multiple level room and pillar mining concept.
(Source: Reference 1.)
Bulk underground mining could also prove to be a very efficient means of ex-
tracting oil shale at high volume with a minimum cost. Sublevel sloping is an exam-
ple of a bulk underground mining method. Sublevel sloping involves blasting the
oil shale into a stope (a high vertical column of ore) by means of fan rounds drilled
from the sublevel and stope floor. Front-end loaders are then used to transport the
broken muck from the stope to rail cars pulled by trolley locomotives. The muck is
dumped from the rail cars into gyratory crushers at the shaft station and is hoisted
to the surface.
Block caving using slushers is another method of bulk underground mining. The
caving system is retreat in nature and starts within an economic distance from the
main access area. A mining level is divided into panels, with each panel subdivided
into blocks. Caved oil shale from an undercut level flows by gravity down finger
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raises, is slushed along a slusher drift, and dropped directly into rail cars on the
main haulage level. Instead of slushers, load-haul-dump units may be used to
transport the ore from the finger raises to transfer raises, which in turn are used to
load the ore trains.
Whatever method of mining is used, either surface or underground, the system
must be capable of excavating large quantities of oil shale at a very low cost. The
mine design must not only be cost effective, but must also comply with existing
health and safety regulations and have minimal effects on the physical, biological,
human, and mining environments.
Crushing, Storage, and Transportation
Regardless of the particular surface process chosen for use in a project, raw oil
shale must first be crushed to the appropriate size and transported to the retorting
facility. Green River oil shale can be crushed by conventional crushing equipment,
but the properties of the shale are such that selection of equipment should be made
only after demonstration or previous experimental work has given assurance that
crusher performance will be satisfactory. Oil shale tends to form slab-shaped
fragments when crushed in jaw, gyratory, or toothed-roll crushers. This tendency is
less pronounced when impact-type crushers are used. Fragments of rich oil shale
are resilient, tough, and slippery, the latter characteristic making it difficult for
smooth-roll crushers to nip or catch hold of individual fragments.
Crushing operations planned for large-scale demonstration or commercial
facilities will generally consist of primary crushing at the mine site followed by
secondary crushing near the retorting site. The small particle size required by some
retorting processes will also necessitate tertiary operations in some instances.
Primary crushers would reduce the mined ore to a manageable particle size,
roughly 30.48 cm (12 in.). Dust generated by this operation would either be sup-
pressed or collected in baghouses for later treatment.
Coarse ore would be transported to the retorting site either in trucks, by rail, or
on covered conveyors. All commercial plans have proposed the use of covered con-
veyors. Dust generated by this operation would be collected at strategic locations
and would either be retorted or discarded. The coarse ore would be stockpiled to
provide for surge conditions and to allow the retorting facility to continue
operating in the event of a temporary shutdown of mining operations. The pro-
posed stockpiling procedure for small-scale operations would be containment in a
silo or hopper, with discharge to the retorting plant from the bottom. Larger
operations have proposed the use of open stockpiles, with the ore being removed to
the retorting operation by bucket reclaimer units or underlying conveyor systems.
Dust suppression techniques employing polymer or latex solutions have been pro-
posed for use on these stockpiles.
Secondary (and tertiary) crusher units would prepare the ore for use in the retort-
ing facility. Fine ore storage facilities would also be provided, but because of the
relatively small size of the fragments, these would be enclosed to minimize dusting
and eliminate exposure to detrimental environmental conditions.
Surface Retorting
All surface retorts are similar in that the retorting process actually occurs in a
metal vessel in an above-ground facility. Such a configuration has the advantage
that process flows and operating parameters can be easily controlled and manipu-
lated; however, the surface processes also suffer the disadvantage that large quan-
tities of raw oil shale must be mined, transported to the retort area, processed, and
disposed of in an environmentally acceptable manner.
Literally hundreds of U.S. patents have been issued concerning surface retorting
of oil shale. Despite the number and types of retorting processes described in the
literature, no one process has yet been shown to be the best for all purposes. It is
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probable that a combination of processes would best serve a commercial shale
retorting industry.
Surface retorting processes can generally be divided into three classes: Direct-
heated, indirect-heated, and combination. Direct-heated processes rely on internal
combustion of fuel (generally recycle gas and/or residual carbon in the spent shale)
with air or oxygen within the bed of shale in the retort to provide all the necessary
process heat requirements. Nitrogen and products of combustion (if air is used for
combustion) accompany the off-gas stream from the retort.
Indirect-heated retorting processes utilize a separate furnace for heating solid or
gaseous heat-carrying media that are injected, while hot, into the shale in the retort
to provide the process heat requirements. Hydrogen retorting processes are of the
indirect-heated type, varying from the more conventional techniques in that the
retorting is conducted in a hydrogen-rich atmosphere.
Combination processes do not actually operate in the direct- and indirect-heated
modes at the same time. Rather, they are processes that may be either directly or in-
directly heated, depending on the specific equipment configuration used.
In Situ Retorting
In situ processes are those in which the actual retorting, or conversion of organic
matter in the oil shale to shale oil, occurs underground with a minimum of disloca-
tion of the oil shale from its original position in the formation. In situ processes re-
quire at most only a limited amount of mining and solids handling, but they have
the disadvantage that remote sensing must be used to monitor almost all process
operating conditions, thus complicating the control problem. Though an in situ
recovery process produces little waste material to dispose of aboveground, the
retorted zone of spent shale left after retorting could present serious environmental
problems of its own if not dealt with properly.
Discussions of in situ retorting often distinguish between "true" in situ proc-
esses, which involve only the drilling of wells, and "modified" in situ processes,
which require some mining to develop the underground retort chambers. With the
exception of Occidental Petroleum's work on a modified in situ process, the
development of in situ processes has not advanced to as large a scale of production
as surface retorting methods. There is, however, much interest in and a large poten-
tial application for both true and modified in situ methods.
In situ retorting involves the in-place heating of an underground shale formation
under conditions wherein the flows of heat, vapors, and liquids can be controlled,
resulting in the recovery of acceptable quantities of gaseous and liquid products
from the resource. Typical Green River Formation oil shale occurs as competent,
hard, nonporous rock formations with relatively little permeability. They are
generally unsuitable for in situ retorting. It is therefore necessary to create
permeability.
Joint patterns and fractures do occur in the formations, but the natural fractures
are widely spaced and do not provide the massive fracturing and surface area
necessary for successful in situ processing. In certain zones, water-soluble minerals
(e.g. nahcolite, halite, etc.) occur. These occurrences are as bedded zones, nodules
and spherical crystals, and disseminated crystals. These soluble minerals may be
leached from the oil shale by natural groundwater or from a borehole resulting in
some permeability of the remaining rock. Permeability for true in situ (borehole) is
generally induced by explosive or hydraulic fracturing and propping techniques.
Modified in situ methods create the greatest degree of permeability by mining out a
portion of the formation and then explosively expanding the adjacent rock into the
void. The key technical problem in modified in situ recovery is to develop the
proper mining and blasting techniques that would optimize rock fragmentation in
underground retorts, and thus permit the controlled flow of heat, gases, and li-
quids through retorts.
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Once adequate permeability has been established (for either true or modified in
situ), the oil shale can be heated to the necessary temperature by either direct or in-
direct heating techniques. All of the major projects currently underway involve the
direct heating of the shale and utilization of the combustion of recycle gas and/or
residual carbon on the spent shale to provide the necessary heat.
Spent Shale Disposal
Once oil shale is mined, crushed, and retorted, the spent shale must be used or
disposed of in an environmentally acceptable manner. The composition and size
range of the spent shale particles largely depends on the type of retorting process
used, and these properties in turn determine the possible uses and the method and
ease of disposal.
Even though the spent shale usually occupies a greater volume than the raw in-
place shale, it would be desirable to place as much of the spent material as possible
back in the mine. Unfortunately, the logistics of mining and the material handling
costs may make such an option uneconomical. It is expected that with the proper
moisture content, all or part of the spent shale can be returned to the mine and be
packed completely to the roof. It will then set up similar to shotcrete. In this man-
ner, mine subsidence would be prevented, and unsightly waste piles would be
eliminated.
Disposal of spent shale in an open pit mine appears attractive. Once the open pit
is large enough to accomodate both continued operation and spent shale backfill-
ing, all of the spent shale can be returned to the pit. The pit can then be advanced
with ongoing backfilling and reclamation.
Aboveground disposal of spent shale from underground mining/surface retort-
ing operations is a potential alternative to returning spent shale to an underground
mine, and one that has been proposed by several developers. This technique simply
involves compacting and contouring the spent shale in the vicinity of the processing
facility in canyons or valleys or on relatively flat terrain. A valley site allows for
disposal of a large volume of material and the surfaces requiring stabilization and
revegetation are relatively small. Furthermore, the bulk of the material is hidden
from view. If the disposal site is in a natural drainage path, efforts must be made to
reroute natural water flows and minimize or eliminate the natural leaching of water
soluble material. Reclamation and revegetation, with appropriate planning, can be
conducted along with the placement of spent shale, which will result in relatively
small areas of unreclaimed spent shale at any point in time during active disposal.
During modified in situ operations, oil shale mined and removed to the surface
may be processed in aboveground retorts, thus creating spent shale requiring
disposal. For this situation, it has been proposed that some or all of the spent shale
from the surface retorts could be slurried and injected into underground retorts in
which retorting has been complete.
During recent years, much research has been conducted on dealing with the
revegetation of spent shale. This research has indicated that the high salinity of the
spent shale is one of the most important hinderances to revegetation. Other studies
have shown that spent shale is deficient in both nitrogen and phosphorus, and
therefore some degree of fertilization would be necessary for successful revegeta-
tion. It was also found that the surface temperatures that the black spent shale may
attain — 60° to 66 °C (140° to 150°F) — may adversely affect the revegetation
process. Therefore, mulching may be required to revegetate successfully.
