BLM Mission Statement

It is the mission of the Bureau of Land Management to sustain the health, diversity, and 

productivity of the public lands for the use and enjoyment of present and future generations.

BLM/WO/GI-12/013+3000

DOI No. FES 12-41
Final OSTS PEIS

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DOCUMENT CONTENTS

VOLUME 1

Executive Summary

Chapter 1: Introduction

Chapter 2: Descriptions of Alternatives

Chapter 3: Affected Environment

VOLUME 2

Chapter 4: Effects of Oil Shale Technologies

Chapter 5: Effects of Tar Sands Technologies

VOLUME 3

Chapter 6: Impact Assessment for Oil Shale and Tar Sands Alternatives

VOLUME 4

Chapter 7: Consultation and Coordination

Chapter 8: List of Preparers

Chapter 9: Glossary

Appendix A: Oil Shale Development Background and Technology Overview

Appendix B: Tar Sands Development Background and Technology Overview

Appendix C: Proposed Land Use Plan Amendments Associated with Alternatives 2, 3, and 4

for Oil Shale and Tar Sands

Appendix D: Federal, State, and County Regulatory Requirements Potentially Applicable 

to Oil Shale and Tar Sands Development Projects

Appendix E: Threatened and Endangered Species within the Oil Shale and Tar Sands 

Study Area

Appendix F: Proposed Conservation Measures for Oil Shale and Tar Sands Leasing and 

Development

Appendix G: Socioeconomic and Environmental Justice Analysis Methodologies

Appendix H: Approach Used for Interviews of Selected Residents in the Oil Shale and Tar 

Sands Study Area Considered in the 2008 Oil Shale and Tar Sands Programmatic 

Environmental Impact Statement

Appendix I: Instream Flow Water Rights in the Piceance Basin, Colorado

Appendix J: Summary of Public Scoping Comments for the Programmatic Environmental 

Impact Statement and Possible Land Use Plan Amendments for Allocation of Oil 

Shale and Tar Sands Resources on Lands Administered by the Bureau of Land 

Management in Colorado, Utah, and Wyoming
Final OSTS PEIS

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DOCUMENT CONTENTS (Cont.)

VOLUME 5

Appendix K: Greater Sage-Grouse Instructional Memoranda, Conservation Measures, and Core 

Area Protection Strategies

Appendix L: Government-to-Government and National Historic Preservation Act Section 106

Consultations

Appendix M: Cooperating Agency and U.S. Environmental Protection Agency Letters

Comment Response Document
Final OSTS PEIS

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VOLUME 4 CONTENTS

NOTATION.............................................................................................................................. ix

ENGLISH/METRIC AND METRIC/ENGLISH EQUIVALENTS ........................................ xvi

7 CONSULTATION AND COORDINATION ................................................................. 7-1

7.1 Public Involvement ................................................................................................. 7-1

7.2 Government-to-Government Consultation ............................................................. 7-2

7.3 Coordination of BLM State and Field Offices........................................................ 7-6

7.4 Agency Consultation and Coordination.................................................................. 7-6

7.5 Explanation of the Public Protest Process for the Proposed Land Use Plan 

Amendments........................................................................................................... 7-8

7.6 Endangered Species Act Section 7 Requirements.................................................. 7-9

7.7 National Historic Preservation Act Section 106 Requirements.............................. 7-12

7.8 References............................................................................................................... 7-13

8 LIST OF PREPARERS ................................................................................................... 8-1

9 GLOSSARY .................................................................................................................... 9-1

APPENDIX A: OIL SHALE DEVELOPMENT BACKGROUND AND 

TECHNOLOGY OVERVIEW................................................................... A-1

APPENDIX B: TAR SANDS DEVELOPMENT BACKGROUND AND

TECHNOLOGY OVERVIEW................................................................... B-1

APPENDIX C: PROPOSED LAND USE PLAN AMENDMENTS 

ASSOCIATED WITH ALTERNATIVES 2, 3, AND 4 FOR 

OIL SHALE AND TAR SANDS ............................................................... C-1

APPENDIX D: FEDERAL, STATE, AND COUNTY REGULATORY 

REQUIREMENTS POTENTIALLY APPLICABLE TO OIL SHALE

AND TAR SANDS DEVELOPMENT PROJECTS .................................. D-1

APPENDIX E: THREATENED, ENDANGERED, AND SENSITIVE SPECIES

WITHIN THE OIL SHALE AND TAR SANDS STUDY AREA............. E-1

APPENDIX F: PROPOSED CONSERVATION MEASURES FOR OIL SHALE 

AND TAR SANDS LEASING AND DEVELOPMENT .......................... F-1

APPENDIX G: SOCIOECONOMIC AND ENVIRONMENTAL JUSTICE 

ANALYSIS METHODOLOGIES.............................................................. G-1
Final OSTS PEIS 

iv 

CONTENTS (Cont.) 

APPENDIX H: APPROACH USED FOR INTERVIEWS OF SELECTED 

 RESIDENTS IN THE OIL SHALE AND TAR SANDS STUDY 

 AREA CONSIDERED IN THE 2008 OIL SHALE AND TAR 

 SANDS PROGRAMMATIC ENVIRONMENTAL IMPACT 

 STATEMENT ............................................................................................. H-1 

APPENDIX I: INSTREAM FLOW WATER RIGHTS IN THE PICEANCE 

 BASIN, COLORADO ................................................................................ I-1

APPENDIX J: SUMMARY OF PUBLIC SCOPING COMMENTS FOR THE 

 PROGRAMMATIC ENVIRONMENTAL IMPACT STATEMENT 

 AND POSSIBLE LAND USE PLAN AMENDMENTS FOR 

 ALLOCATION OF OIL SHALE AND TAR SANDS RESOURCES 

 ON LANDS ADMINISTERED BY THE BUREAU OF LAND 

 MANAGEMENT IN COLORADO, UTAH, AND WYOMING .............. J-1

FIGURES 

A-1 Green River Formation Basins in Colorado, Utah, and Wyoming; Most 

 Geologically Prospective Oil Shale Resources; Areas Where the Overburden 

 above the Oil Shale Resources is ≤500 ft ............................................................... A-5 

A-2 Generalized Stratigraphic Section of the Parachute Creek Member of the 

 Green River Formation in the Uinta Basin, Utah ................................................... A-8 

A-3 ATP System Flow Diagram Processor ................................................................... A-38 

A-4 Pictorial Representation of ATP Processor ............................................................. A-38 

A-5 Conceptual Design of the Occidental Oil Shale, Inc., MIS Retorting Process ....... A-44 

A-6 Conceptual View of the Downward Movement of the Heat Front through the 

 Formation in the Occidental Oil Shale, Inc., Vertical In Situ Retort ...................... A-44 

A-7 Cross Section of Shell’s Patented ICP Technology ................................................ A-53 

A-8 Shell’s Field Research in Rio Blanco County, Colorado ........................................ A-54 

A-9 Locations of Eight Current and One Proposed RD&D Tracts and Associated 

 Preference Right Lease Areas ................................................................................. A-57 
Final OSTS PEIS 

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FIGURES (Cont.) 

B-1 Special Tar Sand Areas in Utah .............................................................................. B-6

B-2 Generalized Stratigraphy of the Areas in Utah Where the STSAs Are Present ..... B-7

B-3 Simplified Diagrams of Forward and Reverse Combustion Processes ................. B-25

B-4 Simplified Steam Drive Process ............................................................................. B-28

B-5 Simplified Diagram of Hot Water Recovery Process ............................................. B-32

G-1 The Cycle of Social Adjustment to “Boom” and “Bust” ........................................ G-8

J-1 Most Geologically Prospective Oil Shale Resources within the Green River 

 Formation Basins in Colorado, Utah, and Wyoming .............................................. J-2 

J-2 Special Tar Sand Areas in Utah .............................................................................. J-3 

TABLES 

7.2-1 Government-to-Government Consultation Summary ............................................. 7-3

A-1 Estimated In-Place Oil Shale Resources in the Southeastern Portion of the 

 Uinta Basin Based on a Minimum Thickness of 15 ft and Various Expected 

 Yields ......................................................................................................................A-9

A-2 Estimated In-Place Oil Shale Resources in the Southeastern Portion of the 

 Uinta Basin Based on a Minimum Expected Yield of 25 gal/ton and a 

 Minimum Thickness of 25 ft ................................................................................... A-10

A-3 Estimated In-Place Oil Shale Resources in the Green River Basin Based on a 

 Minimum Expected Yield of 15 gal/ton and a Minimum Thickness of 15 ft ......... A-12

A-4 Estimated In-Place Oil Shale Resources in the Washakie Basin Based on a 

 Minimum Expected Yield of 15 gal/ton and a Minimum Thickness of 15 ft ......... A-13

A-5 Structural Properties of Compacted Paraho AGR Spent Shale .............................. A-49 

A-6 Summary of the Range of Leachate Characteristics of Simulated Spent Shale 

 from In Situ Retorting and from Three AGRs ........................................................ A-51
Final OSTS PEIS 

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TABLES (Cont.) 

A-7 Expected Characteristics of Leachates from Raw Shale Piles and Spent Shale 

 Disposal Piles from Various AGRs ........................................................................ A-52

A-8 Hazardous Materials and Wastes, Other Wastes, and Wastewater Associated 

 with the RD&D Projects ......................................................................................... A-58

A-9 Estimated Water Needs per Year for Chevron RD&D Site .................................... A-61

A-10 AMSO RD&D Project Air Emissions Summary .................................................... A-67

A-11 Anticipated Water Usage for the Proposed Shell RD&D Projects ......................... A-74

A-12 Phase I Estimated Emissions .................................................................................. A-82

A-13 Phase 2 Estimated Emissions .................................................................................. A-83

A-14 Phase 3 Estimated Emissions .................................................................................. A-84

A-15 Phase 2 Greenhouse Gas Emissions ....................................................................... A-85

A-16 Phase 3 Greenhouse Gas Emissions ....................................................................... A-86

B-1 Estimated Resources in Place in Utah Tar Sands Deposits .................................... B-8

B-2 Potential Impact-Producing Factors Associated with a Tar Sands Surface Mine 

 Operating at a Diatomaceous Earth Tar Sands Deposit .......................................... B-21

B-3 Potential Air Emissions from a Surface Mine Operating at a Sandstone-Based 

 Tar Sands Deposit ................................................................................................... B-22

B-4 Potential Impact-Producing Factors Associated with In Situ Combustion 

 Processes ................................................................................................................. B-27

B-5 Potential Impact-Producing Factors Associated with In Situ Steam Injection 

 Processes ................................................................................................................. B-31

B-6 Potential Impact-Producing Factors Associated with a Solvent Extraction 

 Facility ....................................................................................................................B-35

B-7 Potential Impact-Producing Factors Associated with a Surface Retort Facility ..... B-37

B-8 Potential Impact-Producing Factors Associated with Upgrading Facilities ........... B-39 
Final OSTS PEIS 

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TABLES (Cont.) 

C-1 Proposed Land Use Plan Amendments and Rationale Associated with 

 Alternatives 2 through 4 for Oil Shale .................................................................... C-5

C-2 Proposed Land Use Plan Amendments and Rationale Associated with 

 Alternatives 2 through 4 for Tar Sands ................................................................... C-17

D-1 Air Quality ..............................................................................................................D-5

D-2 Cultural Resources and Native Americans ............................................................. D-6

D-3 Energy Project Siting .............................................................................................. D-7

D-4 Floodplains and Wetlands ....................................................................................... D-8

D-5 Groundwater, Drinking Water, and Water Rights .................................................. D-9

D-6 Hazardous Materials ............................................................................................... D-10

D-7 Hazardous Waste and Polychlorinated Biphenyls .................................................. D-11

D-8 Land Use .................................................................................................................D-12

D-9 Noise ....................................................................................................................... D-14

D-10 Pesticides and Noxious Weeds ............................................................................... D-15

D-11 Solid Waste .............................................................................................................D-16

D-12 Source Water Protection ......................................................................................... D-17

D-13 Water Bodies and Wastewater ................................................................................ D-18

D-14 Wildlife and Plants .................................................................................................. D-19

D-15 Visual Resources ..................................................................................................... D-22

D-16 Federal and State Leasing and Permitting Requirements ....................................... D-21

D-17 Cultural Resource Laws and Regulations ............................................................... D-25

D-18 BLM Guidance Regarding Cultural Resource Management .................................. D-27

D-19 Colorado Limits on Maximum Permissible Noise Levels ...................................... D-27 
Final OSTS PEIS

viii

TABLES (Cont.)

E-1 Federally Listed and State-Listed Threatened, Endangered, Candidate

Species, Species of Special Concern, and BLM-Designated Sensitive

Species That Occur in the Study Area .................................................................... E-3

G-1 Input Data for Tar Sands Direct Employment Estimates........................................ G-4

I-1 Colorado Water Conservation Board Instream Flow Tabulation—Water 

Division 6, White River Basin, Streams in the Oil Shale Study Area 

Protected by Instream Flow Water Rights, April 5, 2012....................................... I-3
Final OSTS PEIS

ix

NOTATION

The following is a list of acronyms and abbreviations, chemical names, and units of 

measure used in this document. Some acronyms used only in tables may be defined only in those 

tables.