Retort Gas Treatment
The crude retort gas from an oil shale retorting unit consists of a mixture of shale
oil vapors, paniculate matter, light hydrocarbon gases, and a wide range of non-
condensable gases such as hydrogen, carbon dioxide, and hydrogen sulfide. The
first step in treating this stream is oil recovery. Two techniques are commonly pro-
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posed to perform this operation — electrostatic precipitation and partial condensa-
tion (fractionation), although impact precipitators are also suitable for this pur-
pose. The first approach is usually applied when the retort gas stream is largely
composed of gases and the concentration of condensable oil droplets is rather
dilute, such as from vertical kiln type retorts or in situ processes. The fractionation
approach is most commonly proposed for use when treating streams with a fairly
high concentration of oil droplets, such as those from a TOSCO II or Lurgi-
Ruhrgas process.
The electrostatic precipitator oil recovery operation also removes significant
quantities of water and particulate matter. The oil/water/solids stream is further
treated by conventional separation processes to yield three separate streams. The
water is sent to a foul water stripper for cleanup. The solids are either discarded or
reinjected into the retorting unit, and the oil is further upgraded, if desired.
The fractionation operation yields several different product streams, from
naphtha to residual oil and particulate matter. The bottoms product can be cen-
trifuged to yield an oil residue and a sludge stream.
The gaseous overhead stream from the electrostatic precipitator or partial con-
denser oil recovery units is normally separated into product gas, low pressure gas
(LPG), and butane. Depending on the retorting process used, the product gas may
either be of a high or low heating value. In the latter case, it would most likely be
used as a plant fuel and as a hydrogen plant feedstock. In either case, the stream
may be further treated in a conventional amine scrubbing unit (or similar device) to
remove hydrogen sulfide and carbon dioxide. The hydrogen sulfide-rich stream
from this unit would then be treated in a Claus unit to recover elemental sulfur. An
alternative approach would be to treat the entire gas stream in a Stretford unit to
recover elemental sulfur directly. The LPG stream from the fractionator could be
sold as product and the butane stream could serve as additional plant fuel.
Shale Oil Upgrading
Shale oil is the term applied to the liquid oil product recovered from the thermal
decomposition (pyrolysis) of kerogen, the organic material present in the oil shale.
Crude shale oil, sometimes called retort oil, is the liquid oil product recovered
directly from the retort. Synthetic crude oil is the upgraded oil product resulting
from the hydrogenation of crude shale oil.
The properties of crude shale oil from a retort are dependent on a variety of fac-
tors. One of the most important of these is retorting temperature, or more
specifically, temperature history. Retorting pressure and atmosphere also have
significant effects on the product oil properties, as do particle size and shale grade.
Table 7-1 is a summary of the properties of crude shale oil produced by various
pilot plants and bench-scale operations. It should be noted that though these pro-
perties are indicative of what would be produced by a commercial facility, the oil
samples investigated were not produced by an optimized process. Rather, they were
generated during test runs on relatively small scales under operating conditions that
may vary from those at a commercial installation.
Because of the high pour point, viscosity, and nitrogen and oxygen contents of
crude shale oil, it is not a premium grade feedstock for a conventional refinery. To
convert the raw shale oil into a more desirable feedstock, it must be upgraded, or
partially refined, using proved refining techniques. Thus, there are three different
levels of shale oil refining, any or all of which may be used for a particular situa-
tion:
Conversion to a pipelinable product to facilitate transport to a distant refining
installation.
Upgrading to produce a low-sulfur, low-nitrogen, premium grade refinery
feedstock.
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Complete refining of crude shale oil or some intermediate into usable end prod-
ucts.
To produce a pipelinable product, several schemes are possible:
Coking — crude shale oil is heated to crack the hydrocarbons, producing a coke-
like material plus a light oil that has a low pour point. This method is rather
unattractive because of the severe losses resulting from production of low-value
coke, with relatively small yields of product oil.
Addition of pour-point depressants — these are proprietary compounds that are
said to reduce the pour point of crude shale oil.
Hydrogenation — hydrogenation may be used to remove sulfur and nitrogen
compounds. The product oil may then be burned directly as fuel oil or further
refined into other end products.
The complete refining of crude shale oil into usable end products has been suc-
cessfully demonstrated by several investigators. Some of the most extensive
research was conducted by Sohio and Gary Western Refining using crude shale oil
TABLE 7-1. PROPERTIES OF CRUDE SHALE OILS8
Property
Carbon, wt. %
Hydrogen, wt. %
Oxygen, wt. %
Nitrogen, wt. %
Sulfur, wt. %
Gravity,' °API
Specific Gravity
Arsenic, ppm
Nickel, ppm
Iron, ppm
Vanadium, ppm
C/H Ratio
Pour Point, °F
Heating Value,
BTU/lb
Distillation
5 vol. % at °F
10
30
40
50
60
70
80
90
95
Fischer
Assay
Samples
84.59
11.53
—
1.96
0.61
—
0.92
—
-
—
-
7.3
80
18,508
—
336
518
_
655
685
705
_
_
-
NTU
84.61
11.40
1.10
2.10
0.79
20.3
—
—
-
—
—
7.42
90
—
—
—
—
_
—
—
_
_
_
-
Gas
Com-
bustion
83.92
11.36
1.67
2.14
0.7
19.8
—
—
6.4
108
6
—
83.5
—
378
438
607
678
743
805
865
935
1030
1099
TOSCO
85.1
11.6
0.8
1.9
0.9
21.2
"0.928
—
6
100
3
7.34
80
—
200
275
500
620
700
775
850
920
—
—
Union
A
84.2
11.4
2.2
2.0
1.0
18.6
0.943
—
—
—
—
—
—
18,600
390
465
640
710
775
830
980
—
—
—
Union
B
84.8
11.7
0.9
1.7
0.8
22.7
0.918
—
-
—
-
—
—
18,530
234
330
551
—
711
-
—
848
984
1045
Paraho
84.90
11.50
1.40
2.19
0.61
19.3
0.938
19.6
2.5
—
0.37
7.38
85
—
—
520
680
750
810
840
—
—
—
—
Hydro-
tort
85.44
11.12
—
1.88
0.56
21.5
—
—
-
71.2
—
—
65
—
—
278
430
—
568
634
682
712
—
—
8 Source: Reference 1.
283
-------
from the Paraho retorting operation at Anvil Points, Colorado. A total of 1,360
tonnes (100,000 bbl) of crude shale oil was refined into a full range of military
fuels, including heavy fuel oil, diesel fuel, JP-4, JP-5/Jet-A, and gasoline. While
none of the fuels produced during the refinery runs met all specifications, the tests
did demonstrate that it is feasible to produce a wide range of civilian and military
fuels from crude shale oil if appropriate modifications are made and specific opera-
tional procedures are followed at a commercial refinery.
SURFACE RETORTING PROCESSES
Gas Combustion Retorting Process
The Gas Combustion retorting process involves the gravity flow of oil shale
through a refractory-lined vertical kiln, with the shale feed rate being controlled by
a grate mechanism located at the bottom of the retort. As the shale progresses
through the retort, it passes through four functional zones, though there are no
physical separations in the retort and no distinct division between the zones. A
simplified flow diagram of the process showing these zones is provided in Figure
7-2.
The top zone, into which the 0.64 cm (1/4-in.) to 7.62 cm (3-in.) shale fragments
enter through a continuous antisegregation feeder, is called the shale preheating or
product cooling zone. In this stage, heat is transferred from the rising stream of hot
product gas to incoming raw shale. Thus, this zone serves two purposes—first, to
cool the product gases below the dew point of the contained product oil, which
then condenses as a fine mist and is carried out of the top of the retort, and second,
to preheat incoming shale to minimize the heat load on the process in subsequent
heating zones.
Having passed through the first zone, the preheated shale enters the retorting
zone, where it is heated to retorting temperature by hot gases rising from the com-
bustion zone. As kerogen contained in the oil shale pyrolyzes, it yields oil (in vapor
form), gas, and a residual carbonaceous product that adheres to retorted shale
solids. The vapors are swept upward by the rising flow of hot gases.
Leaving the retorting zone, shale fragments pass into the hottest part of the
retort, the combustion zone. In this zone, a mixture of recycle gas and air is in-
troduced. Oxygen available from the injected air supports combustion of the car-
bonaceous residue present on shale fragments coming from the retorting zone. The
oxygen present also supports combustion of hydrocarbon constituents in the in-
jected recycle gas. As shown in Figure 7-2, the temperature in the retort at the com-
bustion zone may reach 760° to 816°C (1400° to 1500°F). Hot flue gases produced
in the combustion zone rise upward into the retorting zone to provide the heat
necessary for pyrolysis.
The retorted and partially burned spent shale fragments then pass into the cool-
ing or heat recovery zone. This area of the retort essentially serves as a countercur-
rent heat exchanger wherein heat from hot spent shale is transferred to cool incom-
ing recycle gas. Like the topmost zone, this serves a dual purpose—first, to preheat
the recycle gas and thereby reduce the heat load in the combustion zone, and sec-
ond, to cool the spent shale to minimize handling problems and increase thermal
efficiency.
The Gas Combustion process, being directly heated, requires the injection of
oxygen (usually in air) into the retort to burn off residual carbon on the spent shale
and thus provide the necessary heat for retorting. The injection of nitrogen in the
combustion air dilutes the product gas and, after the liquid hydrocarbons are con-
densed from the stream, the remaining gas has a low heating value. Since the Gas
Combustion process uses relatively coarse shale feed, and very little if any attrition
occurs within the retort, the spent shale will have a particle size distribution very
similar to that of the feed shale. This minimizes dusting problems encountered dur-
284
-------
OIL SHALE
MINE
— •*•
SHALE
CRUSHING
AND
SCREEN
SIZING
,1
-•j" FINES DISCARD
GAS
SEAL
PRODUCT
GAS
t
SHALE OIL
RECYCLE
GAS
SLOWER
AIR
AIR BLOWER
DILUTION SAS
SHALE
PREHEATING
ZONE
SHALE
.RETORTING. ZONE
COMBUSTIi
ZONE
SPENT SHALE
COOUNG ZONE
COOL RECYCLE GAS
TYPICAL TEMPERATURE PROFILE
5OO 1000 1500
TEMPERATURE OF SHALE "F
SEAL
SPENT SHALE
SOUOS
Figure 7-2. Gas Combustion retorting process.
(Source: Reference 1.)
-------
ing the transportation and disposal of spent shale. Because some of the residual
carbon on the spent shale is combusted in the retort, the spent shale product con-
tains less residual carbon than that from indirect-heated processes and is lighter in
color.
During six evaluation runs conducted on the 136-tonne (150-ton) Gas Combus-
tion retort by the U.S. Bureau of Mines, the offgas following oil recovery had the
average composition shown in Table 7-2.
TABLE 7-2. AVERAGE COMPOSITION OF
OFFGAS FROM GAS
COMBUSTION RETORT8
Orsat analysis component:
C02
Unsatu rated hydrocarbons
02
CO
H2
Saturated hydrocarbons
N2
Vol. %
24.2
1.7
0.3
2.6
4.7
4.0
62.6
3 Source: Reference 1.
TOSCO II Retorting Process
The TOSCO II retorting process configuration is shown in Figure 7-3. Raw oil
shale, crushed to minus 1.3 cm ('/i in.) is mixed with hot ceramic balls in a pyrolysis
drum. In the semi-works plant, this drum is 2.44 m (8 ft) in diameter and approx-
imately 4.57 m (15 ft) long. The 1.3 cm (Vz in.) diameter balls enter the drum at ap-
proximately 650 °C (1200 °F), having been heated in a separate vessel. The heated
balls are charged into the drum to mix with the incoming preheated shale at 260 °C
(500 °F) in the proportion of about 2 tons of balls for every ton of shale. As the
pyrolysis drum rotates, the balls come into contact with oil shale and heat it to ap-
proximately 482 °C (900 °F).
The shale oil vapors evolved during pyrolysis, the spent shale, and the ceramic
balls exit together and are separated in an accumulator vessel. The shale oil vapor is
quenched and then fractionated using conventional hydrocarbon fractionation
equipment. The ceramic balls and the crushed oil shale are separated by a trommel,
which is a heavy-duty, rotating cylindrical screen. The trommel operates within the
sealed accumulator vessel. The balls are lifted by a bucket elevator to a ball heater,
which is a direct-contact heat exchanger designed to heat the balls to about 688 °C
(1270 °F). The spent shale leaving the pyrolysis drum goes through a special heat ex-
changer to cool the shale and produce steam for plant use. The spent shale is also
quenched with water and moisturized to approximately 14 percent, a level deter-
mined to be optimum for disposal.
Hot flue gas from the ball heater is used to lift raw shale to a point at which it can
subsequently flow by gravity into the pyrolysis drum. In so doing, the flue gas also
preheats the raw shale to approximately 260 °C (500 °F).
Primary outputs from the TOSCO II process are product gas, shale oil, and fine
spent shale. The fact that the process is indirectly heated accounts for the high
heating value gas product, since there is no nitrogen dilution effect from internal
combustion. On the other hand, the indirect-heated nature requires that the spent
shale leave the retort still bearing the residual carbon left after pyrolysis. Direct-
286
-------
RAW SHALE
SURGE HOPPER
.CAN CAS TO
I ATMOSPHERE
MOISTURIZER
SCRUBBER
RAW SMAlt
FEEDER
TO SPENT SHALE
DISPOSAL AND
REVEGE MTIOM
AREA
SPENT SHALE DISPOSAL CONVEYORS
Figure 7-3. TOSCO II retorting process.
-------
heated retorts, on the other hand, usually produce low heating value product gas,
but make use of some of the residual carbon on the spent shale. The spent shale
from the TOSCO II process is also distinguished from that of many other processes
in that it leaves the retort as a fine powder, with the average particle size approx-
imating .074 mm (200 mesh).
Primary sources of emissions from the TOSCO II process that require treatment
before discharge are:
Crushing, mining, conveying systems
Shale preheat system
Shale elutriation system (final ball-shale separator)
Shale moisturizing system
Hydrotreating, sulfur recovery, and other upgrading units
Steam boilers
The shale preheating system serves as the primary vent for all of the thermal re-
quirements of the process, and as such, emissions from this source represent the
most significant flow of gaseous emissions. Emissions-from this source will include
typical products of combustion, as well as sulfur dioxide nitrogen oxides, particu-
lates, hydrocarbons, and carbon monoxide. Though a variety of control devices
have been considered to control these emissions, the most effective technique to
minimize SO2 and NOX emissions is the use of low-sulfur clean fuels and proper
burner control. This, however, would require combustion of the more valuable
process products rather than low-value raw shale oil. The TOSCO II retorting
process could be utilized at various throughput rates, locations, and in combina-
tion with a variety of additional equipment. Emission data are therefore project-
specific, and data from one project would not necessarily apply to other projects.
Emission data presented in the conditional PSD permit from EPA for the Colony
Project have been summarized and are presented on Table 7-3 as an example only
of potential emissions from a plant processing 59,870 tonnes/day (66,000 tons) of
oil shale and recovering 6256 tonnes (46,000 bbl/day) of low-sulfur distillate.
Emissions from the shale elutriation system would be composed primarily of
NOX, carbon monoxide, and hydrocarbons. The levels of NOX could be controlled
by the use of clean fuels such as treated butane-butene from the gas treating plant,
or by proper burner operation.
Emissions from the shale moisturizing system would be confined to paniculate
matter, CO2, and possibly a small amount of hydrocarbon. Except for the sulfur
recovery unit, all emissions from the oil and gas treatment system would be the
result of fuel combustion. The properties of offgas, therefore, can largely be con-
trolled by proper utilization of clean fuels.
The TOSCO II process will produce wastewater from the following major
sources:
Pyrolysis of oil shale
Pyrolysis section steam condensate
Gas recovery section
This water would first be treated to remove the NH3, H2S, CO2 gases and other
volatile constituents and then be used to moisturize spent shale. The approximate
composition of this moisturizing water is shown in Table 7-4.
The solid waste from the process will consist of spent shale with an average parti-
cle size of approximately 0.074 mm (200 mesh). Since the process is indirectly
heated, the spent shale will also contain significant quantities of residual carbon,
making the material black in color and possibly inhibiting revegetation efforts.
Mulching, etc. would effectively reduce this tendency. In a commercial plant,
however, residual carbon could be burned off to provide process heat. The
chemical composition of typical spent shale from the process is shown in Table 7-5.
288
-------
TABLE 7-3. AVERAGE RATES OF AIR EMISSIONS
FROM PROPOSED COLONY PROJECT8
kg/hour (Ib/hr)
Source S02 NO,, HC Part. CO
Crushing, mining, 25.13
and conveying — — — (55.4) —
Shale preheat system 23.13 596.4 122.47 36.74 19.19
(51.0) (1314.8) (270.0) (81.0) (43.9)
Shale elutriation 42.77 51.44 0.14 17.15 1.27
system (94.3) (113.4) (0.3) (37.8) (2.8)
Shale moisturizing — — — 17.37 —
system (38.3)
Hydrotreating, sulfur
recovery, and other
upgrading units
Steam boilers
58.88
(129.8)
3.49
(7.2)
47.99
(105.8)
10.16
(21.6)
1.0
(2.2)
0.18
(0.4)
6.67
(14.7)
1.36
(2.9)
5.85
(12.9)
1.22
(2.6)
8 Source: Data summarized from Reference 2.
Paraho Development
The Paraho retort is a refractory-lined, vertical kiln in which a moving bed of
crushed oil shale, flowing downward through the kiln, is contacted with a counter-
current flow of hot gases having an adequate heat content to pyrolyze organic con-
stituents in the shale and convey the resulting vapors out of the top of the retort.
The process can be operated to utilize the residual carbon on the retorted shale as
the source of retorting heat (direct-heated mode) or in a configuration whereby the
retorting heat is provided by the recycling of product gas heated in an external fur-
nace (indirect-heated mode). First to be discussed will be the direct-heated mode,
since this is the configuration used in most of the earlier testing. Figure 7-4 il-
lustrates the process. In this process, crushed oil shale feed of 0.95 to 8.9 cm (3/8 to
3Vi in.) is charged to the top of the vertical kiln by an appropriate antisegregation
feeding device. As the shale passes downward through the retort, it is contacted by
an upward flow of gases near the top of the kiln, in the shale preheating and mist
formation zone, the heat in the rising gases is transferred to the cool incoming
shale, thereby preheating the solids and increasing overall thermal efficiency. Pass-
ing into the retorting zone, the solids encounter hot gases rising from the combus-
tion zone. These gases heat the shale to a temperature such that the organic constit-
uents are pyrolyzed. The vapors that are evolved are carried upward by the flow of
gases.
The retorted shale then passes into the combustion zone, where air is injected in
sufficient quantities to burn the residual carbon off the surface of the retorted
shale. This combustion provides the necessary heat to pyrolyze the shale in the
overlying retorting zone. In some cases, additional heat is supplied by injecting and
burning a part of the product gas. Passing through the combustion zone, the shale
enters the shale-cooling zone, where heat from the spent shale is transferred to a
rising stream of recycle gas. The cooled shale is then discharged from the retort by
a patented grate mechanism at the bottom of the vessel.
289
-------
TABLE 7-4. APPROXIMATE COMPOSITION
OF TOSCO II WASTEWATER
USED TO MOISTURIZE SPENT
SHALE"
Concentration
Componentb (ppm)
Ca+2 280
Mg+2 100
Na + 1 670
NH4+1 15
Zn+2 5
As+5 (15-300 ppb)
Cr+6 2
CO-2 360
HC03-1 100
S0«-2 850
S203-2 90
P04-3 5
Cl-1 570
CM'1 5
Phenols 315
Amines 410
Organic acids 1,330
Neutral oils 960
Chelate 5
a Source: Reference 3.