GENERAL ACRONYMS AND ABBREVIATIONS

ACEC Area of Critical Environmental Concern

AGR aboveground retort

AIRFA American Indian Religious Freedom Act

AMSO American Shale Oil, LLC

ANFO ammonium nitrate and fuel oil

APE Area of Potential Effects

API American Petroleum Institute 

APLIC Avian Power Line Interaction Committee

APP Avian Protection Plan

AQRV air quality–related value

ARCO Atlantic Richfield Company

ATP Alberta Taciuk Process

ATSDR Agency for Toxic Substances and Disease Registry

AWEA American Wind Energy Association

AZGFD Arizona Game and Fish Department

BA biological assessment

BCD barrels per calendar day

BLM Bureau of Land Management

BMP best management practice

BO biological opinion

BOR U.S. Bureau of Reclamation

BPA Bonneville Power Administration

BSD barrels per stream day

BTEX benzene, toluene, ethylbenzene, and xylenes

CAA Clean Air Act

CAPP Canadian Association of Petroleum Producers

CARB California Air Resources Board

CASTNET Clean Air Status and Trends Network

CBOSC Cathedral Bluffs Oil Shale Company

CCRTM Conduction, Convection, and Reflux

CCW coal combustion waste

CDC Centers for Disease Control and Prevention

CDOT Colorado Department of Transportation

CDOW Colorado Division of Wildlife (now Colorado Parks and Wildlife)
Final OSTS PEIS

x

CDPHE Colorado Department of Public Health and Environment

CEQ Council on Environmental Quality

CFR Code of Federal Regulations

CHAT Critical Habitat Assessment Tool

CHL combined hydrocarbon lease

CIRA Cooperative Institute for Research in the Atmosphere

CNHP Colorado Natural Heritage Program

COGCC Colorado Oil and Gas Conservation Commission

CPC Center for Plant Conservation

CPW Colorado Parks and Wildlife (formerly Colorado Division of Wildlife)

CRBSCF Colorado River Basin Salinity Control Forum

CRD Comment Response Document

CRSCP Colorado River Salinity Control Program

CRWQIP Colorado River Water Quality Improvement Program

CSS cyclic steam stimulation

CSU Controlled Surface Use

CWA Clean Water Act

CWCB Colorado Water Conservation Board

CWS Canadian Wildlife Service

DoD U.S. Department of Defense

DOE U.S. Department of Energy

DOI U.S. Department of the Interior

DOL U.S. Department of Labor

DOT U.S. Department of Transportation

DRMS Division of Reclamation Mining & Safety (Colorado)

DRUA Dispersed Recreation Use Area

EA environmental assessment

EGL EGL Resources, Inc.

EIA Energy Information Administration

E-ICP bare electrode in situ conversion process

EIS environmental impact statement

EMF electric and magnetic field

E.O. Executive Order

EOR enhanced oil recovery

EPA U.S. Environmental Protection Agency

EPRI Electric Power Research Institute

EQIP Environmental Quality Incentives Program

ESA Endangered Species Act of 1973

FAA Federal Aviation Administration

FLPMA Federal Land Policy and Management Act of 1976

FONSI Finding of No Significant Impact

FR Federal Register
Final OSTS PEIS

xi

FTE full-time equivalent

FY fiscal year

GCR gas combustion retort

GHG greenhouse gas

GIS geographic information system

GPO Government Printing Office

GSENM Grand Staircase–Escalante National Monument

HAP hazardous air pollutant

HAZCOM hazard communication

HFC hydrofluorcarbon

HMA Herd Management Area

HMMH Harris Miller Miller & Hanson, Inc.

I-70 Interstate 70

IARC International Agency for Research on Cancer

ICP in situ conversion process

IEC International Electrochemical Commission

IM Instructional Memorandum

IPPC Intergovernmental Panel on Climate Change

ISA Instant Study Area

ISWS Illinois State Water Survey

IUCNNR International Union for Conservation of Nature and Natural Resources

JMH CAP Jack Morrow Hills Coordinated Activity Plan

KOP key observation point

KSLA Known Sodium Leasing Area

LAU Lynx Analysis Unit

Ldn day-night average sound level

Leq equivalent sound pressure level

LETC Laramie Energy Technology Center

LM Office of Legacy Management (DOE)

LPG liquefied petroleum gas

LWC lands having wilderness characteristics

M&I municipal and industrial

MFP Management Framework Plan

MIG, Inc. Minnesota IMPLAN Group, Inc.

MIS modified in situ recovery

MLA Mineral Leasing Act

MMC Multi Minerals Corporation

MMTA Mechanically Mineable Trona Area

MOU Memorandum of Understanding
Final OSTS PEIS

xii

MPCA Minnesota Pollution Control Agency

MSDS Material Safety Data Sheet

MSHA Mine Safety and Health Administration

MSL mean sea level

MTR military training route

NAAQS National Ambient Air Quality Standards

NADP National Atmospheric Deposition Program

NAGPRA Native American Graves Protection and Repatriation Act

NCA National Conservation Area

NCDC National Climate Data Center

NEC National Electric Code

NEPA National Environmental Policy Act of 1969

NESHAP National Emission Standards for Hazardous Air Pollutants

NFS National Forest Service

NHPA National Historic Preservation Act of 1966

NLCS National Landscape Conservation System

NMFS National Marine Fisheries Service

NNHP Nevada Natural Heritage Program

NOA Notice of Availability

NOI Notice of Intent

NORM naturally occurring radioactive materials

NOSR Naval Oil Shale Reserves

NPDES National Pollutant Discharge Elimination System

NPS National Park Service

NRA National Recreation Area

NRHP National Register of Historic Places

NSC National Safety Council

NSO No Surface Occupancy

NTSA National Trails System Act

NTT National Technical Team

NWCC National Wind Coordinating Committee 

NWR National Wildlife Refuge

OHV off-highway vehicle 

OOSI Occidental Oil Shale, Inc.

OPEC Organization of Petroleum Exporting Countries

OSEC Oil Shale Exploration Company

OSEW/SPP Oil Sands Expert Workgroup/Security and Prosperity Partnership

OSHA Occupational Safety and Health Administration

OSTS oil shale and tar sands

OTA Office of Technology Assessment

PA Programmatic Agreement

PADD Petroleum Administration for Defense District

PAH polycyclic aromatic hydrocarbon
Final OSTS PEIS

xiii

PCB polychlorinated biphenyl

PEIS programmatic environmental impact statement

PFC perfluorcarbons

PFYC Potential Fossil Yield Classification

PILT payment in lieu of taxes

P.L. Public Law

PM particulate matter

PM2.5 particulate matter with an aerodynamic diameter of 2.5 μm or less

PM10 particulate matter with an aerodynamic diameter of 10 μm or less

PPE personal protective equipment

PPH Preliminary Priority Habitat

PRLA preference right lease area

PSD Prevention of Significant Deterioration

R&D research and development

R&I relevance and importance

RBOSC Rio Blanco Oil Shale Company

RCRA Resource Conservation and Recovery Act of 1976

RD&D research, development, and demonstration

RF radio frequency

RFDS reasonably foreseeable development scenario

RMP Resource Management Plan

ROD Record of Decision

ROI region of influence

ROS Recreation Opportunity Spectrum

ROW right-of-way

SAGD steam-assisted gravity drainage

SAMHSA Substance Abuse and Mental Health Services Administration

SDWA Safe Drinking Water Act of 1974

SFC Synthetic Fuels Corporation

SHPO State Historic Preservation Office(r)

SIP State Implementation Plan

SMA Special Management Area

SMP suggested management practice

SPR Strategic Petroleum Reserve

SRMA Special Recreation Management Area

SSI self-supplied industry

STSA Special Tar Sand Area

SWCA SWCA, Inc., Environmental Consultants

SWPPP Stormwater Pollution Prevention Plan

SWWRC States West Water Resources Corporation

TDS total dissolved solids

THAI toe to head air injection

TIS true in situ recovery
Final OSTS PEIS

xiv

TL timing limitation

TMDL Total Maximum Daily Load

TOSCO The Oil Shale Corporation

TSCA Toxic Substances Control Act of 1976

TSDF treatment, storage, and disposal facility

UDEQ Utah Department of Environmental Quality

UDNR Utah Department of Natural Resources

UDWR Utah Division of Wildlife Resources

UGS Utah Geological Survey

UIC underground injection control

ULP Uranium Leasing Program

USACE U.S. Army Corps of Engineers

USC United States Code

USDA U.S. Department of Agriculture

USFS U.S. Forest Service

USFWS U.S. Fish and Wildlife Service

USGCRP U.S. Global Change Research Program

USGS U.S. Geological Survey 

VCRS Visual Contrast Rating System

VOC volatile organic compound

VRI Visual Resource Inventory

VRM Visual Resource Management

WDEQ Wyoming Department of Environmental Quality

WEQC Wyoming Environmental Quality Council

WGFD Wyoming Game and Fish Department

WRAP Western Regional Air Partnership

WRCC Western Regional Climate Center

WRI World Resources Institute

WRSOC White River Shale Oil Corporation

WSA Wilderness Study Area

WSR Wild and Scenic River

WTGS wind turbine generator system

WYCRO Wyoming Cultural Records Office

WYNDD Wyoming Natural Diversity Database

CHEMICALS

CH4 methane

CO carbon monoxide

CO2 carbon dioxide

CO2e carbon dioxide equivalent

H2S hydrogen sulfide

NH3 ammonia

NO2 nitrogen dioxide
Final OSTS PEIS

xv

N2O nitrous oxide

NOx nitrogen oxides

O3 ozone

Pb lead

SF6 sulfur hexafluoride

SO2 sulfur dioxide

SOx sulfur oxides

UNITS OF MEASURE

ac-ft acre foot (feet)

bbl barrel(s)

Btu British thermal unit(s)

C degree(s) Celsius

cfs cubic foot (feet) per second

cm centimeter(s) 

dB decibel(s) 

dBA A-weighted decibel(s) 

F degree(s) Fahrenheit

ft foot (feet)

ft3 cubic foot (feet)

g gram(s)

gal gallon(s)

GJ gigajoule(s)

gpd gallon(s) per day

gpm gallon(s) per minute

GW gigawatt(s)

GWh gigawatt hour(s)

h hour(s)

ha hectare(s)

hp horsepower

Hz hertz

in. inch(es)

K degree(s) Kelvin

kcal kilocalorie(s)

kg kilogram(s)

km kilometer(s)

kPa kilopascal(s)

kV kilovolt(s)

kWh kilowatt-hour(s)

L liter(s)

lb pound(s)

m meter(s)

m2 square meter(s)

m3 cubic meter(s)

mg milligram(s)

mi mile(s)

mi2 square mile(s)

mJ megajoule(s)

mm millimeter(s)

MMBtu million Btus

mph mile(s) per hour

MW megawatt(s)

ppb part(s) per billion

ppm part(s) per million

ppmv part(s) per million by volume

psi pound(s) per square inch

rpm rotation(s) per minute

s second(s)

scf standard cubic foot (feet)

yd2 square yard(s)

yd3 cubic yard(s)

yr year(s)

μm micrometer(s)
Final OSTS PEIS

xvi

ENGLISH/METRIC AND METRIC/ENGLISH EQUIVALENTSa

The following table lists the appropriate equivalents for English and metric units.

Multiply By To Obtain

English/Metric Equivalents

 acres 0.4047 hectares (ha)

 cubic feet (ft3) 0.02832 cubic meters (m3)

 cubic yards (yd3) 0.7646 cubic meters (m3)

 degrees Fahrenheit (oF) –32 0.5555 degrees Celsius (oC)

 feet (ft) 0.3048 meters (m)

 gallons (gal) 3.785 liters (L)

 gallons (gal) 0.003785 cubic meters (m3)

 inches (in.) 2.540 centimeters (cm)

 miles (mi) 1.609 kilometers (km)

 miles per hour (mph) 1.609 kilometers per hour (kph)

 pounds (lb) 0.4536 kilograms (kg)

 short tons (tons) 907.2 kilograms (kg)

 short tons (tons) 0.9072 metric tons (t)

 square feet (ft2) 0.09290 square meters (m2)

 square yards (yd2) 0.8361 square meters (m2)

 square miles (mi2) 2.590 square kilometers (km2)

 yards (yd) 0.9144 meters (m)

Metric/English Equivalents

 centimeters (cm) 0.3937 inches (in.)

 cubic meters (m3) 35.31 cubic feet (ft3)

 cubic meters (m3) 1.308 cubic yards (yd3)

 cubic meters (m3) 264.2 gallons (gal)

 degrees Celsius (oC) +17.78 1.8 degrees Fahrenheit (oF)

 hectares (ha) 2.471 acres

 kilograms (kg) 2.205 pounds (lb)

 kilograms (kg) 0.001102 short tons (tons)

 kilometers (km) 0.6214 miles (mi)

 kilometers per hour (kph) 0.6214 miles per hour (mph)

 liters (L) 0.2642 gallons (gal)

 meters (m) 3.281 feet (ft)

 meters (m) 1.094 yards (yd)

 metric tons (t) 1.102 short tons (tons)

 square kilometers (km2) 0.3861 square miles (mi2)

 square meters (m2) 10.76 square feet (ft2)

 square meters (m2) 1.196 square yards (yd2)

a

In general in this PEIS, only English units are presented. However, 

where reference sources provided both English and metric units, both 

values are presented in the order in which they are given in the source. 

Where reference sources provided only metric units, only those units 

are presented.
Final OSTS PEIS 7-1 

7 CONSULTATION AND COORDINATION 

7.1 PUBLIC INVOLVEMENT 

 An NOI to prepare a PEIS and possible land use plan amendments for allocation of oil 

shale and tar sands resources on lands administered by the BLM in Colorado, Utah, and 

Wyoming was published in the Federal Register on April 14, 2011 (BLM 2011). The NOI 

articulated a preliminary purpose and need for the proposed action of amending land use plans; 

identified planning criteria; initiated the public scoping process; and invited interested members 

of the public to provide comments on the scope and objectives of the PEIS, including 

identification of issues and alternatives that should be considered in the PEIS analyses. 

 During the scoping period, the BLM conducted public meetings in April and May of 

2011, in Salt Lake City, Vernal, and Price, Utah; Rock Springs and Cheyenne, Wyoming; and 

Rifle and Denver, Colorado. Approximately 28,800 people participated in the scoping process by 

attending public meetings and/or submitting comments. The BLM published a scoping report in 

October 2011, summarizing and categorizing issues, concerns, and comments, and considered 

them in developing the alternatives in this 2012 PEIS. A summary of scoping comments is 

provided in Section J.3 of Appendix J of this document. 