^ Elements present in trace amounts include Pb, Ce, Ag, Mo, Zr, Sr, Rb,
Br, So, Cu, Ni, Co, Fe, Mn, V, Ti, K, P, Al, F, B, and Li.
TABLE 7-5. CHEMICAL COMPOSITION OF
TOSCO II SPENT SHALE8
Component
S03
Total carbon
Inorganic carbon
Organic carbon
Si02
AI203
Fe.03
CaO
MgO
Na20
K20
Weight %
2.63
9.83
4.41
5.41
33.07
9.14
3.24
17.56
7.74
0.77
1.39
a Source: Reference 4.
290
-------
OIL MIST
EXTRACTORS
STRIPPING AND
WATER GAS SHIFT
CONDENSER
000
PREHEATING
AND
MIST FORMATION
PYROLYSIS
GRA1E SPEED
CONTROLLER
BLOWER
RESIDUE
Figure 7-4. Diagram of Paraho retorting process.
(Source: Reference 1).
The same basic flow regime is used in the indirect-heated mode, except that in-
stead of injecting air and thus forming a combustion zone, only hot recycle gas is
injected. This recycle gas is taken as a slip stream off the product gas line and
heated externally in a furnace. The fuel for combustion in this furnace is usually
product gas, but this could be augmented by burning residual carbon or spent
shale.
The direct-heated mode of the Paraho process resembles other vertical kiln
operations such as the gas combustion process, and as such, it would be expected to
have similar emissions and effluents. Because of the effect of nitrogen dilution, the
product gas from the Paraho process would have a heating value of approximately
890 kcal/scm (100 BTU/scf). The spent shale, since it undergoes very little if any
attrition in the retorting operation, will emerge from the retort at essentially the
same size it entered. This size range minimizes the dust problem when transporting
and disposing of the spent shale. Since some of the residual carbon on the spent
shale is used to provide heat for the retorting operation, the final spent shale from
the retort will not be black, but rather gray in color. The composition of Paraho
spent shale is shown in Table 7-6.
When operating in the indirect-heated mode, the Paraho process will produce
product gas with a heating value of approximately 7832 kcal/scm (880 BTU/scf).
However, the spent shale from the retort will contain all of the residual carbon pro-
duced by the pyrolysis process. As in the direct-heated mode, the shale fragments
will undergo little if any attrition during the retorting operation and will thus leave
291
-------
TABLE 7-6. COMPOSITION OF PARAHO
SPENT OIL SHALES
Component
Si02
CaO
MgO
AI203
Fe203
Na20
K20
S03
P206
Mineral C02
Organic C
Inorganic C
Texture
pH
Paraho
Indirect
(In Weight
23.1
15.3
6.5
8.0
2.7
2.3
2.4
0.7
—
18.1
1.84
4.95
silty
gravel
10.9
Paraho
Direct
%)
28.0
18.3
6.5
6.9
2.7
2.6
6.6
0.2
—
13.3
2.18
4.15
silty
gravel
11.1
Reference: Table 3-24.
the retort with approximately the same particle size distribution as the feed.
The composition of the gas stream from the indirect- and direct-heated retorting
mode varies considerably. The estimated composition of this stream, following
compression, cooling, and water knockout is shown in Table 7-7. The retort gas
analysis is shown in Table 7-8.
The wastewater produced by the Paraho retorting process is comparable to that
produced by other processes, as reported in the literature. Three separate
wastewater streams were analyzed by EPA during test runs in 1976 (5). These
streams are:
Cold condensate stream from the sample condenser at the pilot plant
Hot condensate stream from the bottom gas cooler of the semi-works plant
Process water separated from the crude shale oil
A summary of the data collected during these tests is shown in Tables 7-9 and
7-10. The BOD tests were conducted with great difficulty and little precision. Cor-
relation with COD was poor. Thus, the values shown on the table should not be
taken as definitive. Reference 5 also cites cautions regarding the values for total
alkalinity and hardness.
Union Oil Development
All three of the processes developed by Union Oil are variations of an upflow
vertical kiln retort using a rock-pump shale feeding mechanism. The retorts are
known as Retort A, Retort B, and SGR-3 . In all three processes, the oil shale is
pushed upward through the retort while the gas flow is downward. In Retort A, the
heat for pyrolysis is generated by the internal combustion of residual carbon on the
spent shale. In Retort B and the SGR retort, the heat is supplied indirectly by hot
gases.
The Retort A process was developed through 1.8-, 45-, and 9000-tonne/day (2-,
292
-------
TABLE 7-7. COMPOSITION OF PARAHO RETORT
GAS PRODUCT8
Component
N2
02
H2
CO
C02
H2S
c,
C2's
C3's
C4's
H20
Total
Direct-Heated
(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
Indirect-Heated
(Vol. %)
1.8
_
36.6
7.3
21.2
2.0
20.5
6.1
1.2
0.6
2.3
100.0
a Source: Reference 6.
TABLE 7-8. AVERAGE COMPOSITION OF PARAHO RETORT
OFFGAS8
Component
H2
02
N2 + argon
CH4
CO
C02
H2S
NH3
C2=
C2
C3
C4
Direct-Heated
(Vol. %)
2.5
—
65.7
2.2
2.5
24.2
0.266
0.249
0.7
0.6
0.7b
0.4C
Indirect-Heated
(Vol. %)
24.8
—
0.7
28.7
2.6
15.1
3.5
1.2
9.0
6.9
5.5
2.0
a Source: Reference 7.
b Includes Ca~
c Includes 64.
293
-------
TABLE 7-9. INORGANIC ANALYSIS OF CONDENSATE
STREAMS FROM THE PARAHO PROCESS"
Parameter
Cations:
Calcium
Magnesium
Sodium
Potassium
Ammonium (NH, + )
Anions:
Carbonates
Bicarbonates
Sulfate
Sulfide
Chloride
Fluoride
Nitrate
Nitrite
Nutrients:
NH3-N
TKN
Phosphate (total)
Gross parameters:
BOD
COD
TOG
TIC
Oil 8- grease
Solids, total
Solids, upon
evaporation
Solids, suspended
Total alkalinity
Hardness
Phenols
pH
Cold condensate from
pilot plant,
direct mode
(mg/l)
60.74
<0.1
0.20
0.08
5652-calc.
30500-calc.
31265-calc.
113.6
<0.1
TR
0.35
118
0.02
14060-calc.
31,400
0.58
12,000
19,400
29,200
9,800
502
22,000
21,800
200
68,550
152-calc.
46
9.8
Hot condensate from
semi-works plant,
indirect mode
(mg/l)
39.16
<0.1
0.29
0.18
13440-calc.
3030-calc.
6280-calc.
1.65
390
TR
0.10
1.0
<0.002
16800-calc.
—
0.75
4,850
17,100
9,800-36,900
1,600
33.3
429
406
—
12,900
98-calc.
42
9.5
a Source: Reference 5.
294
-------
TABLE 7-10. ANALYSIS OF PARAHO CONDENSATE WATER
AND PROCESS WATER"'"
Element
Uranium
Lead
Mercury
Praseodymium
Cesium
Lanthanum
Barium
Iodine
Tin
Molybdenum
Zirconium
Yttrium
Strontium
Rubidium
Bromine
Selenium
Arsenic
Gallium
Zinc
Copper
Nickel
Cobalt
Germanium
Iron
Manganese
Chromium
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Boron
Lithium
Cold Condensate Water
from pilot plant,
3/10/76
0800-1,700 hrs
(/jg/ml)
0.03
0.7
<0.01
0.008
0.01
0.04
0.1
0.008
0.05
0.3
0.05
0.007
0.1
0.4
0.02
0.04
0.09
0.04
0.2
0.1
0.1
10
0.2
0.07
<0.01
0.9
0.01
8
3
0.4
3
0.2
4
0.2
3
51b
-0.1
0.06
0.02
Process Water
from semi-works
3/15/76
1,500 hr
(ng/ml)
0.2
<0.01
0.01
2.0
0.1C
3.0
0.009
0.1
1.0
<0.02
0.4
0.2
0.2
<0.04
<0.05
5.0
0.3
0.3
0.03
0.3
<0.05
>10
>10
2.0
>10
5.0
>10
0.8
>10
>10
7
-5.0
1.0
a Source; Reference 5.
b After extraction of organics, sample was thermally ashed @ 450°C for % hr in a laboratory furnace
in a quartz crucible before analysis.
c Heterogeneous.
295
-------
50-, and 10,000-ton/day) pilot plants that were operated before 1960. A view of the
Retort A process is shown in Figure 7-5. The retort is an inverted cone fitted with a
rock-pump shale feeder that pushes the oil shale upward through the vessel. Air is
injected at the top of the retort to support combustion of the residual carbon on the
retorted shale fragments in the upper portion of the retort. This combustion pro-
vides the heat necessary to retort the upward-flowing shale.
•AIR
SPENT
SHALE
COOLING
AND
DISPOSAL
OIL
Figure 7-5. Diagram of Union Oil Retort A.
(Source: Reference 1.)
The crushed shale feed is removed from the hopper and transferred to the bot-
tom of the retort by a shale feeder. As the shale enters the retort, it is contacted by
a countercurrent flow of hot product gases leaving the combustion and retorting
zones above. In this lower zone, the gas-cooling zone, heat is transferred from the
hot gases to the cool incoming shale. The feed is preheated, and the oil vapors are
condensed, resulting in higher thermal efficiencies. In addition, the recovery of the
sensible heat in the gas also -makes subsequent gas handling easier. Passing up
through the retort, the preheated shale enters the retorting or pyrolysis zone. The
gases passing downward in this area, having just left the combustion zone, heat the
shale to a temperature such that organic material is pyrolyzed, producing shale oil
vapor, product gas, and residual carbon on the surface of the shale. As the gaseous
products of pyrolysis are evolved, they are swept downward by the flow of combus-
tion gases.
The retorted shale fragments then enter the combustion zone where they en-
counter preheated combustion air passing down through the retort. This air sus-
tains the combustion of the residual carbon that remains on the surface of the shale
after retorting. Temperatures in this zone may reach 1093 °C (2000 °F), high enough
to fuse a portion of the shale. In earlier versions of the retort, retorting spiral plows
296
-------
were used to break clinkers and remove retorted shale. In later versions, these
plows were not used. Herein lies one advantage of the Union rock-pump retorts.
Since the spent shale will eventually overflow the top of the retort rather than pass
through a discharge grate mechanism, the formation of large clinkers does not pre-
sent as much of a problem as it does in typical gravity flow retorts.
The hot spent shale leaves the combustion zone and enters the topmost zone, the
air preheat zone. In this area, heat from the spent shale is transferred to the cool in-
coming combustion air, thus preheating the air before entry into the combustion
zone. Upon leaving this zone, the shale is pushed up over the top of the retort and
falls into the ash disposal chute.
Below the gas cooling zone, in which some of the retort products are condensed,
the retort walls are slotted to allow separation of the oil and gas from the incoming
shale. A bustle surrounds this section, and the gas and oil pass through this bustle
to the product recovery system. The shale feeder is constructed so that any fines
that pass through the slots return to the feeding piston and are reintroduced into
the kiln. Thus, the gas and oil collector does not become plugged with an ac-
cumulation of fines. The feeding mechanism is filled with oil to a level just below
that of the slot edges, providing a liquid seal that prevents air from being drawn in-
to the kiln through the shale feeder. The liquid oil level is determined by pressure in
the retort. Oil drains through the retort exit line to the Roto-clone collector.
Retort B closely resembles Retort A, except that the heat for pyrolysis is supplied
by hot recycle gas rather than internal combustion. Another difference is that the
design of the rock-pump shale feeder is slightly altered to permit feed rates up to
9,072 tonnes/day (10,000 tons/day). Diagrams of the Retort B process are shown
in Figures 7-6 and 7-7.
Sized and screened oil shale is drawn through a shale oil seal in the feed chutes
and pumped into the bottom of the retort by the two rock-pump pistons. Shale oil
product acts as a hydraulic seal in the feed chutes to maintain retort pressure. The
solids pump, mounted on a movable carriage, is completely enclosed within the
feeder housing and immersed in shale oil. The pump consists of two hydraulic
piston and cylinder assemblies that alternately feed shale to the retort. While one
cylinder of this rock-pump is filling with oil shale feed during a piston downstroke,
the other cylinder is charging oil shale into the retort. When this operation is com-
pleted, the pump carriage is moved horizontally on rails until the full cylinder
comes under the retort. This cylinder charges its oil shale upward into the retort
while the other fills with shale from the other feed chute. The carriage is then
moved back to its original position and the cycle is repeated. Seal plates outboard
of each cylinder close off the idle feed chute to prevent discharge of shale into the
feeder housing.
The oil shale moves uniformly up through the cone to form a free-standing pile
on top of the retort bed. Retorted shale falls by gravity from the top of the vessel,
but it may be assisted by a lightweight rake rotated above the top of the bed. The
retorted shale is then discharged into a collection and cooling system. The top of
the retort cone is enclosed by a pressure dome, permitting operation at a nominal
1.10 kg/cm2 (15 psig). As in the Retort A, a series of vertical slots around the
perimeter of the lower cone wall provides the openings for disengaging the con-
densed oil and retort vapors from the solids bed.
The composition of Retort A off gas is given in Table 7-11. Emission data for the
Union B retort and associated facilities for a modular oil shale facility contained in
the proposed conditional PSD permit from EPA to the Union Oil Co. are sum-
marized on Table 7-12. The modular project will consist of mining 13,750 tonnes/
day (15,156 tons/day) of oil shale and producing 1,224 tonnes of oil/day (9,000
bbl/day).
Because of its relative simplicity and encouraging process economics, the Retort
B process was selected in 1976 as the process to be demonstrated on a commercial
297
-------
RtlOUt MAKE OA5
Figure 7-6. Process Flow Diagram Union Retort B Process.
-------
SHALE FEED
CHUTE
OIL LEVEL
•RETORTED SHALE
DISCHARGE
TO WATER SEAL
RETORT
OUT
SHALE OIL
OUT
Figure 7-7. Diagram Union Oil Retort B.
(Source: Reference 1.)
TABLE 7-11. COMPOSITION OF
UNION A OFFGAS
Component
H2
02
N2 + argon
CH4
CO
C02
H2S
C2=
c.
Ca"
Cs
c4=
c«
cs
Vol. %
2.2
2.2 air
57.6
0.9
4.6
30.3
0.1
0.6
0.4
0.4
0.2
0.3
0.1
0.1
Source: Reference 7.
299
-------
TABLE 7-12. SUMMARY OF DESIGN EMISSIONS FOR
THE UNION B RETORT AND RELATED
FACILITIES
kg/hr (Ib/hour)
Source S02 NOX Part. CO HC
Mining, conveying, —
crushing.
etc. —
Retorting and
handling
Spent shale
product
36.80
(81.11)
6.12
(13.5)
38.99
(85.96)
disposal — —
14.28
(31.5)
0.64
(1.42)
0.
,99
3.76
(8.3)
22.98
(50.66)
—
(2.2)
—
—
11.
(25.
8.
(17.
4
13)
12
9)
scale. In early 1977, a process was announced that, when retrofitted to a Retort B
prototype unit, would further improve the economics of the process by utilizing the
residual carbon left on the spent shale. This process, known as SGR-3, provides for
the combustion of the residual carbon in a separate vessel, thus producing enough
hot flue gas to supply all of the retort heat requirements. This technique provides
for the production of a 8,720-kcal/scm (980-BTU/scf) product gas from the retort
while maintaining a high thermal efficiency (83 percent) by using the residual car-
bon on the spent shale. Following the removal of Ct plus hydrocarbons and acid
gases from the gas stream, the heating value is reduced to approximately 7,120
kcal/scm (800 BTU/scf). This value can be increased to more than 8,900 kcal/scm
(1,000 BTU/scf) by methanation. A flow diagram for the process is shown in
Figure 7-8.
Because of the design of the rock pump feed mechanism, all of the proposed
Union Oil processes utilize fairly large shale fragments of 5 cm to 0.3 cm (2 to 1/8
in.). As in the other vertical kiln type processes, very little attrition occurs during
the retorting process, and thus the spent shale fragments leave the retort essentially
the same size as they entered. The spent shale from the direct-heated Union retorts
would be gray in color, having had some of the residual carbon burned off. The
indirect-heated retorts, on the other hand, would discharge shale still containing
the residual carbon. The SGR-3 process employs a separate spent shale combustor
unit. The spent shale from these processes, therefore, would be light-colored, con-
taining very little if any residual carbon. The composition of the spent shales is
shown in Table 7-13.
The composition of the product gas from the retort largely depends on the mode
of heating. Indirectly heated retorts will produce a high-BTU gas product whereas
the product from direct-heated retorts will have a low BTU content because of
nitrogen dilution. The product gas composition from the SGR-3 process is shown
in Table 7-14. Composition of the flue gas from the combustor in the SGR-3 proc-
ess is shown in Table 7-15.
Superior Oil Development
The retorting process that the Superior Oil Co. proposes to use in its multi-
mineral extraction facility features a circular traveling grate retort. The design
features of the process are shown in Figures 7-9 and 7-10. Figure 7-11 is a diagram
of the Superior retorting process. In the process, a layer of crushed and sized oil
shale is placed on a continuous belt or grate. This grate is designed so that gases can
flow through both it and the shale bed. As the shale circulates within the doughnut,
it encounters separate zones in which it is heated, retorted, cooled, and dumped.
300
-------
RAW
OIL/WATER
SEPARATOR
Figure 7-8. Diagram of Union Oil SCR-3 retorting process.
(Source: Reference 1.)
-------
STATIONARY
— HOOO
OIL HIST AND
RECYCLE GAS
TO OIL REMOVAL
Figure 7-9. Cross sectional view of Superior retort.
302
-------
FEED
COOL
RECYCLE
GAS
COOL,
EQUIVALENT TO AN
ADIABATIC RETORT
FIXED BED SECTION
Figure 7-10. Functional design of Superior retort.
-------
HOT AIR TO NAHCOUTE PLANT
HOT AIR TO ALUMINUM AND
OIL/WATER
SEPARATION
HEAT EXCHANGER
Figure 7-11. Diagram of Superior retorting process.
(Source: Reference 9.)
-------
TABLE 7-13. COMPOSITION OF UNION SPENT OIL SHALES
Component
Si02
CaO
MgO
AI203
Fe203
Na20
K20
S03
P20B
Mineral CO2
Organic C
Inorganic C
Texture
pH
Union A
35.3
27.2
9
8.5
7.3
5.5
2.8
0.1
2.2
1.6
0.5
—
graded
gravel to
silty gravel
12.5-13.0
Union B
(in weight %)
31.5
19.6
5.7
6.9
2.8
2.2
1.6
1.9
0.4
22.9
4.3
—
silty
gravel
8.7
Union SGR
39.2
27.3
8.2
8.9
3.8
3.7
2.7
1.4
0.5
3.1
0.3
—
silty
gravel
12.5
TABLE 7-14. COMPOSITION OF
PRODUCT GAS
FROM UNION
SGR-3 PROCESS8
TABLE 7-15.
COMPOSITION OF
COMBUSTOR FLUE
GAS FROM SCR-3
PROCESS"
Component
H2
C,
Cz
Cs
c«
C5
C.