 The BLM published a Notice of Availability for the Draft Programmatic Environmental 

Impact Statement and Possible Land Use Plan Amendments for Allocation of Oil Shale and Tar 

Sands Resources on Lands Administered by the Bureau of Land Management in Colorado, Utah, 

and Wyoming (BLM 2012a) on February 3, 2012, and announced a 90-day public comment 

period that closed on May 4, 2012. Open house meetings were held during March 2012 to 

provide additional information on the Draft PEIS. Approximately 160,000 comment letters were 

received, about 600 of which contained substantive comments, and roughly 160,000 appeared to 

be similar or identical to one another (i.e., form letters). Comments on the Draft PEIS received 

from the public, cooperating agencies, other federal agencies, and from internal BLM review 

were considered and incorporated, as appropriate, into this Proposed RMP Amendments/Final 

PEIS. Issues identified in the comments include air quality, climate change, water quality and 

quantity, socioeconomic concerns, wildlife concerns, and cultural resources concerns, as well as 

concerns related to the agency’s compliance with FLPMA, NEPA, and the Energy Policy Act of 

2005. These issues are summarized and the resolution of them described in the Comment 

Response Document in Volume 5 of this Final PEIS. 

 As a result of public comments and upon further review, corrections/revisions were made 

to the alternatives and changes were made from what was presented as the Preferred Alternative 

in the Draft PEIS. These changes have resulted in a Proposed Plan Amendment that references 

new acreage figures. 
Final OSTS PEIS 7-2 

7.2 GOVERNMENT-TO-GOVERNMENT CONSULTATION 

 The BLM works on a government-to-government basis with federally recognized Indian 

tribes. As a part of the government’s “treaty and trust” responsibilities, the government-togovernment relationship was reaffirmed by the federal government on May 14, 1998, with 

E.O. 13084, and was strengthened on November 6, 2000, with E.O. 13175 (U.S. President 1998, 

2000). DOI recently issued the Department of the Interior Policy on Consultation with Indian 

Tribes (DOI 2011). The BLM coordinates and consults with tribal governments, native 

communities, and tribal individuals whose interests might be directly and substantially affected 

by activities on public lands. It strives to provide the Indian tribes with sufficient opportunities 

for productive participation in BLM planning and resource management decision making. In 

addition, Section 106 of the NHPA requires federal agencies to consult with Indian tribes on 

undertakings on tribal lands and on historic properties of significance to the tribes that may be 

affected by an undertaking (36 CFR 800.2 (c)(2)). BLM Manual 8120 (BLM 2004a) and 

Handbook H-8120-1 (BLM 2004b) provide guidance for Native American consultations. 

 The BLM developed a process to offer specific consultation opportunities to “directly 

and substantially affected” tribal entities, as required under the provisions of E.O. 13175 and to 

Indian tribes as defined under 36 CFR 800.2(c)(2). Beginning in July 2011, the three BLM State 

Directors contacted the 25 federally recognized tribes located in or with historical or cultural ties 

to the three-state study area. The letters sent by the BLM State Directors provided notification of 

the BLM’s intention to take a fresh look at the land use allocation decisions regarding the 

management of oil shale and tar sands resources made in 2008. The BLM has followed up with 

additional letters, e-mails, telephone calls, and meetings for tribes who have expressed a wish to 

continue government-to-government consultation. Once the Draft PEIS was completed 

(BLM 2012a), a second mailing was sent to all federally recognized tribes with interests in the 

area under consideration. Follow-up meetings and discussions occurred after the Draft PEIS was 

issued. Table 7.2-1 lists the tribes that were contacted by state and describes the status of the 

ongoing consultations with each tribe. 

 Eight tribes have responded by letter, e-mail, or telephone to communications from the 

BLM, or have met with local BLM personnel. Three tribes (the Southern Ute Indian Tribe, the 

Ute Mountain Ute Tribe, and the Ute Indian Tribe) have met with the BLM to discuss and field 

visit wickiup sites and cultural landscapes in the Yellow Creek area, Rio Blanco County, 

Colorado, and discuss their protection. The Ute Indian Tribe also discussed the leasing of split 

estate lands on their reservation (Section 3.10.2). Interaction with the Ute Indian Tribe is 

ongoing. Through the response form, two tribes (the Hopi and Eastern Shoshone) expressed an 

initial interest in meeting with the BLM to discuss the project. The Hopi did not respond to 

follow-up communications, and the Eastern Shoshone were unable to meet with the BLM. One 

Navajo Chapter (Navajo Mountain) requested additional information, which they received. The 

BLM followed up with all three tribes, providing information about the project. Two tribes (the 

Pueblo of Santa Clara and the Paiute Indian Tribe of Utah) have indicated through the Tribal 

Response Form that further consultation is not needed. The remaining 10 tribes (Kaibab Paiute 

Tribe, Northern Arapaho Tribe, Northwestern Band of the Shoshone Nation, Pueblo of Laguna, 

Pueblo of Nambe, Pueblo of Zia, Pueblo of Zuni, San Juan Southern Paiute Tribe, ShoshoneBannock Tribes, and White Mesa Band of Ute Mountain Ute Tribe) and 7 Navajo Chapters 
Final OSTS PEIS 7-3 

TABLE 7.2-1 Government-to-Government Consultation Summary 

Tribes Contacted for Consultation on the PEIS Status of Consultation Process 

 

Tribes with Ties to Colorado

 

Eastern Shoshone Tribe, Fort Washakie, WY The tribe initially expressed a desire to be a 

cooperating agency. They did not sign the 

required MOU. Invited to but did not participate 

in the field trip with the BLM to consult on 

wickiup sites and cultural landscapes in the 

Yellow Creek area, Rio Blanco County, 

Colorado. Consultation is ongoing. 

 

Southern Ute Indian Tribe, Ignacio, CO Invited to and participated in the field trip with 

the BLM to consult on wickiup sites and cultural 

landscapes in the Yellow Creek area, Rio Blanco 

County, Colorado. Follow-up consultation is 

ongoing. 

 

Ute Mountain Ute Tribe, Towoac, CO Met with the BLM for project overview. 

Requested that the BLM meet with the Ute 

Mountain Ute Tribe, the Southern Ute Tribe, the 

Ute Indian Tribe (Uintah and Ouray Reservation), 

and the Eastern Shoshone Tribe to field visit 

wickiup sites and cultural landscapes in the 

Yellow Creek area, Rio Blanco County, 

Colorado, and discuss their protection. Invited to 

and participated in the field trip with the BLM to 

consult on wickiup sites and cultural landscapes 

in the Yellow Creek area. Consultation is 

ongoing. 

 

Ute Indian Tribe (Uintah and Ouray Reseervation), 

Fort Duchesne, UT

Contacts continue regarding potential leasing for 

commercial oil shale and/or tar sands 

development on split estate lands located in the 

Hill Creek Extension of the Uinta and Ouray 

Reservation. Invited and participated in the field 

trip with the BLM to consult on wickiup sites and 

cultural landscapes in the Yellow Creek area, 

Rio Blanco County, Colorado. Consultation is 

ongoing. 

 

Tribes with Ties to Utah

Hopi Tribe, Kykotsmovi, AZ The tribe initially indicated it desires further 

contact regarding the EIS but has not responded 

to follow-up communications. Consultation 

opportunities will continue to be provided. 

 

Kaibab Paiute Tribe, Fredonia, AZ No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 
Final OSTS PEIS 7-4 

TABLE 7.2-1 (Cont.) 

Tribes Contacted for Consultation on the PEIS Status of Consultation Process 

 

Navajo Nation, Window Rock, AZ No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Navajo Nation, Aneth Chapter, Montezuma Creek, UT No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Navajo Nation, Dennehotso Chapter, Dennehotso, AZ No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Navajo Nation, Mexican Water Chapter, Teec Nos Pos, 

AZ 

No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Navajo Nation, Navajo Mountain Chapter, Tonalea, AZ The chapter requested further information, which 

was provided. Consultation opportunities will 

continue to be provided. 

 

Navajo Nation, Oljato Chapter, Monument Valley, UT No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Navajo Nation, Red Mesa Chapter, Montezuma Creek, 

UT 

No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Navajo Nation, Teec Nos Pos Chapter, Teec Nos Pos, AZ No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Northwestern Band of Shoshone Nation, Pocatello, ID No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Paiute Indian Tribe of Utah, Cedar City, UT The tribe has indicated that further consultation is 

not needed. 

 

Pueblo of Laguna, Laguna, NM No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Pueblo of Nambe, Santa Fe, NM No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 
Final OSTS PEIS 7-5 

TABLE 7.2-1 (Cont.) 

Tribes Contacted for Consultation on the PEIS Status of Consultation Process 

 

Pueblo of Santa Clara, Espanola, NM The tribe has indicated that further consultation is 

not needed. 

 

Pueblo of Zia, Zia Pueblo, NM No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Pueblo of Zuni, Zuni, NM No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

San Juan Southern Paiute Tribe, Tuba City, AZ No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Ute Indian Tribe (Uintah and Ouray Reservation), 

Fort Duchesne, UT 

Contacts continue regarding potential leasing for 

commercial oil shale and/or tar sands 

development on split estate lands located in the 

Hill Creek Extension of the Uinta and Ouray 

Reservation. Invited to and participated in the 

field trip with the BLM to consult on wickiup 

sites and cultural landscapes in the Yellow Creek 

area, Rio Blanco County, Colorado. Consultation 

is ongoing. 

 

White Mesa Band of the Ute Mountain Ute Tribe, 

Blanding, UT 

No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Tribes with Ties to Wyoming

Northern Arapaho Tribe, Fort Washakie, WY No response to letters and follow-up phone calls. 

Consultation opportunities will continue to be 

provided. 

 

Eastern Shoshone Tribe, Fort Washakie, WY The tribe initially expressed a desire to be a 

cooperating agency. They did not sign the 

required MOU. Invited to but did not participate 

in the field trip with the BLM to consult on 

wickiup sites and cultural landscapes in the 

Yellow Creek area, Rio Blanco County, 

Colorado. Consultation opportunities will 

continue to be provided. 

 
Final OSTS PEIS 7-6 

(Aneth, Dennehotso, Mexican Water, Oljato, Red Mesa, Teec Nos Pos, and Window Rock) have 

yet to respond to the BLM’s request for consultation. 

 The BLM will continue to provide consultation opportunities for interested tribes and will 

continue to keep all tribal entities informed about the NEPA process for the PEIS. In addition, 

the BLM will continue to implement government-to-government consultation on a case-by-case 

basis for site-specific oil shale and tar sands resource development projects (see Appendix L for 

copies of the correspondence). 

7.3 COORDINATION OF BLM STATE AND FIELD OFFICES 

 This PEIS is being prepared by the BLM to evaluate potential land use plan amendments 

for oil shale and tar sands resources on public lands in three states. The BLM Washington, D.C., 

Office has worked extensively with BLM state offices and multiple district and field offices 

throughout the course of this PEIS to ensure adequate coordination. BLM state office, district 

and field office representatives have worked directly with the BLM Washington, D.C., Office 

staff to share relevant information about the existing planning documents and decisions, the 

location and nature of natural and cultural resources within the study area, and other land uses 

within the study area. 

 In addition, the BLM Washington, D.C., Office Public Affairs Division has coordinated 

with Public Affairs Office staff from each of the state offices. Jointly, these staff members 

have been responsible for coordinating all public involvement activities related to the PEIS 

(e.g., public meetings, local public notifications, and advertisements). Coordination with BLM 

state, district, and field office staff continued throughout the preparation of the PEIS to ensure 

that the analysis adequately reflects state- and local-level concerns and issues regarding oil shale 

and tar sands resources development. 

7.4 AGENCY CONSULTATION AND COORDINATION 

 The BLM invited approximately 55 federal, tribal, state, and local government agencies 

to participate in preparation of the Oil Shale and Tar Sands PEIS as cooperating agencies. 

Fourteen agencies expressed an interest in participating as cooperating agencies, and MOUs 

between these agencies and the BLM were established. The following 14 agencies are 

participating as cooperating agencies on the PEIS: 

• NPS; 

• USFWS; 

• State of Colorado, Department of Natural Resources and Department of 

Public Health and the Environment; 

• State of Utah; 
Final OSTS PEIS 7-7 

• State of Wyoming; 

• Garfield County, Colorado; 

• City of Rifle, Colorado; 

• Carbon County, Utah; 

• Duchesne County, Utah; 

• Grand County, Utah; 

• Uintah County, Utah; 

• Lincoln County, Wyoming; 

• Sweetwater County, Wyoming; and 

• Coalition of Local Governments (Wyoming). 

 Interactions with the cooperating agencies have included notification of the opening of 

the scoping period; briefing on the draft alternatives; review of preliminary, internal drafts of the 

PEIS; and informal meetings and discussions. 

 As required under Section 106 of the NHPA of 1966, as amended, the BLM has initiated 

consultation with those parties identified in 36 CFR 800.2(c). These parties include the Colorado, 

Utah, and Wyoming SHPOs, the tribes listed in Section 7.3, and other parties with an interest in 

consulting under this authority regarding the proposed plan amendments discussed in Chapter 2 

and Appendix C. The BLM has also notified the public, in the NOI, that it will use and 

coordinate public participation opportunities offered and consistent with NEPA and land use 

planning process to assist the agency in satisfying public involvement requirements under 

Section 106 (36 CFR 800.2(d)). Consultation with these and other identified parties will be 

ongoing throughout this project review. (See Appendix L for copies of the correspondence.) 

 Section 202 of FLPMA, and BLM’s planning regulations, require that BLM land use 

plans, including amendments, be consistent with the planning of other federal departments and 

agencies, and of the states and local governments, to the extent practicable and consistent with 

the laws governing the administration of the public lands, including their purposes, policies, and 

programs. Appendix M presents an explanation of differences between the current proposed land 

use plan amendments and state and local plans in the study area. Appendix M also includes 

comment letters submitted by cooperating agencies on the January 2011 Draft PEIS, wherein 

issues related to these differences were raised. 

 In addition to coordination with each of the three states in preparation of the PEIS, prior 

to the approval of proposed plan amendments, the governor of each state will be given the 

opportunity to identify any inconsistencies between the proposed plan amendments and state or 
Final OSTS PEIS 7-8 

local plans and to provide recommendations in writing (during the 60-day consistency review 

period). 

7.5 EXPLANATION OF THE PUBLIC PROTEST PROCESS FOR THE PROPOSED 

LAND USE PLAN AMENDMENTS 

 As discussed in Chapter 2 and Appendix C, the BLM proposes to amend 10 land use 

plans in Colorado, Utah, and Wyoming to adopt specific decisions rendered in the PEIS related 

to land use designations for oil shale and tar sands resources. 