CO
C02
H2S
Vol. %
25
24
10
8
5
2
1
5
16
4
Component
N2, mol. %
CO2, mol. %
02, mol. %
S02, ppm
NOX, ppm
a Source: Reference 8.
Amount
71
28
0.5
5
300
a Source: Reference 8.
305
-------
The hot gases that pass through the shale in the retorting zone are heated extern-
ally; these gases are products of combustion from burned product gas. In one zone
of the retort, some of the residual carbon on the spent shale is burned off.
Both circular and straight grates have long been in commercial use for iron ore
pellet sintering, cooling, and other kiln applications. Superior's process develop-
ment effort focuses on adaptation of the circular grate process for oil shale retort-
ing. This effort included construction and operation of an adiabatic fixed-bed
retort designed to simulate the conditions encountered by a section of solids as it
travels through the separate processing zones in the circular grate. The adiabatic
retort tests identified the significant process variables and their effect(s) on cost
responses such as throughput rate, thermal efficiency, product yield, etc. Cost sen-
sitivity analyses established optimum ranges in which to design and operate the cir-
cular grate oil shale pilot retort that was later constructed.
The pilot circular grate retort operations defined design and scale-up informa-
tion for the oil removal system that had never been tested in prior circular grate ap-
plications. Pilot plant operations also confirmed the mechanical reliability of solids
flow on four types of shale. The primary results of this process development effort
have been:
Attainment of thermal efficiency for the cross-flow circular grate which ap-
proaches those achieved in countercurrent flow devices.
Product oil yields more than 98 percent of Fischer assay.
Development of a proved oil recovery system.
Optimized throughput and gas rates/ton of oil shale processed.
Lurgi-Ruhrgas Process
The Lurgi-Ruhrgas process features the use of heat-carrier solids of small parti-
cle size, such as sand grains or spent shale solids derived from the retorting process.
Figure 7-12 is a simplified diagram of the process. The hot solids are mixed with
finely crushed (0.6-cm or 1/4 in.) raw oil shale in a sealed, screw-type conveyor.
The organic constituents are pyrolyzed during the mixing which occurs in this
device. Upon leaving the screw conveyor, the effluents are separated into solid and
gaseous components in a collection bin. A portion of the spent solids is recycled to
a lift pipe, and the remainder is discarded. In the lift pipe, the hot spent shale is
contacted with air at approximately 400 °C (750 °F), raising the material pneu-
matically and simultaneously burning the carbon residue on the shale surface. The
combustion gases and hot spent shale are separated at about 650 °C (1200 °F) in a
collecting bin, and the solids are mixed again with incoming oil shale in the screw
conveyor. Between 6 and 8 pounds of heat-carrying solids are circulated and mixed
with each pound of raw oil shale.
Since no air is injected into the retorting area, the gas product from the process
has a high heating value. Furthermore, the oil yield from the process typically
ranges between 95 and 110 percent of Fischer assay. Since the residual carbon on
the spent shale is mostly utilized in the process, the overall thermal efficiency is
quite high.
Because the Lurgi-Ruhrgas process is indirectly heated, the product gas has a
high heating value; but unlike other indirectly heated retorts such as the TOSCO II
process, residual carbon utilization is an integral part of the retorting process, and
therefore the spent shale will be rather light in color and contain relatively little
residual carbon. Like the TOSCO II process, the Lurgi-Ruhrgas process used raw
oil shale feed with a particle size of less than 0.6 cm (1/4 in.). No public informa-
tion is yet available regarding the final spent shale characteristics, but it is
reasonable to assume that some degree of attrition will occur, thus leading to a
somewhat smaller average particle size in the final spent shale.
The primary atmospheric emission stream from the Lurgi-Ruhrgas process is flue
gas from the combustion of residual carbon on the spent shale. This stream will
306
-------
6AS/SC
SEPAR/0
BIN
\
ILIDS
TION
1
\
WASTE HEAT
RECOVERY
DUST
CYCLONE
WASTE
•FLUE GAS WASTE
OIL
CONDENSER
DUST
REMOVAL
CYCLONE
MIXING SCREW
TYPE RETORT
GASEOUS AND
"LIQUID PRODUCTS
AIR+ FUEL
(If Required)
Figure 7-12. Lurgi-Ruhrgas retorting process.
(Source: Reference 1.)
contain typical products of combustion, along with some sulfur dioxide (SO2),
nitrogen oxides (NOx), and particulates. During pilot plant tests conducted thus
far, particulate loading averaged 80 mg/m3, and this level could be controlled with
available technology. The SO2 content detected during these tests was approxi-
mately 10.5 ppm. This low level may be attributable to the absorption of SO2 by the
CaO and MgO formed in the spent shale during the retorting process. Under the
expected operating conditions for large-scale installations, the NOX level is not ex-
pected to exceed 100 ppm (10). The offgas is shown in Table 7-16, in volume
percent.
The major source of liquid waste from the process is the gas condensate pro-
duced during the pyrolysis of oil shale. This stream would contain minor amounts
of ammonia, sulfur, oil, and phenols. The stream could either be used to
moisturize spent shale or be treated with existing technology before disposal or
reuse. The properties of this stream are shown in Table 7-17.
The fine spent shale from the Lurgi-Ruhrgas process would be light in color
because of the utilization of residual carbon. This would perhaps enhance revegeta-
tion efforts. Recent studies have indicated that spent shale similar to that from the
307
-------
TABLE 7-16. COMPOSITION OF
LURGI-RUHRGAS
OFFGAS"
Component
H2
N2 + argon
CH4
CO
C02
H2S
C2=
C3=
C4
S02
Vol. %
18.5
7.7
11.9
2.7
25.0
46.2
12.0
8.9
C«+ 13.3
g/NM3
0.06 gNM3
a Source: Reference 7.
Lurgi-Ruhrgas process may be moistened to achieve some degree of cementation,
thus minimizing erosion effects on disposal piles (4).
TABLE 7-17. PROPERTIES OF
LURGI-RUHRGAS
CONDENSATE
WASTEWATER"
Constituent Amount %
Total hydrocarbons
(including phenols) 0.4 wt. %
Dust 0.03 wt. %
Ammonia 1.7 wt. %
Sulfur 0.05 wt. %
Phenols 0.026 wt. %
pH 9.3
8 Source: Reference 10.
IGT HYTORT Process
The HYTORT process developed by IGT has been scaled up from laboratory
and bench-scale to a Process Development Unit (PDU) with a capacity of 22 tonnes
(24 tons) per day. The process has been developed to process eastern Devonian as
well as Western Eocene shales to produce either a synthetic crude or synthetic
natural gas (SNG).
Eastern Devonian shales, although they may have a similar organic carbon con-
tent, produce a much lower yield of oil plus gas when retorted by conventional
methods (as indicated by Fisher Assay) than do western Green River Formation oil
shales. This is probably due to the lower hydrogen/carbon ratio of the eastern shale
as well as to structural differences in the two types of shale. The Institute of Gas
Technology found that by retorting eastern shales under high hydrogen partial
pressure the oil and gas yield could be significantly increased.
308
-------
Based on the encouraging results obtained thus far in laboratory and bench-scale
tests, IGT has prepared preliminary process designs for the HYTORT process. A
commercial HYTORT plant would consist of three basic sections: the retort and
associated solids handling system; the hydrogen plant and other utilities; and the
shale oil or SNG upgrading equipment. A block flow diagram for a plant produc-
ing syncrude from eastern Devonian shale is shown in Figure 7-13.
Raw shale would be crushed to the size range required by the HYTORT reactor,
with undersize material returned to the land reclamation site. Process shale would
be fed to the high-pressure HYTORT reactor through liquid-sealed lockhoppers,
patented IGT devices. The shale would move downward, counter-current to the
hydrogen-rich gas flow, through the HYTORT reactor. A small amount of oxygen
would be injected into the reactor near its center for heat balance purposes. Spent
shale would be removed from the reactor through liquid-sealed lockhoppers.
Product gas from the retort, containing a mist of partially-condensed shale oil
and water would be scrubbed to recover water and raw shale oil. Acid gas constit-
uents would then be removed, and by-product sulfur and ammonia recovered. A
bleed stream of the clean gas would be sent to the steam reformer, to convert
hydrocarbon gas constituents into hydrogen. The balance would be recycled di-
rectly to the HYTORT reactor. All of the makeup hydrogen requirements for
hydroretorting and catalytic hydrotreating would be produced in this fashion.
Raw shale oil would be catalytically hydrotreated to produce a low-sulfur, low-
nitrogen refinery feedstock product and a plant utility fuel stream. A supplemen-
tary acid-treating step could be added to reduce the product nitrogen content fur-
ther. A net syncrude yield of approximately one-half barrel per ton of shale would
typically be produced with eastern Devonian shale.
The major source of pollutants in the process plant would be the water produced
by the chemical reactions in the hydroretorting and,to a lesser extent, the catalytic
hydrotreating steps. Table 7-18 shows estimated production rates of these
substances from the hydroretorting step in a 6,285 tonnes (46,214 bbl) per day
plant processing eastern Devonian shales. It is anticipated that in a commercial
plant a zero discharge concept could be employed and that internal water streams
would be extensively treated. Net water usage would result from cooling tower
evaporation and drift, and from water on the spent shale.
The main identified sources of air pollutants for the HYTORT process are:
Shale handling and crushing facilities.
Claus sulfur plant and process gas vents.
Flue gas from plant boilers and fired heaters.
These sources produce pollutants in the form of particulates, SO2, NOX, light
hydrocarbon gases, and CO. An estimate of emission rates of these pollutants from
a 6,285 tonnes (46,214 bbl) per day syncrude plant operating on eastern Devonian
shale is shown in Table 7-19.
IN SITU RETORTING PROCESSES
Occidental Modified In Situ Process
The modified in situ (MIS) recovery process developed by Occidental Oil Shale,
Inc. (Oxy) involves the mining of approximately 15 to 25 percent of the retort
volume and rubblizing the remaining shale into the void. Vertical longholes are
drilled, loaded with an ammonium nitrate-fuel oil explosive, and detonated with
timing delays in a fashion that explosively expands the rock mass to fill the entire
volume. After rubblization, ignition of the retort is initiated by injecting a small
amount of supplemental fuel at the top of the retort to heat the rubble pile to ap-
proximately 500 °C (900 °F). The heat released retorts the top shale to produce shale
oil, some gas, and a residual carbon left on the shale. This carbon then becomes
part of the required fuel. Either steam is added along with the combustion air or
309
-------
RUN-Of-MINE
RAW SHALE
ACTIVE
DISTRIBUTORS
LIQUID-SEALED
LOCK. HOPPERS
FINES TO
DISPOSAL
SCRUBBING AND PHASE
RETORT
PRODUCT
GAS AND OIL
02
RECYCLE H2-RICH GAS
PRODUCT
SYNCRUDE
Figure 7-13. HYTORT™ commercial plant concept.
(Source: Reference 11.)
-------
TABLE 7-18. WATER POLLUTANT LOADING FROM
HYDRORETORT REACTORS8
Pollutant
Oxygenated Compounds
Alcohols
Acetone
2-butanone
2-pentanone
Acetic Acid
Propanoic Acid
Butanoic Acids
Pentanoic Acids
Phenol
Cresols
Xylenols
Total
Sulfur Compounds
H2S
Methyl Mercaptan
Ethyl Mercaptan
Thiocyanate (SCN)
Miscellaneous
Total
Nitrogen Compounds
Ammonia
Acetonitrile
Tolunitrile
Pyridine
Methyl Pyridines
Ca-Pyridines
Ca-Pyridines
Production
kg/ day
307
1,011
661
78
6,608
1,944
389
661
451
389
214
12,711
73,857
272
389
54,987
3,498
133,003
76,505
12
233
292
233
175
Rate
(Ib/day)
(677)
(2,229)
(1,457)
(171)
(14,572)
(4,286)
(857)
(1,457)
(994)
(857)
(471)
(28,028)
(162,860)
(600)
(857)
(121,250)
(7,714)
(293,281)
(168,700)
(26)
(514)
(643)
(514)
(386)
(continued)
311
-------
Table 7-18. (continued)
Pollutant
Production Rate
kg/day (Ib/day)
Pyrolle
Methyl Pyrolles
C2-Pyrolles
C3-Pyrolles
C4- Pyrolles
Aniline
Methyl Aniline
C2-Anilines
Quinoline
Indole
C6H13N
C7H1BN
CaH^N
C,H17N
2,177
739
350
117
20
972
661
50
39
39
156
428
280
389
(4,800)
(1,629)
(771)
(257)
(43)
(2,143)
(1,457)
(111)
(86)
(86)
(343)
(943)
(617)
(857)
Total 87,207 (192,298)
Hydrocarbons
Benzene 311 (686)
Toluene 583 (1,286)
Total 894 (1,972)
Trace Organic Constituents 1,088 (2,400)
a Source: Reference 12.
part of the offgas may be recirculated to control the oxygen concentration in the in-
coming air. The oil and water vapor condenses in the coal rubble below the retort-
ing zone and flows to the bottom of the retort where it is collected in a sump and
pumped to underground storage. The gas not consumed to the system has a poten-
tial for power generation significantly in excess of the plant needs.
The product shale oil flows downward ahead of the combustion zone and is col-
lected in a sump at the bottom of the retort. Pipelines carry the shale oil from the
sump to surface storage facilities. A conceptual diagram of an Oxy retort is shown
in Figure 7-14, and a flow diagram for the commercial process is shown in Figure
Retorts 7 and 8 are now being developed at Oxy's Logan Wash test site near
DeBeque, Colorado. These two retorts, operated simultaneously, constitute a net
increase of greater than 100 tons per year of certain effluents. The facility is,
therefore, considered a modified source and is subject to the PSD process. A con-
ditional PSD permit was issued by EPA on November 1, 1979. Table 7-20 gives the
air emissions allowed by the permit.
The total offgas flow will pass through a contact condenser and reduce by 60
312
-------
TABLE 7-19. ESTIMATED EMISSIONS FROM COMMERCIAL HYTORT PLANT
Tonnes (Tons) Per Year"
Source of
Emissions
SCOT Tail Gas Unit
High Pressure Boiler
Steam Reformers
Hydrotreater Preheaters
Shale Crushing &
Handling Equipment
Fluidized Bed Incinerator
Totals
Participates
0.19
1.62
3.18
0.28
6.37
0.28
11.92
(0.21)
(1.79)
(3.50)
(0.31)
(7.02)
(0.31)
(13.14)
3
0
1
0
0
4
S02
.15
.52
.01
.09
—
.03
.79
(3.47)
(0.57)
(1.11)
(0.10)
(-)
(0.03)
(5.28)
NOX
0.58
4.87
9.52
0.85
0.28
16.10
(0.64)
(5.37)
(10.49)
(0.94)
(-)
(0.31)
(17.75)
CO
5
9
92
8
3
117
(6)
(10)
(101)
(9)
(-)
(3)
(129)
Light
Hydrocarbon Vapors
83
468
1,372
122
41
2,087
(92)
(516)
(1,512)
(135)
(-)
(45)
(2,300)
a Source: Reference 12.
-------
percent the condensable hydrocarbons. Three steam plants will be at the site, but
only two will operate at any one time. Two heater treater units will operate at the
head of Logan Wash on an intermittent basis. The offgas consists primarily of
gases from shale pyrolysis, carbon dioxide and water vapor from the combustion of
carbonaceous residue, carbon dioxide from the decomposition of inorganic car-
bonate (primarily dolomite and calcite), and hydrogen from the water gas reaction
as well as N2. A pilot combustor and pilot FGD system will be built and tested for
retorts 7 and 8. Table 7-21 gives the composition of the retort gas assuming the MIS
retort producing 56,874 barrels per day crude shale from an assumed 147,600
tonne/day (164,000 tons/day) of shale of approximately 113.5 I/tonne (25 gal/ton)
assay oil shale. Table 7-22 shows a typical process water analysis from Retort 6.
Rio Blanco MIS Process
The Rio Blanco MIS process removes about 50 percent of the shale from
underground and the remainder is explosively rubbled into the resulting void, then
retorted. The mining is done from the bottom level of the target zone and a
rectangular-shaped room is created. A pattern of blast holes is then drilled from the
surface, loaded with explosive, and sequentially fired to optimize rubble size and
thus create an optimum void volume. Some of the vertical blast holes are then used
for down-hole burners and injection of air, steam, and water. The retort is then ig-
nited and retorting progresses downward through the retort. Quench water can be
used to control outlet gas temperature. Retort water is kept from mingling with
mine seepage by bulkheads and separate collection drifts. A Modular Development
Phase (MDP) mine diagram is shown in Figure 7-16.
Rio Blanco intends to use this process on Federal lease Tract C-a. Estimated par-
ticulate and SO2 emissions from the Modular Development Phase on Tract C-a are
shown in Table 7-23. The estimates include emissions from all mining, processing,
waste disposal, and vehicular movement during the MDP. Estimates of other emis-
sions are not available.
Multi-Mineral Integrated In Situ Process
The Multi-Mineral Integrated In Situ Process for the recovery of shale oil and
associated minerals consists of three steps: underground mining and nahcolite
recovery; retorting and hydrocarbon recovery; and leaching and soda ash/alumina
recovery.
The process involves creating large underground chambers (slopes) by sequential
blasting and removal of the oil shale from the slope. Gravity flow extraction is
through funnel-like openings at the base. The slopes are separaled by walls of un-
broken oil shale. Their dimensions are variable, depending on Ihe rock character
and zone Ihickness. Extracted oil shale is crushed and screened into two sizes with
the larger size being backfilled into Ihe slope. The smaller size is Ihen crushed and
screened to separate nahcolite from the oil shale. Rejects from this operation are
stored on the surface for future processing.
After backfilling with the lop size, Ihe slopes, full of sized oil shale, become
underground relorls. The oil shale is relorted by hoi gas introduced into the top of
the retorl and exlracled al the base. The shale oil formed, along with the pyrolysis
gas and waler, is direcled lo a collection sump where Ihe oil, waler and gas are
separaled. The oil is pumped lo Ihe surface for marketing. After Ihe oil shale has
been relorled, residual carbon is left on Ihe spenl shale. The carbon is converted in-
lo a low-lo-medium BTU gas which will be used for on-sile eleclrical power genera-
tion. A simplified flow diagram is shown in Figure 7-17.
After Ihe shale in Ihe relort is cooled, soda ash and alumina are leached from Ihe
slope by spraying waler over Ihe lop of Ihe relorled shale and collecting Ihis waler
as pregnanl liquor at Ihe base. This can be done in more lhan one slope
simultaneously in a countercurrenl process. The pregnanl liquor is then pumped lo
the surface for recovery of Ihe alumina and soda ash.
314
-------
prillholM for •xplotivat
'and air injection
^X>^,r^.. «7..ffr&.* ^-x,.v, v;y,S. M/fr •;.;»;
Air & Propane
Injection from Surface
Bulking to Within
1 or 2 Feet of
Predicted Top
3,000^ to 4.000
[j Tons of Broken
(Oil Shale at '
"".15-25% Voids
' * •
:«
-------
CLARIFIED
WATER FROM
COLORADO
RIVER
EXHAUST GAS TO
STACK 1 MINE
INLET AIR
HEATERS
ELECTRIC POWER
TO GRID
BOILER FEED
WATER
TREATMENT
AMMONIA
SCRUBBER
t-
ss
Si
1|
a
OIL-WATER-GAS
SEPARATORS
EQUALIZATION
BASIN
Figure 7-15. Flow diagram of Oxy MIS plant.