 Pursuant to BLM’s planning regulations at 43 CFR 1610.5-2, any person who 

participated in the planning process for these Proposed Plan Amendments and has an interest that 

is or may be adversely affected by the proposed planning decisions may protest approval of the 

planning decisions within 30 days from date the Environmental Protection Agency (EPA) 

publishes the Notice of Availability in the Federal Register. The regulations specify the required 

elements of your protest. Take care to document all relevant facts. As much as possible, 

reference or cite the planning documents or available planning records (e.g., meeting minutes or 

summaries, correspondence) associated with your protest. 

 E-mailed and faxed protests will not be accepted as valid protests unless the protesting 

party also provides the original letter by either regular or overnight mail postmarked by the close 

of the protest period. Under these conditions, the BLM will consider the e-mailed or faxed 

protest as an advance copy and will afford it full consideration. If you wish to provide the BLM 

with such advance notification, please direct faxed protests to the attention of Brenda HudgensWilliams, BLM protest coordinator, at 202-245-0028, and e-mailed protests to Brenda_HudgensWilliams@blm.gov. 

 All protests, including the follow-up letter to e-mails or faxes, must be in writing and 

mailed to one of the following addresses: 

Regular Mail: Overnight Mail: 

Director (210) Director (210) 

Attn: Brenda Hudgens-Williams Attn: Brenda Hudgens-Williams 

P.O. Box 71383 20 M Street SE, Room 2134LM 

Washington, D.C. 20024-1383 Washington, D.C. 20003 

 Before including your address, phone number, e-mail address, or other personal 

identifying information in your protest, be advised that your entire protest – including your 

personal identifying information – may be made publicly available at any time. While you can 

ask us in your protest to withhold from public review your personal identifying information, we 

cannot guarantee that we will be able to do so. 

 The BLM Director will make every attempt to promptly render a decision on each 

protest. The decision will be in writing and will be sent to the protesting party by certified mail, 

return receipt requested. The decision of the BLM Director shall be the final decision of the 
Final OSTS PEIS 7-9 

Department of the Interior on each protest. Responses to protest issues will be compiled and 

formalized in a Director’s Protest Resolution Report made available following issuance of the 

decisions. 

 Upon resolution of all land use plan protests, the BLM will issue an Approved RMP and 

ROD. The Approved RMP and ROD will be mailed or made available electronically to all who 

participated in the planning process and will be available to all parties through the “Planning” 

page of the BLM national Web site (http://www.blm.gov/planning), on the project Web site 

(http://ostseis.anl.gov), or by mail upon request. 

7.6 ENDANGERED SPECIES ACT SECTION 7 REQUIREMENTS 

 Section 7 of the Endangered Species Act of 1973, as amended (ESA; 16 USC 1536), 

directs each federal agency, in consultation with the USFWS or the National Marine Fisheries 

Service (NMFS), as appropriate, to ensure that any action authorized, funded, or carried out by 

the agency is not likely to jeopardize the continued existence of any listed threatened or 

endangered species or result in the destruction or adverse modification of critical habitat. Under 

Section 7 of the ESA, those agencies that authorize, fund, or carry out the federal action are 

commonly known as “action agencies.” If an action agency determines that its federal action 

“may affect” listed species or critical habitat, it must consult with the USFWS or NMFS 

(collectively known as the “Services”), or both, whichever has jurisdiction over the species or 

habitat that may be affected (see 50 CFR 402.02, 402.13–14). If an action agency determines that 

the federal action will have no effect on listed species or critical habitat, the action agency may 

make a “no effect” determination. In that case, the action agency does not initiate consultation 

with the Services and its obligations under Section 7 are complete. 

 In complying with its duty under Section 7, the BLM, as the action agency, has examined 

whether amending land use plans to identify lands as available for application for commercial 

leases for oil shale or tar sands development would have any effects on listed species and/or 

critical habitat. In making this determination, the BLM also reviewed USFWS’ guidance 

concerning emissions of greenhouse gases and any effects they may cause on listed species and 

critical habitats, in particular the polar bear, because if and when oil shale and tar sands resources 

are developed those development activities may result in the emissions of greenhouse gases 

(Caswell 2008; Hall 2008). As a result of these reviews, the BLM has determined that its 

proposed action of amending land use plans to allocate areas as available or not available for 

application for oil shale and tar sands leasing would cause no effect on any listed species or 

critical habitat. 

 Because of the nascent character of any oil shale or tar sands industry, it is impossible 

at present to determine what biological effects on listed species or critical habitat might be 

“reasonably certain to occur” (50 CFR 402.02). That is, there is no proven commercially viable 

technology for extracting liquid fuels from oil shale and tar sands. This circumstance is described 

in the 2008 OSTS PEIS and ROD associated with land use plan amendments to address the 

management of oil shale and tar sands on the public lands, as well as in the preamble to the 2008 
Final OSTS PEIS 7-10 

oil shale regulations. Even today, despite ongoing research efforts, there is no such proven 

technology. 

 As a result, the specifics of the technology or technologies that may be shown in the 

future to be commercially viable cannot be predicted with any certainty at this time. Neither can 

the specific areas (among those generally available) most likely to be developed or the possible 

environmental consequences of such development be predicted at this time. Therefore, the 

NEPA analysis associated with the current land use planning initiative, like the 2008 NEPA 

analysis, will be based for analytical purposes on very general assumptions about the possible 

technologies, areas, and environmental consequences involved in management of oil shale and 

tar sands resources. 

 With respect to compliance with the ESA for this land use planning initiative, the BLM 

considered preparing a biological assessment (BA) and initiating consultation with the USFWS 

under Section 7(a)(2) of the ESA. After discussing various approaches in light of the nascent 

character of the development of oil shale and tar sands resources, and closely examining the 

regulations for implementing the ESA, the BLM determined, however, that preparation of a BA 

before a lease- or site-specific project had been proposed would be based largely on conjecture 

and speculation. There simply would be no way to know before such a proposal is made whether 

the impacts to be assessed would be those that would actually occur as a result of a proposal by a 

future proponent. Further, without knowing the specifics of when and where a project would 

occur, it would be impossible to know what species or habitat, if any, would be affected by the 

project. The BLM considered whether it made sense to make assumptions for the purposes of a 

BA, but was left with no credible basis on which to make such assumptions. The BLM 

determined such assumptions would be speculative and not linked to the federal action of 

amending land use plans. Any BA would be a speculative assessment of the effects from future 

site-specific projects, not of the current proposed action. Therefore, the BLM has determined that 

the land use plan amendments to identify lands as available for application for commercial 

leasing for oil shale or tar sands development would have no effect on listed species or critical 

habitat. 

 Moreover, as noted in the 2008 OSTS PEIS, this land use plan amendment is solely an 

allocation decision; it does not establish a precedent or create any legal right that would allow 

ground-disturbing activities without further agency decision making and compliance with 

applicable statutes, including the ESA, NEPA, and other applicable authorities. Further, apart 

from possible socioeconomic impacts associated with speculative investments in lands adjacent 

to lands allocated for oil shale and tar sands development, there are no environmental 

consequences at all from the administrative action of amending land use plans in the manner 

described. Therefore, the NEPA analysis being prepared focuses on the potential effects 

associated with possible future leasing and development, in order to inform the decision-maker 

regarding the allocation decisions. 

 This determination of “no effect” is consistent with the determination made with respect 

to the planning initiative that was completed in 2008. At the outset of the development of the 

2008 OSTS PEIS, when the BLM planned to issue leases on the basis of the analyses conducted 

in that document, the BLM began the process of consultation with the USFWS pursuant to its 
Final OSTS PEIS 7-11 

obligations under Section 7 of the ESA. During this preliminary consultation, the BLM and 

USFWS jointly developed conservation measures to support conservation of species listed under 

the ESA. During preparation of what became the 2008 OSTS PEIS, the decision to be made (the 

proposed action) was limited to the amendment of land use plans setting out the allocation of 

areas that would be available for application for leases; therefore, during that period, the BLM 

determined that the proposed action would result in no effect on listed species or critical habitat. 

 The BLM recognizes that listed species and critical habitat are likely to be present in the 

lands described in the land use plan amendment. Tables 4.8.1-6 and 5.8.1-6 in the 2008 OSTS 

PEIS identify the listed species that occur in the states of Colorado, Utah, and Wyoming where 

the land use plan amendments would allocate lands for either oil shale or tar sands leasing. 

Portions of the designated areas are occupied by listed species or contain designated critical 

habitat. Therefore, the BLM fully expects that if in response to a call for nominations, an 

application for a lease, permit, or other authorization is received by the BLM for oil shale or tar 

sands development within lands identified as available for application, procedures to comply 

with Section 7 of the ESA would be initiated at that time. Such procedures may take the form of 

a “no effect” determination by the BLM, informal consultation with USFWS, or formal 

consultation with USFWS. At such time as any “no effect” determination is made, or informal 

or formal consultation occurs, such determination/consultation would be made based on a full 

record describing the proposed lease, project, site, method of construction, and other relevant 

information—all features that are lacking at the present time. Such a determination would take 

place following a full policy and legal review. 

 Further, if analysis undertaken in consideration of a definitely proposed lease or project 

area or technology warrants, the BLM may impose conservation measures upon potential lessees 

through lease stipulation or other means. In fact, as in the 2008 OSTS PEIS, the BLM has 

included Appendix F, which presents conservation measures developed through coordination 

with the USFWS during the oil shale and tar sands planning process that culminated in the 2008 

land use plan amendments, as well as additional conservation measures that have been developed 

during more recent coordination. These measures have been included in Appendix F, both for the 

new NEPA/planning process and to provide the public and any potential lessees with some sense 

of what conservation measures might be imposed, if warranted. 

 The BLM, in coordination with USFWS, intends to ensure that the conservation measures 

presented are consistent with those currently applied to other land management actions where 

associated impacts are similar. However, it is presumed that potential impacts from possible 

development alternatives (described based on assumptions made for analytical purposes in the 

NEPA analysis) are likely to vary in scale and intensity compared with previously considered 

land management actions (e.g., oil and gas exploration and production, surface mining, and 

underground mining). Hence, final conservation measures will be developed commensurate 

with the anticipated level of impact from actual future site-specific projects developed under 

the selected alternative, as analyzed in those site-specific project level analyses, and will be 

consistent with agency policies. For instance, current BLM guidance on similar actions 

(e.g., projects involved in the development of fluid mineral resources) requires that the least 

restrictive stipulation that effectively accomplishes the resource objectives or resource uses for a 

given alternative should be used in order for a project to remain in compliance with the ESA.
Final OSTS PEIS 7-12 

7.7 NATIONAL HISTORIC PRESERVATION ACT SECTION 106 REQUIREMENTS 

 Section 106 of NHPA requires federal agencies to take into account the effects of their 

undertakings (actions or authorizations) on any district, site, building, structure or object that 

is included in or eligible for inclusion in the NRHP, and to provide the ACHP a reasonable 

opportunity to comment. The procedural requirements for compliance with Section 106 of the 

NHPA are set forth in the ACHP’s Section 106 regulations at 36 CFR Part 800. The BLM has 

initiated the Section 106 process pursuant to these regulations and has reviewed existing 

information regarding historic properties in the Area of Potential Effects (APE) for this proposed 

amendment of land use plans. The APE has been defined as the most geologically prospective 

areas for oil shale and tar sands in Colorado, Utah, and Wyoming. The BLM has initiated 

consultation with the SHPOs, tribes, and other consulting parties. (Appendix L describes the 

consultation process.) The BLM has reviewed existing information on historic properties within 

the APE, incorporating information gathered through consultation with the consulting parties. 

The findings of the review are presented in Sections 3.8, 3.9, and 3.10. 

 Based on the review, the BLM has identified historic properties within the APE, and 

that additional unidentified historic properties are likely present within the APE. The BLM 

has determined that this decision to allocate lands as open or closed for oil shale and tar sands 

potential leasing and development does not affect these historic properties. As articulated in 

the BLM’s finding letters sent to the Colorado, Utah, and Wyoming SHPOs pursuant to 

36 CFR 800.4(d)(1), the BLM bases its determination on the following: (1) the decision to 

allocate lands as open or closed to potential oil shale and tar sands leasing does not approve any 

on-the-ground activities and does not restrict any managers’ authority to fully consider the 

potential effects on historic properties prior to the potential offer for leasing or development, 

including the ability to approve, modify, or deny a lease application or development proposal 

based on consideration of such effects; and (2) the current status of oil shale and tar sands 

development technology is not sufficiently defined to identify with certainty the types of impacts 

that might occur on historic properties if areas were leased and developed. Therefore, while they 

may inform future decisions, the analyses in this document are more likely to be added to, or 

elaborated upon, prior to any future leasing or development decisions, which will be subject to 

full compliance with Section 106 at that time. 

 Oil shale and tar sands development would require a three-stage decision-making 

process. The first stage, which is the subject of this PEIS, is the proposed amendment of land use 

plans to allocate lands as open or closed to potential oil shale and/or tar sands leasing and, where 

leases are acquired, potential development. Compliance with Section 106 for this stage is at a 

level appropriate for this decision. The BLM recognizes that the decision to allocate lands does 

not identify or authorize any future leasing or development, and that the technology for such 

development is subject to change from that reviewed in this study. Accordingly, the BLM has 

determined that no historic properties would be affected by amending the land use plans. 

 The second stage requires full compliance with Section 106 of the NHPA prior to the 

BLM issuing a lease for potential oil shale or tar sands development. The APE for a potential 

lease would be determined based on the extent of the proposed lease. Government-togovernment consultation with affected tribes concerning a proposed lease area would occur at 
Final OSTS PEIS 7-13 

the second stage. The second stage would require consultation with all interested parties. 

Documentation and inventory would occur at the second stage in order to identify, evaluate, and 

mitigate any historic properties in the APE. This effort would include an analysis of existing 

overview information and a current records and literature search. A Class II or Class III 

inventory or visual resource inventory may also be required, if necessary, to determine the 

undertaking’s effect on historic properties. Lease areas may be subject to stipulations or other 

requirements identified during the leasing process. 

 The final stage is the potential approval of a specific plan of development. A plan of 

development would identify specific locations, facilities, and timing for development. This 

decision would also require compliance with Section 106 of the NHPA prior to approval, and 

may also be subject to stipulations or other requirements identified during the leasing stage to 

avoid, minimize, or mitigate impacts on historic properties. Government-to-government 

consultation with tribes would occur during this stage to determine whether the plan of 

development would have an effect on properties of concern. Consultation with interested parties 

would also take place. Detailed field review will take place at this stage, including Class III 

cultural resource inventories, visual resource inventories, and other site-specific reviews, as 

needed. 

 The BLM will complete comprehensive identification (e.g., field inventory), evaluation, 

protection, and mitigation, following the policies and procedures contained within the 2012 BLM 

National Programmatic Agreement (BLM 2012b) and as indicated in any lease stipulations. In 

addition, the BLM will continue to implement government-to-government consultation with 

tribes and with other consulting parties on a case-by-case basis for plans of development. 

 The BLM does not approve any ground-disturbing activities that may affect any historic 

properties, sacred landscapes, and/or resources protected under the NHPA, American Indian 

Religious Freedom Act, NAGPRA, E.O. 13007 (U.S. President 1996), or other statutes and 

Executive Orders until it completes its obligations under applicable requirements of the NHPA 

and other authorities. The BLM may require modification to exploration or development 

proposals to protect such properties, or it may disapprove any activity that is likely to result in 

adverse effects that cannot be successfully avoided, minimized, or mitigated. 

7.8 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

BLM (Bureau of Land Management), 2004a, Manual 8120Tribal Consultation under Cultural 

Resources, Release 8-74, U.S. Department of the Interior. 

BLM, 2004b, Handbook H-8120-1General Procedural Guidance for Native American 

Consultation, Release 8-75, U.S. Department of the Interior.
Final OSTS PEIS 7-14 

BLM, 2011, “Notice of Intent to Prepare a Programmatic Environmental Impact Statement (EIS) 

and Possible Land Use Plan Amendments for Allocation of Oil Shale and Tar Sands Resources 

on Lands Administered by the Bureau of Land Management in Colorado, Utah, and Wyoming,” 

Federal Register 76:21003–21005. 

BLM, 2012a, Draft Programmatic Environmental Impact Statement and Possible Land Use Plan 

Amendments for Allocation of Oil Shale and Tar Sands Resources on Lands Administered by the 

Bureau of Land Management in Colorado, Utah, and Wyoming, Vols. 1–4, DES 12-01, Jan. 

BLM, 2012b, Programmatic Agreement among the Bureau of Land Management, the Advisory 

Council on Historic Preservation, and the National Conference of State Historic Preservation 

Officers Regarding the Manner in Which BLM Will Meet Its Responsibilities under the 

National Historic Preservation Act Preamble, U.S. Department of the Interior. Available at 

http://www.blm.gov/pgdata/etc/medialib/blm/wo/Information_Resources_Management/policy/ 

im_attachments/2012.Par.24647.File.dat/IM2012-061_att1.pdf. Accessed Aug. 14, 2012. 

Caswell, J.L., 2008, personal communication from Caswell (Bureau of Land Management, 

Washington, D.C.) to H.D. Hall (Director, U.S. Fish and Wildlife Service, Washington, D.C.), 

June 19. 

DOI (U.S. Department of the Interior), 2011, Department of the Interior Policy on Consultation 

with Indian Tribes, Washington, D.C., Dec. 1. 

Hall, H.D., 2008, personal communication from Hall (Director, U.S. Fish and Wildlife Service, 

Washington, D.C.) to J.L. Caswell (Bureau of Land Management, Washington, D.C.), June 26. 

U.S. President, 1996, “Locating Federal Facilities on Historic Properties in Our Nation’s Central 

Cities,” Executive Order 13006, Federal Register 61:26071, May 24. 

U.S. President, 1998, “Consultation and Coordination with Indian Tribal Governments,” 

Executive Order 13084, Federal Register 63:27655, May 19. 

U.S. President, 2000, “Consultation and Coordination with Indian Tribal Governments,” 

Executive Order 13175, Federal Register 65:67249, Nov. 9. 
Final OSTS PEIS 8-1 

8 LIST OF PREPARERS 

Name Education/Expertise Contribution 

 

Bureau of Land Management

Sherri Thompson B.S., Petroleum Engineering; 20 years of 

experience in fluid minerals resources; 

9 years of experience in planning and 

NEPA. 

BLM Project Manager 

Scott F. Archer B.S., Chemistry, Environmental Science, 

and Police Administration; 31 years of 

experience in air resource management. 

Air quality and climate 

impacts analysis 

Susan Bassett B.S., Chemical Engineering; B.A., 

English; 21 years of experience in air 

quality compliance and NEPA analysis. 

Air quality impacts 

analysis 

Kate Winthrop Ph.D., Anthropology; 31 years of cultural 

resource management experience. 

Cultural resources 

Angela Zahniser B.A., Anthropology and Philosophy; 

7 years of experience in air resource 

management. 

Global climate change 

Argonne National Laboratory

Timothy Allison M.S., Mineral and Energy Resource 

Economics; M.A., Geography; 26 years 

of experience in regional analysis and 

economic impact analysis. 

Technical lead for 

socioeconomic analysis 

and environmental justice 

Georgia Anast B.A., Mathematics/Biology; 22 years of 

experience in environmental assessment. 

Comment/response 

manager 

Bruce M. Biwer Ph.D., Chemistry; 22 years of experience 

in transportation and environmental risk 

analysis. 

Transportation impacts 

analysis 

Brian L. Cantwell B.S., Forestry; 29 years of experience in 

cartography and GIS mapping. 

Technical lead for GIS 

mapping 

Young-Soo Chang Ph.D., Chemical Engineering; 25 years of 

experience in air quality and noise impact 

analysis. 

Affected environment, air 

quality and emissions, 

noise 
Final OSTS PEIS 8-2 

Name Education/Expertise Contribution 

 

Vic Comello M.S., Physics; 34 years of experience in 

technical writing and editing. 

Editor 

Linda Graf Desktop publishing specialist; 41 years of 

experience in creating, revising, 

formatting, and printing documents. 

Lead for document 

processing and formatting 

Mark Grippo Ph.D., Biology; 8 years of experience in 

ecological research; 5 years of experience 

in environmental assessment. 

Ecological resources 

analysis (aquatic) 

Heidi M. Hartmann M.S., Environmental Toxicology and 

Epidemiology; 26 years of experience in 

exposure and risk analysis and 

environmental impact assessment. 

Health and safety 

analysis; cumulative 

impacts summary 

John Hayse Ph.D., Zoology; 25 years of experience in 

ecological research and environmental 

assessment. 

Ecological resources 

analysis (aquatic) 

Elizabeth Hocking J.D., 22 years of experience in regulatory 

and policy analysis. 

Regulatory requirements 

Patricia Hollopeter M.A., Philosophy; 31 years of experience 

in editing and writing. 

Lead editor 

Ronald Kolpa M.S., Inorganic Chemistry; B.S., 

Chemistry; 37 years of experience in 

environmental regulation, auditing, and 

planning. 

Hazardous materials and 

waste management; 

technology overview for 

oil shale 

Douglas Kullen M.A., Social Sciences; B.A., 

Anthropology; 33 years of experience in 

North American archaeology, 6 years in 

environmental assessment. 

Cultural resources 

impacts analysis 

Kirk E. LaGory Ph.D., Zoology, M.En., Environmental 

Science; 38 years of experience in 

ecological research, 22 years in 

environmental assessment. 

Program Manager; 

technical lead for 

ecological resources 

analysis 

Andrea Manning B.A., M.A., English 

20 years of experience in writing and 

editing. 

Editor 

 
Final OSTS PEIS 8-3 

Name Education/Expertise Contribution 

 

James E. May M.S., Water Resources Management; 

B.A., Zoology; 38 years of experience in 

natural resources management; 9 years of 

consulting experience in land use 

planning and NEPA compliance. 

Land use, grazing, 

recreation, wilderness, 

specially designated areas

Mary R. Moniger B.A., English, 34 years of experience in 

editing and writing. 

Editor 

Michele Nelson Graphic designer; 34 years of experience 

in graphical design and technical 

illustration. 

Graphics 

Daniel J. O’Rourke M.S., Industrial Archaeology; B.A., 

History/Anthropology; 22 years of 

experience in archaeology, 15 years in 

environmental assessment. 

Technical lead for cultural 

resources impacts analysis

Terri Patton M.S., Geology; 25 years of experience in 

geology and environmental assessment. 

Technical lead for 

paleontology 

Kurt Picel Ph.D. and M.S., Environmental Health 

Sciences; 34 years of experience in 

environmental health sciences, 21 years 

in environmental assessment. 

Project Manager 

John Quinn Ph.D., Hydrogeology; 21 years of 

experience in hydrogeology. 

Technical lead for water 

resources and for soils 

and geology 

Pam Richmond M.S., Computer Science; 12 years of 

experience in multimedia development 

and Web design/programming. 

Web site development 

and management 

Lorenza Salinas Desktop publishing specialist; 30 years of 

experience in creating, revising, 

formatting, and printing documents. 

Document assembly and 

production 

Scott Schlueter B.S., Computer Graphics Technology; 

3 years of experience in GIS mapping and 

database management. 

GIS mapping and data 

management 

Kerri Schroeder Desktop publishing specialist; 32 years of 

experience in creating, revising, 

formatting, and printing documents.

Document assembly and 

production 

 
Final OSTS PEIS 8-4 

Name Education/Expertise Contribution 

 

Barbara A. Simmons B.A., Technical Writing; E.L.S. 

certification by the Board of Editors in 

the Life Sciences; Fellow of the Society 

for Technical Communication; 46 years 

of experience in publications 

management and technical editing. 

Editor

Albert E. Smith Ph.D., Physics; 32 years of experience in 

air quality and environmental assessment. 

Technical review for 

noise and air quality 

impacts analysis 

Carolyn M. Steele B.A., English; B.A., Rhetoric; 6 years of 

experience in technical writing and 

editing. 

Editor 

Robert Sullivan M.L.A., Landscape Architecture; 26 years 

of experience in visual impact analysis 

and simulation; 18 years in Web site 

development. 

Technical lead for visual 

impact analysis; public 

Web site development 

Robert A. Van Lonkhuyzen B.A., Biology; 21 years of experience in 

ecological research and environmental 

assessment. 

Ecological resources 

analysis (plant 

communities and habitats) 

Bruce Verhaaren Ph.D., Archaeology; 25 years of 

experience in archaeological analysis; 

22 years in environmental assessment and 

records management. 

Native American 

consultation and 

concerns; records 

management

William S. Vinikour M.S., Biology with environmental 

emphasis; 36 years of experience in 

ecological research and environmental 

assessment. 

Ecological resources 

analysis (wildlife) 

Leroy J. Walston M.S., Biology; 10 years of experience in 

ecological research and environmental 

assessment. 

Ecological resources 

analysis (threatened, 

endangered, and sensitive 

species) 

Ellen White M.P.P., Public Policy; B.A., 

Environmental Studies; 8 years of 

experience in environmental assessment. 

Scoping summary and 

cumulative impacts 

update 

Suzanne Williams B.S., Communication Studies with 

concentration in English; 28 years of 

experience in technical communications. 

Editor 

 
Final OSTS PEIS 8-5 

Name Education/Expertise Contribution 

 

Emily A. Zvolanek B.A., Environmental Science; 4 years of 

experience in GIS mapping. 

GIS mapping 

Aerotek 

Jennifer Abplanalp M.A., Anthropology; B.A., 

Anthropology; 11 years of experience in 

archaeology; 3 years of experience in 

environmental assessment and records 

management. 

Native American 

consultation and 

concerns; records 

management 

Maureen McHugh B.S., Environmental Policy and 

Mathematics; M.E.M., Environmental 

Economics and Policy; 3 years of 

experience in environmental research and 

assessment. 

Public comment review; 

water resources 

assessment 

Angela Ziech M.P.P., Public Policy; B.A., Chemistry; 

5 years of experience in environmental 

research and assessment. 

Public comment review 

 
Final OSTS PEIS 8-6 

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Final OSTS PEIS 9-1 

9 GLOSSARY 

Abiotic: Refers to nonliving objects, substances, or processes. The abiotic factors of the 

environment include light, temperature, and atmospheric gases. 

Aboveground retorting: see Retorting. 

Acre-foot (ac-ft): A term used in measuring the volume of fluid. An acre-foot is the amount of 

fluid required to cover 1 acre to a depth of 1 ft, or 43.540 ft3 (325,829 gal). 

Adaptive management: Adaptive management is a structured, iterative process of robust 

decision making in the face of uncertainty, with an aim of reducing uncertainty over time via 

system monitoring. 

Adiabatic change: Change in the volume and pressure of a parcel of gas without an exchange of 

heat between the parcel of gas and its surroundings. 

Aerodynamics: The study of the forces exerted on and the flow around solid objects moving 

relative to a gas, especially the atmosphere. 

Aggregate: Mineral materials such as sand, gravel, crushed stone, or quarried rock used for 

construction purposes. 

Air density: The weight of a given volume of air. Air is denser at a lower altitude, lower 

temperature, and lower humidity. 

Air quality: Measure of the health-related and visual characteristics of the air. Air quality 

standards are the prescribed level of constituents in the outside air that cannot be exceeded 

during a specific time in a specified area. 

Air toxics: Substances that have adverse impacts on human health when present in ambient air. 

All-American Roads: Roads selected for this designation by the U.S. Department of 

Transportation because of their important scenic, natural, historical, cultural, archaeological, or 

recreational qualities. They provide an exceptional traveling experience such that motorists go to 

these highways as a primary reason for their trip. 

Alluvial: Formed by the action of running water; of or related to river and stream deposits. 

Alluvial fan: A gently sloping mass of unconsolidated material (e.g., clay, silt, sand, or gravel) 

deposited where a stream leaves a narrow canyon and enters a plain or valley floor. Viewed from 

above, it has the shape of an open fan. An alluvial fan can be thought of as the land counterpart 

of a delta. 

Alluvium: Sediments deposited by erosion processes, usually by streams. 
Final OSTS PEIS 9-2 

Ambient air: The surrounding atmosphere as it exists around people, plants, and structures. 

Ambient noise level: The level of acoustic noise existing at a given location, such as in a room 

or somewhere outdoors. 