-------
TABLE 7-20. OXY LOGAN WASH RETORTS 7 & 8 AIR EMISSIONS RATES
kg/hr (Ib/hr)
Location
Retort stack
Other sources3
Total
Total tonnes/year
(tons/year)15
S02
nil
13.9
13.9
80
(31)
(31)
(90)
H2S
169
nil
nil
986
.2 (376)
.4(1,096)
NOX
nil
23,
23,
135
.4 (52)
.4 (52)
(150)
HC
69.3
3.2
70.7
410.4
(154)
(7)
(157)
(456)
Particulates
nil
3.2 (7)
16.2 (18)
CO
1,638
.9
1,638:9
9,561.7
(3,640)
(2)
(3,642)
(10,613)
a Includes boilers, heater-treaters, hot water circulators, and mine vent,
k Based on 8 months of operation.
-------
TABLE 7-21. COMPOSITION OF MIS RETORT GAS"
Constituent
Total
Raw Retort Gas Cooled 8- Scrubbed Gas
MWt
Mass % Volume % Mass % Volume %
N2
C02
CO
H2
CH,
C2'S
C3'S
C4+
02
H2S
NH3
H20
28
44
28
2
16
29
43
60
32
34
17
18
43.930
38.153
0.759
0.298
0.650
0.315
0.232
0.618
0.086
0.184
0.369
14.405
44.699
24.704
0.772
4.246
1.158
0.309
0.154
0.309
0.077
0.154
0.618
22.800
51.244
40.471
0.885
0.348
0.758
0.267
0.271
0.721
0.100
0.201
-
4.633
55.338
27.865
0.958
5.271
1.763
0.383
0.191
0.364
0.095
0.179
—
7.594
100.
100.
100.
100.
Hb (dry basis)
C (dry basis)
MWt
0.835
14.245
28.49
0.796
13.76
30.29
Gas rate, wet, 103 Ib/hr: 6,366
dry, 103 Ig/hr: 5,449
5,482C
5,229
a Source: Reference 6.
b Not including hydrogen in the water vapor an
0 About 46 x 3D3 Ib/hr C02 are removed in gas treatment.
Geokinetics Horizontal In Situ Process
Geokinetics has dubbed its process LOFRECO, an acronym for "Low Front.
End Cost." Figure 7-18 depicts a schematic of the LOFRECO retort. Rubblization
is achieved by detonating explosives within a pattern of blastholes, whereupon the
overburden is lifted. The bottom of the retort is sloped to provide drainage into a
sump from which product shale oil is pumped. Air injection holes and offgas holes
are drilled at opposite ends of the rubblized zone. The oil shale is ignited at the air
injection wells, and air is injected to establish and maintain a burning front that oc-
cupies the full thickness of the fragmented zone. As the front moves towards the
offgas wells, oil shale ahead of the front is pyrolized and product oil drains to the
sloping bottom of the retort to the production wells. Residual coke in the spent
shale provides fuel for the burn front, the progress of which is monitored by ther-
mocouples set in wells.
318
-------
TABLE 7-22. TYPICAL ANALYSIS OF OXY RETORT 6
PROCESS WATER8
Parameter
mg/l
Total Alkalinity (mg/l as CaC03)
Carbonate, (mg/l as CaC03)
Bicarbonate, (mg/l as CaC03)
Total Dissolved Solids
Total Suspended Solids
Sulfate
Chloride
Fluoride
Phenol
Nitrate
Oil & Grease
Silica
Sodium
Potassium
Arsenic
Iron
Magnesium
Manganese
Calcium
Boron
Vanadium
Copper
Molybdenum
Lithium
Zinc
Aluminum
Barium
Strontium
Lead
Nickel
Cadmium
Ammonia, as N
Sulfite
2/15/79
8,000
1,500
6,500
11,200
170
970
110
33
48
460
280
39
3,400
59
0.44
< 0.5
3
< 0.02
5
5
< 0.1
< 0.02
0.06
2
0.02
< 0.1
2
2
< 0.02
< 0.02
< 0.02
1,000
180
a Source: Reference 13.
319
-------
DOWN-HOLE
BURNERS
ESCAPE
SHAFT
EXHAUST SHAFT
HERGET SHAFT
C' LEVEL
INSTR
RAISE
SUMP
Figure 7-16. RBOSC Modular Development Phase Mine diagram.
Equity BX In Situ Process
The Equity BX Process involves the injection of superheated steam into the
leached zone to retort oil shale in situ. Figure 7-19 is a flow diagram detailing the
basic elements of project equipment and instrumentation. The operating sequence
is as follows: water is produced from the leached zone and stored in the water
storage pit until it can be processed in the water treatment plants. After treatment,
water is fed to two steam generators capable of producing dry steam at 112 kg/cm2
(1,600 psig) and 318 °C (605 °F). These two streams of dry steam are then fed to the
superheater where the steam is superheated to 539 °C (1,000°F) at 105 kg/cm2
(1,500 psig). From the superheater, the steam is distributed to eight injection wells,
the quantity going to each being proportionately controlled by automatic control
valves. The steam is injected into the injection wells through insulated steel tubing
which is suspended in steel casing perforated at the top and bottom of the leached
zone. After the steam enters the leached zone, it gives up its heat and is produced as
water accompanied by retorted oil and gas at production wells.
320
-------
REIO8T .
(KtAT
REIORT 2
mcovcnr}
COlO RECYCLE GAS
S1EAM 1 AIK ;
ARM fitCVCtE GAS
Figure 7-17. Multi Mineral Integrated in situ process.
-------
PLAN
/
^
x
$'
^\
\ ^^
) AIR INJECTION
xX -^ WELLS
VIEW COMBUSTION GAS
EXHAUST WELLS
- k y
^
X°M
OIL PRODUCTION , /
WELLS f\
\ A
\ \ V)
PRE-BLAST SURFACE
AIR IN
SECTION
^SJJRFACE_UP(jFT_jr
OVERBURDEN
•\ OXr5^^ ^^r?
|i,oX .....^-^^^^ .>£
COMBUSTION
rtto —*-
-------
STEAM
GENERATOR
STEAM
SUPERHEATER
INJECTION PRODUCTION
WELLS WELLS
—O--OH
r
GAS TO
FLARE
GAS-LIQUID
SEPARATOR
HEATER-
TREATER
OIL TO
STORAGE
"a" FUEL
SUPPLY
BOILER FEED WATER
PRODUCED WATER
EXCESS WATER TO
DISPOSAL WELLS
Figure 7-19. Equity Oil/DOE BX in situ shale project flow diagram.
-------
TABLE 7-23. RIO BLANCO MDP ESTIMATED EMISSIONS8
kg/hr (Ib/hr)
Source Paniculate SO2
1. Thermal oxidizer scrubber 4.99(11.0) 75.80(167.1)
2.
3.
Steam boiler
Shaft construction
a. Mine . vent
b. Vehicular movement
c. Storage tank
d. ROM ore handling
Total
0.32 (0.7)
0.73 (1.6)
2.45 (5.4)
— —
2.76 (9.1)
12.61 (27.8)
7.53 (16.6)
— —
— —
— —
— —
83.33 (183.7)
a Source: Reference 14.
Each production well is equipped with a "gas lift" system to assist in producing
the production wells, the product stream goes through a free water knockout and a
heater treater to separate oil, gas, and water. Water is returned to the water storage
pit for reuse, oil is stored, and gas is recovered for use as steam-generator fuel gas.
REFERENCES
1. Baughman, G. L. Synthetic Fuels Data Handbook. 2nd ed. Cameron Engineers, Inc.,
Denver, Colorado, 1978.
2. EPA. Prevention of Significant Deterioration of Air Quality, Proposed Conditional
Permit to Commence Construction and Operate for the Colony Development Opera-
tion, Garfield County, Colorado, April 1979.
3. Proposed Development of Oil Shale Resources by the Colony Development Operation in
Colorado. Final Environmental Statement. Bureau of Land Management, U. S. Depart-
ment of the Interior, Washington, D.C., 1977.
4. Nevens, T. D., W. J. Culbertson, and R. Hollingshead. Disposal and Uses of Oil Shale
Ash. Interim Report No. 1, USBM Project SWD-8, University of Denver, Denver
Research Institute, Denver, Colorado, 1961.
5. TRW/DRI. Sampling and Analysis Research Program at the Paraho Shale Oil
Demonstration Plant. U.S. Environmental Protection Agency, Cincinnati, Ohio, 1978.
6. Detailed Development Plan for Federal Lease Tracts U-a and U-b, White River Shale
Project, Vernal, Utah, 1976.
7. DRI. Predicted Costs of Environmental Controls for a Commercial Oil Shale Industry,
prepared for DOE, Denver Research Institute, Denver, Colorado, July 1979.
8. Duir, J. H., R. F. Deering, and H. R. Jackson. Continuous Upflow Retort Improves
Shale Processing. Hydrocarbon Processing, May 1977.
9. U. S. Department of the Interior. Draft EIS, Proposed Superior Oil Company Land Ex-
change and Oil Shale Resource Development, July 1979.
10. TRW/DRI. An Engineering Report on the Lurgi Retorting Process for Oil Shale. U.S.
Environmental Protection Agency, Cincinnati, Ohio, 1977.
11. Feldkirchner, H. L. et al. The IGT HYTORT Process For Hydrogen Retorting of
Devonian Oil Shales, Presented at Sixth National Conference on Energy and the En-
vironment, May 21 - 24, 1979.
12. Institute of Gas Technology. Environmental Aspects of Eastern Oil Shale Development.
IGT, Chicago, Illinois, March 1978.
13. Occidental Oil Shale, Inc. Occidental Vertical Modified In Situ Process for the Recovery
of Oil From Oil Shale, Final Report, November 1979.
14. EPA. Prevention of Significant Deterioration of Air Quality, Conditional Permit to
Commence Construction and Operate. Rio Blanco Oil Shale Project, Rio Blanco, Col-
orado, December 1977.
324
ft U.S. GOVERNMENT PRINTING OFFICE: 1981—757-064/0226
------- |