American Antiquities Act of 1906: Prohibits excavating, injuring, or destroying any historic or 

prehistoric ruin or monument or object of antiquity on federal land without the prior approval of 

the agency with jurisdiction over the land. 

American Indian Religious Freedom Act of 1978: Requires federal agencies to consult with 

tribal officials to ensure protection of religious cultural rights and practices. 

Anthropogenic: Human made; produced as a result of human activities. 

API gravity: A measurement convention established by the American Petroleum Institute for 

expressing the relative density of petroleum liquids to water; the greater the API gravity, the less 

dense the material. 

Aquifer: An underground bed or layer of earth, gravel, or porous stone that yields usable 

quantities of water to a well or spring. 

Archaeological and Historical Preservation Act of 1966, as amended: Directly addresses 

impacts or cultural resources resulting from federal activities that would significantly alter the 

landscape. The focus of the law is the creation of dams and the impacts resulting from flooding, 

creation of access roads, etc. Its requirements, however, are applicable to any federal action. 

Archaeological Resources Protection Act of 1979: Requires a permit for excavation or 

removal of archeological resources from public or Native American lands. 

Archaeological site: Any location where humans have altered the terrain or discarded artifacts 

during prehistoric or historic times. 

Areas of Critical Environmental Concern (ACECs): These areas are managed by the Bureau 

of Land Management (BLM) and are defined by the Federal Land Policy and Management Act 

of 1976 as having significant historical, cultural, and scenic values, habitat for fish and wildlife, 

and other public land resources, as identified through the BLM’s land use planning process. 
Final OSTS PEIS 9-3 

Areas recognized as having wilderness characteristics (WCAs): Areas that are not officially 

identified as “wilderness” under the meaning of the Wilderness Act of 1964; nor are they 

“wilderness study areas” (WSAs) that were identified by BLM inventories in the 1970s and 

1980s under the authority of FLPMA. Generally, they are areas that were identified by the BLM 

or others and that were inventoried by the BLM to determine whether they possessed the 

characteristics of wilderness as described in the Wilderness Act. The BLM may manage the 

lands to protect and/or preserve some or all of those characteristics through the land use planning 

process. In addition, under the land use planning process, the BLM must consider a range of 

alternatives for the land identified with wilderness characteristics. This gives the public the 

ability to fully compare the consequences of protecting or not protecting the wilderness 

characteristics on these non-WSA lands. 

Argillaceous: Used to describe a rock containing a large percentage of clay. 

Atmospheric deposition: The process by which trace gases and particulate matter in the 

atmosphere are deposited on vegetation, soils, and water bodies. Key concerns are total (wet and 

dry) deposition of sulfur and nitrogen compounds, and especially their potential impacts on 

sensitive lake systems. 

Attainment area: An area considered to have air quality as good as or better than the National 

Ambient Air Quality Standards for a given pollutant. An area may be in attainment for one 

pollutant and in nonattainment for others. 

Attenuation: The reduction in level of sound. 

Authigenic: Formed in place; typically refers to minerals formed in place after the sediments 

were deposited. 

Bald and Golden Eagle Protection Act of 1940: Act making it unlawful to take, pursue, 

molest, or disturb bald and golden eagles, their nests, or their eggs. Permits must be obtained 

from the U.S. Department of the Interior (DOI) in order to relocate nests that interfere with 

resource development or recovery. 

Best management practices (BMPs): A practice or combination of practices that are 

determined to provide the most effective, environmentally sound, and economically feasible 

means of managing an activity and mitigating its impacts. 

Biological Assessment: A document prepared for the Endangered Species Act of 1973 (ESA) 

Section 7 process to determine whether a proposed major construction activity under the 

authority of a federal action agency is likely to adversely affect listed species, proposed species, 

or designated critical habitat. 

Biological Opinion: A document resulting from formal consultation with the U.S. Fish and 

Wildlife Service (USFWS). The document presents the opinion of the USFWS as to whether a 

federal action is likely to jeopardize the continued existence of listed species or result in the 

destruction or adverse modification of critical habitat. 
Final OSTS PEIS 9-4 

Biomass: Anything that is or has once been alive. 

Biota: The living organisms in a given region. 

Bitumen: A mix of hydrocarbons with a high carbon-to-hydrogen ratio, which may contain 

elevated concentrations of sulfur, nitrogen, oxygen, and heavy metals. 

Boiler slag: A noncombustible by-product collected from the bottom of furnaces that burn coal 

for the generation of steam. When molten boiler slag comes in contact with water, it fragments 

into coarse, black, angular particles having a smooth, glassy appearance. These particles are used 

for blasting grit and roofing granules. 

Boreal forest: A forest that grows in regions of the northern hemisphere with cold temperatures; 

made up of mostly cold-tolerant coniferous species such as spruce and fir. 

Borrow pit: A pit or excavation area used for gathering earth materials (borrow) such as sand or 

gravel. 

Broadband noise: Noise that has a continuous spectrum; that is, energy is present at all 

frequencies in a given range. This type of noise lacks a discernible pitch and is described as 

having a “swishing” or “whooshing” sound. 

Browse: Shrubs, trees, and herbs that provide food for wildlife. 

Bureau of Land Management (BLM): An agency of the U.S. Department of the Interior that is 

responsible for managing public lands. 

Bureau of Land Management (BLM) “Gold Book”: Surface Operating Standards and 

Guidelines for Oil and Gas Exploration and Development provides comprehensive guidance on 

the design, construction, maintenance, and reclamation of sites and access roads. The Gold Book 

promotes conduct of environmentally responsible oil and gas operations on federal lands. 

Candidate species: Plants and animals for which the USFWS has sufficient information on their 

biological status and threats to propose them as endangered or threatened under the ESA, but for 

which development of a listing regulation is precluded by other higher priority listing activities. 

Canopy: The upper forest layer of leaves consisting of tops of individual trees whose branches 

sometimes cross each other. 

Carbon monoxide (CO): A colorless, odorless gas that is toxic if breathed in high 

concentrations over an extended period. Carbon monoxide is listed as a criteria air pollutant 

under Title I of the Clean Air Act. 

Carrion: The dead, decomposing flesh of an animal. 
Final OSTS PEIS 9-5 

Chaparral: A plant community of shrubs and low trees adapted to annual drought and often 

extreme summer heat and also highly adapted to fires recurring every 5 to 20 years. 

Char: The organic residue remaining on the spent shale. 

Clean Air Act (CAA): Establishes national ambient air quality standards and requires facilities 

to comply with emission limits or reduction limits stipulated in State Implementation Plans 

(SIPs). Under this Act, construction and operating permits, as well as reviews of new stationary 

sources and major modifications to existing sources, are required. The Act also prohibits the 

federal government from approving actions that do not conform to SIPs. 

Clean Water Act (CWA): Requires National Pollutant Discharge Elimination System (NPDES) 

permits for discharges of effluents to surface waters, permits for storm water discharges related 

to industrial activity, and notification of oil discharges to navigable waters of the United States. 

Clearcut: The removal or cutting of all trees in an area of forest land at one time. An area of 

forest land from which all trees have recently been harvested. 

Coal production (on BLM lands): The Mineral Leasing Act of 1920, as amended by the 

Federal Coal Leasing Amendments Act of 1976, requires competitive leasing of coal. These 

leases require payment of a royalty rate of 12.5% for surface-mined coal (8% for coal mined by 

underground methods), diligent development of commercial quantities of coal within 10 years of 

lease issuance, and stipulations to protect other resources within the lease. The BLM routinely 

inspects all coal to ensure accurate reporting of coal production and maximum economic 

recovery of the coal resource. 

Code of Federal Regulations (CFR): A compilation of the general and permanent rules 

published in the Federal Register by the Executive departments and agencies of the 

United States government. It is divided into 50 titles that represent broad areas subject to federal 

regulation. Each volume of the CFR is updated once each calendar year and is issued on a 

quarterly basis. 

Colluvium: A general term to include loose rock and soil material that accumulates at the base 

of a slope as the result of mass wasting processes. 

Combined Hydrocarbon Lease (CHL): Lease issued in a Special Tar Sand Area (STSA) for 

the removal of gas and nongaseous hydrocarbon substances other than coal, oil shale, or 

gilsonite. 

Combined Hydrocarbon Leasing Act of 1981: Act that amended the Mineral Leasing Act of 

1920 to authorize the Secretary of the Interior to issue CHLs in areas containing substantial 

deposits of tar sands, which were to be designated as STSAs. 

Confined aquifer: An aquifer in which groundwater is confined under pressure that is 

significantly greater than atmospheric pressure. 
Final OSTS PEIS 9-6 

Conifers: Cone-bearing trees, mostly evergreens, that have needle-shaped or scale-like leaves. 

Conterminous United States: The 48 mainland states, excluding Alaska and Hawaii. 

Controlled Surface Use (CSU): (1) Use and occupancy is allowed (unless restricted by another 

stipulation), but identified resource values require special operational constraints that may 

modify the lease rights. CSU is used for operating guidance, not as a substitute, for the 

No Surface Occupancy (NSO) or timing stipulations. (2) Stipulations to be attached to oil and 

gas leases to protect specific areas or resources, such as riparian and wetland areas, rivers, 

sensitive species, viewsheds, and watersheds.

Corona/corona noise: The electrical breakdown of air into charged particles. The phenomenon 

appears as a bluish-purple glow on the surface of and adjacent to a conductor when the voltage 

gradient exceeds a certain critical value, thereby producing light, audible noise (described as 

crackling or hissing), and ozone. 

Corona discharge: A noise having a hissing or crackling character. 

Council on Environmental Quality (CEQ): Established by NEPA. CEQ regulations 

(40 CFR Parts 1500–1508) describe the process for implementing NEPA, including preparation 

of environmental assessments (EAs) and environmental impact statements (EISs), and the timing 

and extent of public participation. 

Cradle-to-Grave: A procedure in which hazardous materials are identified and followed as they 

are produced, treated, transported, and disposed of by a series of permanent, linkable, descriptive 

documents (e.g., manifests). Commonly referred to as the cradle-to-grave system. 

Criteria air pollutants: Six common air pollutants for which National Ambient Air Quality 

Standards (NAAQS) have been established by the U.S. Environmental Protection Agency (EPA) 

under Title I of the Clean Air Act (CAA). They are sulfur dioxide, nitrogen oxides, carbon 

monoxide, ozone, particulate matter (PM2.5 and PM10), and lead. Standards were developed for 

these pollutants on the basis of scientific knowledge about their health effects. 

Critical habitat: The specific area within the geographical area occupied by the species at the 

time it is listed as endangered or threatened. The area in which physical or biological features 

essential to the conservation of the species are found. These areas may require special 

management or protection. 

Crude oil: Unrefined oil as it is found underground, consisting of a mixture of hydrocarbons 

formed from organic matter. 

Cryptobiotic organisms: Soil-dwelling organisms, including cyanobacteria (blue-green 

bacteria), microfungi, mosses, lichens, and green algae found in surface soils of the arid and 

semiarid West. These organisms perform many important functions, including fixing nitrogen 

and carbon, maintaining soil surface stability, plant growth, and preventing erosion. They bind 

together with soil particles to create a crust. 
Final OSTS PEIS 9-7 

Cuesta: An asymmetrical ridge with one steep face (an escarpment slope) and an opposite, 

gently inclined face (a dip-slope). 

Cultural resources: Archaeological sites, architectural structures or features, traditional use 

areas, and Native American sacred sites or special-use areas that provide evidence of the 

prehistory and history of a community. 

Culvert: A pipe or covered channel that directs surface water through a raised embankment or 

under a roadway from one side to the other. 

Cumulative impacts: The impacts assessed in an EIS that could potentially result from 

incremental impacts of the action when added to other past, present, and reasonably foreseeable 

future actions, regardless of what agency (federal or nonfederal), private industry, or individual 

undertakes such other actions. Cumulative impacts can result from individually minor but 

collectively significant actions taking place over a period of time. 

Cut slope: An earthen slope that is cut; for example, a trail built lower than the existing terrain 

would result in a cut slope. 

Dawsonite: Dihydroxy sodium aluminum carbonate; found in the lower portion of the northern 

province of the Piceance Basin; can be used as a source of alumina. 

Decibel (dB): A standard unit for measuring the loudness or intensity of sound. In general, a 

sound doubles in loudness with every increase of 10 decibels. 

Decibel, A-weighted (dBA): A measurement of sound approximating the sensitivity of the 

human ear and used to characterize the intensity or loudness of a sound. 

Decommissioning: All activities necessary to take out of service and dispose of a facility after 

its useful life. 

Demographics: Specific population characteristics such as age, gender, education, and income 

level. 

Dendritic drainage pattern: In hydrologic terms, the form of the drainage pattern of a stream 

and its tributaries when it follows a treelike shape, with the main trunk, branches, and twigs 

corresponding to the main stream, tributaries, and subtributaries, respectively, of the stream. 

Dermal: Of or pertaining to the skin. 

Desert scrub: Community characterized by plants adapted to seasonally dry climate. 

Dewater: To remove or drain water from an area. 
Final OSTS PEIS 9-8 

Dewatering: Removal or separation of a portion of the water in a sludge or slurry to dry the 

sludge so that it can be handled and disposed of; removing or draining the water from a tank or 

trench. 

Dielectric fluids: Fluids that do not conduct electricity. 

Diluents: Light petroleum liquids used to dilute bitumen and heavy oil so that they can flow 

through pipelines. 

Direct impact: An effect that results solely from the construction or operation of a proposed 

action without intermediate steps or processes. Examples include habitat destruction, soil 

disturbance, and water use. 

Disseminated: Occurring as scattered particles in the rock. 

Downwarp: A downward bend or gradual sinking of land with respect to its previous level. 

Ecological refugium: See Refugium. 

Ecological resources: Fish, wildlife, plants, biota, and their habitats, which may include land, 

air, and/or water. 

Ecoregion: A geographically distinct area of land that is characterized by a distinctive climate, 

ecological features, and plant and animal communities. 

Ecosystem: A group of organisms and their physical environment interacting as an ecological 

unit. 

Electromagnetic fields (EMFs): Fields that surround both large power lines that distribute 

power and the smaller electric lines in homes and appliances. Generated when charged particles 

(e.g., electrons) are accelerated. EMFs are typically generated by alternating current in electrical 

conductors. They may also be referred to as EM fields. 

Electromagnetic interference: Any electromagnetic disturbance that interrupts, obstructs, or 

otherwise degrades or limits the effective performance of electrical equipment. It is caused by 

the presence of electromagnetic radiation. 

Emergency Planning and Community Right-to-Know Act (EPCRA): This Act requires 

emergency release notification, hazardous chemical inventory reporting, and toxic chemical 

release inventory reporting by facilities, depending on the chemicals stored or used and their 

amounts. 

Emissions: Substances that are discharged into the air from industrial processes, vehicles, and 

living organisms. 

Empirical: Based on experimental data rather than theory. 
Final OSTS PEIS 9-9 

Endangered species: Any species (plant or animal) that is in danger of extinction throughout all 

or a significant part of its range. Requirements for declaring a species endangered are found in 

the ESA. 

Endangered Species Act of 1973 (ESA): Requires consultation with the USFWS and/or the 

National Marine Fisheries Service to determine whether endangered or threatened species or 

their habitats will be impacted by a proposed activity and what, if any, mitigation measures are 

needed to address the impacts. 

Endemic: Unique to a particular region. 

Environmental Assessment (EA): A concise public document that a federal agency prepares 

under NEPA to provide sufficient evidence and analysis to determine whether a proposed action 

requires preparation of an EIS or whether a Finding of No Significant Impact can be issued. An 

EA must include brief discussions on the need for the proposal, the alternatives, the 

environmental impacts of the proposed action and alternatives, and a list of agencies and persons 

consulted. 

Environmental Impact Statement (EIS): A document required of federal agencies by NEPA 

for major proposals or legislation that will or could significantly affect the environment. 

Environmental justice: The fair treatment of people of all races, cultures, incomes, and 

educational levels with respect to the development, implementation, and enforcement of 

environmental laws, regulations, and policies. 

Ephemeral stream: A stream that flows only after a storm or during snowmelt, and whose 

channel is, at all times, above the water table; groundwater is not a source of water for the 

stream. Many desert streams are ephemeral. 

Epicenter: The point on the earth’s surface that is directly over the focus of an earthquake. 

Erosion: The wearing away of the land surface by running water, wind, ice, or other geologic 

agents. 

Escarpments: The topographic expression of a fault. 

Estate lands: See Split estate lands. 

Evaporite: A sedimentary rock formed when a saline solution evaporates. Evaporites are 

typically formed when a saline lake dries up or due to evaporation in tidal marshes in hot, arid 

climates. 

Evapotranspiration: The loss of water from the soil both by evaporation and by transpiration 

from the plants growing in the soil. 
Final OSTS PEIS 9-10 

Executive Order: A President’s or Governor’s declaration that has the force of law usually 

based on existing statutory powers and requiring no action by the Congress or state legislature. 

http://www.legal-explanations.com/definitions/executive-order.htm 

Exotic species: A plant or animal that is not native to the region where it is found. 

Exploration and Mining Activity (on BLM land): Exploration refers to exploring for minerals 

by way of drilling, trenching, etc. Mining refers to the extraction and processing of minerals. 

Exploration and mining activities on BLM-managed lands are regulated under 

43 CFR Part 3809, which provides for three levels of activity. The first, causal use, requires no 

contact with the BLM. The second, a notice, is filed for activities that disturb less than 5 acres 

unreclaimed per calendar year. The third, a plan of operations, is filed for activities that exceed 

5 acres unreclaimed per calendar year. Plans of operation require BLM approval and are subject 

to NEPA. 

Exposure pathway: The path from sources of pollutants via soil, water, or food, to man and 

other species or settings. 

Extant: Currently existing. 

Extensive Recreation Management Areas: All BLM-administered lands outside Special 

Recreation Management Areas. These areas may include developed and primitive recreation sites 

with minimal facilities. 

Extirpation: The elimination of a species or subspecies from a particular area, but not from its 

entire range. 

Federal Cave Resources Protection Act of 1988: Sets forth policy that public lands will be 

managed to secure, protect, and preserve significant caves. 

Federal land: Land owned by the United States, without reference to how the land was acquired 

or which federal agency administers the land. See also Public land. 

Federal Land Policy and Management Act of 1976 (FLPMA): Act requiring the Secretary of 

the Interior to issue regulations to manage public lands and the property located on those lands 

for the long term. 

Federal Mine Safety and Health Act of 1977: Act requiring the U.S. Department of Labor’s 

(DOL’s) Mine Safety and Health Administration (MSHA) to inspect all mines each year to 

ensure safe and healthy work environments for miners. 

Feedstock: Raw material required for an industrial process. 

Flare: A control device that burns hazardous materials to prevent their release into the 

environment; may operate continuously or intermittently, usually on top of a stack. 
Final OSTS PEIS 9-11 

Fledging success: The average number of offspring fledged (i.e., raised until they leave the nest) 

per female. 

Floaters: Nonbreeding adult and subadult birds that move and live within a breeding population. 

Floodplain: Mostly level land along rivers and streams that becomes covered by water when the 

river overflows its banks. 

Flora: Plants, especially those of a specific region, considered as a group. 

Fluvial: Pertaining to a river; fluvial sediments are deposited by rivers. 

Fly ash: Small particles of airborne ash produced by burning fossil fuels. Fly ash is expelled as 

noncombustible airborne emissions or recovered as a by-product for commercial use (e.g., as a 

replacement for Portland cement used in concrete). 

Flyway: A concentrated, predictable flight path of migratory bird species from their breeding 

ground to their wintering area. 

Forbs: Nonwoody plants that are not grasses or grasslike. 

Fragmentation of habitat: The breaking up of a single large habitat area such that the 

remaining habitat patches are smaller and farther apart from each other. 

Frost heave: Expansion in soil volume due to the formation of ice. It is generally expressed as 

an upward movement of the ground surface. 

Fugitive dust: The dust released from activities associated with construction, manufacturing, or 

transportation. 

Gallinaceous birds: Heavy-bodied, largely ground-feeding domestic or game birds, including 

chickens, pheasants, turkeys, grouse, partridges, and quail. 

Geologic resources: Material of value to humans that is extracted (or is extractable) from solid 

earth, including minerals, rocks, and metals; energy resources; soil; and water. 

Geology: The science that deals with the study of the materials, processes, environments, and 

history of the earth, including the rocks and their formation and structure. 

Geotechnical: Related to the use of scientific methods and engineering principles to analyze and 

predict the behavior of earth materials. Geotechnical engineers deal with soil and rock 

mechanics, foundation engineering, ground movement, deep excavation, and related work. 

Geothermal energy: Energy that is generated by the heat of the earth’s own internal 

temperature. Sources of geothermal energy include molten rock, hot springs, geysers, steam, and 

volcanoes. 
Final OSTS PEIS 9-12 

Geothermal production: Electricity produced from the heat energy of the earth. This energy 

may be in the form of steam, hot water, or the thermal energy contained in rocks at great depths. 

The BLM leases geothermal rights to explore for and produce geothermal resources from federal 

lands or from subsurface mineral rights held by the government. 

Gilsonite: A form of natural asphalt found in large amounts only in the Uintah Basin of Utah. 

Discovered in the 1860s, it was first marketed as a lacquer, electrical insulator, and 

waterproofing compound about 25 years later by Samuel H. Gilson. 

Grazing permits and leases (on BLM land): A grazing permit authorizing grazing of a 

specified number and class of livestock within a grazing district on a designated area of land 

during specified seasons each year. A grazing lease authorizes the grazing of livestock on public 

land outside grazing districts during a specified period of time. Grazing privileges are measured 

in terms of animal unit months. 

Groundwater: The supply of water found beneath the earth’s surface, usually in porous rock 

formations (aquifers), which may supply wells and springs. Generally, it refers to all water 

contained in the ground. 

Habitat: The place, including physical and biotic conditions, where a plant or animal lives. 

Halite: Common table salt, NaCl. 

Hazardous air pollutants (HAPs): See Air toxics. 

Hazardous material: Any material that poses a threat to human health and/or the environment. 

Hazardous materials are typically toxic, corrosive, ignitable, explosive, or chemically reactive. 

Hazardous Material Transportation Law: This law (Title 49, Sections 5101–5127 of the 

United States Code) is the major transportation-related statute affecting transportation of 

hazardous cargoes. Regulations include The Hazardous Materials Table (49 CFR 172.101), 

which designates specific materials as hazardous for the purpose of transportation, and 

Hazardous Materials Transportation Regulations (49 CFR Parts 171180), which establish 

packaging, labeling, placarding, documentation, operational, training, and emergency response 

requirements for the management of shipments of hazardous cargos by aircraft, vessel, vehicle, 

or rail. 

Hazardous waste: By-products of society that can pose a substantial or potential hazard to 

human health or the environment when improperly managed. Possesses at least one of four 

characteristics (ignitability, corrosivity, reactivity, or toxicity), or appears on special EPA lists. 

Hedonic statistical framework: A method of assessing the impact of various structural (number 

of bedrooms, bathrooms, square footage, age, etc.) and locational attributes (local amenities, 

fiscal conditions, distance to workplace, etc.) on residential housing prices. 

Herbaceous plants: Nonwoody plants. 
Final OSTS PEIS 9-13 

Hertz (Hz): The unit of measurement of frequency, equivalent to one cycle per second. 

Historic properties: Any prehistoric or historic districts, sites, buildings, structures, or objects 

included in, or eligible for inclusion in, the National Register of Historic Places (NRHP) 

maintained by the Secretary of the Interior. They include artifacts, records, and remains that are 

related to and located within such properties. 

Historic site: The site of a significant event, prehistoric or historic activity, or structure or 

landscape (existing or vanished), where the site itself possesses historical, cultural, or 

archeological value apart from the value of any existing structure or landscape. 

Hydrocarbon: Any compound or mix of compounds, solid, liquid or gas, composed of carbon 

and hydrogen (e.g., coal, crude oil, and natural gas). 

Hydrology: The study of water that covers the occurrence, properties, distribution, circulation, 

and transport of water, including groundwater, surface water, and rainfall. 

Hypolimnetic: The deeper, cooler portions of a reservoir or lake that result from stratification. 

(Stratification refers to the division of water in lakes and ponds into layers with different 

temperatures and oxygen content). 

Impact: The effect, influence, alteration, or imprint caused by an action. 

Impact-producing factor: An activity or process that causes impacts to the environmental or 

socioeconomic setting, such as water use, surface disturbance, numbers of employees hired, or 

solid and liquid waste generation. 

Impoundment: A body of water or sludge confined by a dam, dike, floodgate, or other barrier. 

An impoundment is used to collect and store water for future use. 

Incidental take: To harass, harm, wound, or kill threatened or endangered species as an 

unintentional consequence of project construction or operations. 

Indigenous: Native to an area. 

Indirect impact: An effect that is related to but removed from a proposed action by an 

intermediate step or process. An example would be changes in surface water quality resulting 

from soil erosion at construction sites. 

Infrasound: Sound waves below the frequency range that can be heard by humans (about 1 to 

<20 Hz). Infrasound can often be felt, or sensed as a vibration, and can cause motion sickness 

and other disturbances. 

Infrastructure: The basic facilities, services, and utilities needed for the functions of an 

industrial facility or site. 
Final OSTS PEIS 9-14 

In situ: In its original place; unmoved, unexcavated; remaining at the site or in the subsurface. 

In situ processing: Processing that liquefies and mobilizes the kerogen (oil shale) or bitumen 

(tar sands) in place by circulating a heated working medium such as gas, superheated water, or 

steam, or by using underground electric heaters. 

Interbedded: Alternating layers of different character. 

Intermittent streams: A stream that flows most of the time but occasionally is dry or reduced to 

a pool stage when losses from evaporation or seepage exceed the available streamflow. 

Intermontane: Between or surrounded by mountains. 

Invasive species: Any species, including noxious and exotic species, that is an aggressive 

colonizer and can outcompete indigenous species. 

Isochronal: Recurring at regular intervals; of equal time. 

Joint: A fracture or parting in rock, without movement. 

Just-in-time ordering strategy: A strategy for managing materials used at a project that ensures 

materials become available as needed to support activities but are not stockpiled at the project 

location in excess of what is needed at any point in time. The just-in-time approach controls 

costs by avoiding the accumulation of inflated inventories, reducing the potential for stockpiled 

materials to go out of date or otherwise become obsolete, and minimizing product storage and 

management requirements. When applied to hazardous chemicals, this approach reduces waste 

generation, the potential for mismanagement of materials, and the overall risk of adverse impacts 

resulting from emergency or off-normal events involving those materials. 

Kerogen: The hydrocarbon in oil shale. Kerogen is a pyrobitumen, and oil is formed from 

kerogen by heating. It consists chiefly of low forms of plant life; chemically it is a complex 

mixture of hydrocarbon compounds of large molecules, containing hydrogen, carbon, oxygen, 

nitrogen, and sulfur. Kerogen is the chief source of oil in oil shales. 

Lacustrine: Pertaining to a lake. Lacustrine sediments are deposited in lakes. 

Lands with wilderness characteristics (LWC): Under Section 201 of FLPMA, the BLM has an 

ongoing obligation to maintain an inventory of all public lands and their resources and other 

values. Through this inventory process, the BLM has identified certain lands as having 

wilderness characteristics. 

Laydown area: An area that has been cleared for the temporary storage of equipment and 

supplies. To ensure accessibility and safe maneuverability for transport and off-loading of 

vehicles, laydown areas are usually covered with rock and/or gravel. 
Final OSTS PEIS 9-15 

Ldn: The day-night average sound level. It is the average A-weighted sound level over a 24-hour 

period that gives additional weight to noise that occurs during the night (10:00 p.m. to 

7:00 a.m.). 

Leachate: A liquid that results from water collecting contaminants as it trickles through wastes, 

agricultural pesticides, or fertilizers. Leaching may occur in farming areas, feedlots, and landfills 

and may result in hazardous substances entering surface water, groundwater, or soil. 

Leaching: The process by which soluble substances are dissolved and transported down through 

the soil by recharge. 

Lead: A gray-white metal that is listed as a criteria air pollutant. Health effects from exposure to 

lead include brain and kidney damage and learning disabilities. Sources include leaded gasoline 

and metal refineries. 

Lease: A contract in legal form that provides for the right to develop and produce resources 

within a specific area for a specific period of time under certain agreed-upon terms and 

conditions. 

Lek: A traditional site that is used year after year by males of certain bird species for communal 

display as they compete for female mates. Leks are generally areas supported by low, sparse 

vegetation or open areas surrounded by sagebrush that provide escape, feeding, and cover. 

Leq: Equivalent/continuous sound level. Leq is the steady sound level that would contain the 

same total sound energy as the time-varying sound over a given time. 

Limestone: A sedimentary rock consisting of more than 50% calcium carbonate (CaCO3). 

Listed species: Any species of fish, wildlife, or plant that has been determined, through the full, 

formal ESA listing process, to be either threatened or endangered. 

Losing streams: Streams that seem to disappear because they flow into an aquifer. 

Low-frequency sound: Sound waves with a frequency in the range of 20 to 80 Hz. The range of 

human hearing is approximately 20 to 20,000 Hz. 

Mahogany Zone: The Mahogany Zone (Parachute Member) in the Piceance Creek Basin 

consists of kerogen-rich strata and averages 100 to 200 ft thick. This zone extends to all margins 

of the basin and is the richest oil shale interval in the stratigraphic section. 

Management Framework Plan (MFP): A land use plan that establishes land use allocations, 

multiple use guidelines, and management objectives for a given planning area. The MFP 

planning system was used by the BLM until about 1980. 

Marlstone: An earthy or impure argillaceous limestone. 
Final OSTS PEIS 9-16 

Marsh: A wetland where the dominant vegetation is nonwoody plants, such as grasses, as 

compared with a swamp where the dominant vegetation is woody plants, such as trees and 

shrubs. 

Mechanical noise: Noise caused by the vibration or rubbing of mechanical parts. 

Mesic: Refers to a habitat that is neither wet or dry; intermediate in moisture, without extremes. 

Mesocyclone: A cyclonically rotating vortex, around 2 to 6 mi in diameter, in a convective 

storm. 

Mineral Leasing Act of 1920 (MLA): Authorizes the agency to issue rights-of-way grants for 

oil and gas gathering and distribution pipelines and related facilities not already authorized 

through a lease, and oil and natural gas transmission pipelines and related facilities. 

Mineral materials (salable): For BLM-managed land, these are defined as minerals such as 

common varieties of sand, gravel, pumice, and clay that are not obtainable under the mining or 

leasing law, but that can be obtained through purchase or free use permit under the Materials Act 

of 1947, as amended. 

Mitigation: A method or process by which impacts from actions can be made less injurious to 

the environment through appropriate protective measures. Also called mitigative measure. 

Monocline: An open, step-like fold in rock over a large area. 

Montane: A section of a mountainous region below the timberline, characterized by cool, moist 

temperatures and dominated by evergreen trees. 

Mudflat: A flat sheet of mud between the high- and low-tide marks. Also, the flat bottoms of 

lakes, rivers, and ponds, largely filled with organic deposits, freshly exposed by a lowering of the 

water level. 

Nahcolite: Sodium bicarbonate or baking soda (NaHCO3). 

National Ambient Air Quality Standards (NAAQS): Air quality standards established by the 

CAA, as amended. The primary NAAQS specify maximum outdoor air concentrations of criteria 

pollutants that would protect the public health within an adequate margin of safety. The 

secondary NAAQS specify maximum concentrations that would protect the public welfare from 

any known or anticipated adverse effects of a pollutant. 

National Conservation Areas: Areas designated by Congress to provide for the conservation, 

use, enjoyment, and enhancement of certain natural, recreational, paleontological, and other 

resources, including fish and wildlife habitat. 
Final OSTS PEIS 9-17 

National Environmental Policy Act of 1969 (NEPA): Requires federal agencies to prepare a 

detailed statement on the environmental impacts of their proposed major actions significantly 

affecting the quality of the human environment. 

National Historic Preservation Act of 1996, as Amended (NHPA): Requires federal agencies 

to take into account the effects of their actions on historical and archaeological resources and 

consider opportunities to minimize their impacts. 

National Historic Trails: These trails are designated by Congress under the National Trails 

System Act of 1968 and follow, as closely as possible, on federal land, the original trails or 

routes of travel with national historical significance. 

National Landscape Conservation System (NLCS): Created by the BLM in June 2000 to 

increase public awareness of BLM lands with scientific, cultural, educational, ecological, and 

other values. It consists of National Conservation Areas, National Monuments, Wilderness 

Areas, Wilderness Study Areas, Wild and Scenic Rivers, and National Historic and Scenic 

Trails. 

National Monument: An area owned by the federal government and administered by the 

National Park Service, the BLM, and/or U.S. Forest Service for the purpose of preserving and 

making available to the public a resource of archaeological, scientific, or aesthetic interest. 

National monuments are designated by the president, under the authority of the American 

Antiquities Act of 1906, or by Congress through legislation. 

National Natural Landmark: An area of national significance, designated by the Secretary of 

the Interior or the Secretary of Agriculture, that contains outstanding examples of the nation’s 

natural heritage. 

National Outstanding Natural Areas: Areas of public land that are either congressionally or 

administratively designated on the basis of their exceptional, rare, or unusually natural 

characteristics. 

National Parks: Public lands set aside by an act of Congress because of their unique physical 

and/or cultural value to the nation as a whole. These lands are administered by the National Park 

Service. 

National Pollutant Discharge Elimination System (NPDES): A federal permitting system 

controlling the discharge of effluents to surface water and regulated through the CWA, as 

amended. 

National Recreation Area: An area designated by Congress to conserve and enhance certain 

natural, scenic, historic, and recreational values. 

National Recreation Trails: Trails designated by the Secretary of the Interior or the Secretary 

of Agriculture that are reasonably accessible to urban areas and meet criteria established in the 

National Trails System Act. 
Final OSTS PEIS 9-18 

National Register of Historic Places: A comprehensive list of districts, sites, buildings, 

structures, and objects that are significant in American history, architecture, archaeology, 

engineering, and culture. The National Register is administered by the National Park Service, 

which is part of the U.S. Department of the Interior. 

National Scenic Trails: These trails are designated by Congress and offer maximum outdoor 

recreation potential and provide enjoyment of the various qualities—scenic, historical, natural, 

and cultural—of the areas through which these trails pass. 

National Wild and Scenic River: A river or river section designated by Congress or the 

Secretary of the Interior, under the authority of the Wild and Scenic Rivers Act of 1968, to 

protect outstanding scenic, recreational, and other values and to preserve the river or river section 

in its free-flowing condition. 

National Wildlife Refuge System: A designation for certain protected areas in the 

United States, managed by the USFWS, that includes all lands, waters, and interests therein 

administered by the USFWS as wildlife refuges, wildlife ranges, wildlife management areas, 

waterfowl production areas, and other areas for the protection and conservation of fish, wildlife, 

and plant resources. 

Native American Graves Protection and Repatriation Act: This Act established the priority 

for ownership or control of Native American cultural items excavated or discovered on federal or 

tribal land after 1990 and the procedures for repatriation of items in federal possession. The Act 

allows the intentional removal from or excavation of Native American cultural items from 

federal or tribal lands only with a permit or upon consultation with the appropriate tribe. 

Nitrogen dioxide (NO2): A toxic reddish brown gas that is a strong oxidizing agent, produced 

by combustion (as of fossil fuels). It is the most abundant of the oxides of nitrogen in the 

atmosphere and plays a major role in the formation of ozone. 

Nitrogen oxides (NOx): Nitrogen oxides include various nitrogen compounds, primarily 

nitrogen dioxide and nitric oxide. They form when fossil fuels are burned at high temperatures 

and react with volatile organic compounds to form ozone, the main component of urban smog. 

They are also a precursor pollutant that contributes to the formation of acid rain. Nitrogen oxides 

are one of the six criteria air pollutants specified under Title I of the CAA. 

Noise Control Act of 1972: Requires that noise levels of facilities or operations not jeopardize 

public health and safety. States are authorized to establish their own noise levels. 

Nominal (measurement): A design value, based on experience and generally reflecting 

accepted industry practice. A nominal value (e.g., depth of a tower foundation) may change 

depending on the conditions at a specific location. 

Nonattainment area: The EPA’s designation for an air quality control region (or portion 

thereof) in which ambient air concentrations of one or more criteria pollutants exceed NAAQS. 
Final OSTS PEIS 9-19 

Nonenergy leasables: All solid nonenergy minerals that private entities produce under leases 

issued by the BLM. These entities pay royalties to the federal government based on the value of 

the mineral they produce. Most of these minerals are used in industry and include sodium, 

bicarbonate, and potash. 

Non-point-source contaminant: Forms of diffuse pollution caused by sediment, nutrients, and 

organic and toxic substances originating from land use activities; these substances are carried to 

lakes and streams by surface runoff. Non-point-source pollution is contamination that occurs 

when rainwater, snowmelt, or irrigation water washes off plowed fields, city streets, or suburban 

backyards. As this runoff moves across the land surface, it picks up soil particles and pollutants, 

such as nutrients and pesticides. 

No Surface Occupancy (NSO): A fluid mineral leasing stipulation that prohibits occupancy or 

disturbance on all or part of the lease surface in order to protect special values or uses. Lessees 

may develop the oil and gas or geothermal resources under leases restricted by this stipulation 

through use of directional drilling from sites outside the no surface occupancy area. 

Noxious plants/noxious weeds: Those plants regulated by law or those that are so difficult to 

control that early detection is important. 

Occupational Safety and Health Administration (OSHA): Congress created OSHA under the 

Occupational Safety and Health Act on December 29, 1970. Its mission is to prevent workrelated injuries, illnesses, and deaths. 

Off-highway vehicle (OHV): Any motorized vehicle capable of or designed for travel on or 

immediately over land, water, or other natural terrain. 

Offsets: Reductions in emissions that are caused by an activity not directly related to the source 

creating the emissions. Offsets are used to stabilize total emissions in a particular area. 

Oil and gas leasing (on BLM land): The BLM leases oil and gas rights to explore for and 

produce oil and gas resources from federal lands or mineral rights owned by the federal 

government. Federal oil and gas leases may be obtained and held by any adult citizen of the 

United States. 

Oil shale: A term used to cover a wide range of fine-grained, organic-rich sedimentary rocks. 

Oil shale does not contain liquid hydrocarbons or petroleum as such but organic matter derived 

mainly from aquatic organisms. This organic matter, kerogen, may be converted to oil through 

destructive distillation or exposure to heat. 

Oil Shale, Tar Sands, and Other Strategic Unconventional Fuels Act of 2005: As part of the 

Energy Policy Act of 2005, Congress declared that oil shale and tar sands (and other 

unconventional fuels) are strategically important domestic energy resources that should be 

developed to reduce the nation’s growing dependence on oil from politically and economically 

unstable foreign sources. 
Final OSTS PEIS 9-20 

Organism: Any form of plant or animal life. 

Outwash plain: A smooth plain covered by deposits from water flowing from glaciers. 

Overburden: The surface soil that must be moved away to get at coal seams and mineral 

deposits.

Ozone (O3): A strong-smelling, reactive toxic chemical gas consisting of three oxygen atoms 

chemically attached to each other. It is formed in the atmosphere by chemical reactions involving 

NOx and volatile organic compounds. The reactions are energized by sunlight. Ozone is a criteria 

air pollutant under the CAA and is a major constituent of smog. 

Paleontological resources: Fossilized remains, imprints, and traces of plants and animals 

preserved in rocks and sediments since some past geologic time. 

Paleontology: The study of plant and animal life that existed in former geologic times, 

particularly through the study of fossils. 

Particulate matter: Fine solid or liquid particles, such as dust, smoke, mist, fumes, or smog, 

found in air or emissions. The size of the particulates is measured in micrometers (μm). One 

micrometer is 1 millionth of a meter, or 0.000039 inch. Particle size is important because the 

EPA has set standards for PM2.5 and PM10 particulates. 

Parturition areas: Birthing areas commonly used by more than a few female members of a 

population. Generally used when referring to ungulates, such as elk and mule deer. 

Passerines: Perching birds or songbirds. 

Perennial streams: Streams that flow continuously. 

Permissible exposure limit (PEL): The maximum amount or concentration of a chemical that a 

worker may be exposed to under OSHA regulations. 

Permit: A revocable authorization to use public land for a specified purpose for up to 3 years. 

(BLM glossary). 

Personal protective equipment (PPE): Clothing and equipment that are worn to reduce 

exposure to potentially hazardous chemicals and other pollutants. 

Petroglyphs: Carvings in rock that express artistic or religious meaning. 

Photovoltaic system: A system that converts light into electric current. 

Phreatophytic: Relating to deep-rooted plants that obtain water from a permanent ground 

supply or from the water table. 
Final OSTS PEIS 9-21 

Physiography: The physical geography of an area or the description of its physical features. 

Pigs: Devices routinely introduced into pipelines to clean the inner wall of the pipe and monitor 

for critical conditions that could compromise the integrity or efficiency of the pipeline, such as 

cracks, corrosion, and pipe deformations. 

Planetary boundary layer: The bottom layer of the atmosphere that is in contact with the 

surface of the earth. Within this layer, the effects of friction are significant. It is roughly the 

lowest 1 or 2 km of the atmosphere. 

Plateau: A large, flat area of land that is higher than the surrounding land. 

Playa: A dry, vegetation-free area in the bottom of an undrained desert basin. It may contain 

deposits of clay, silt, or sand and, frequently, soluble salts of sodium, calcium, potassium, etc. 

Playa lake: A shallow, intermittent lake in an arid or semiarid region. It occupies a playa and 

may dry up in the summer. 

PM10: Particulate matter with a mean aerodynamic diameter of 10 m (0.0004 in.) or less. 

Particles less than this diameter are small enough to be deposited in the lungs. PM10 is one of the 

six criteria air pollutants specified under Title I of the CAA. 

PM2.5: Particulate matter with a mean aerodynamic diameter of 2.5 m (0.0001 in.) or less. 

Policy: A plan of action adopted by an organization. 

Pollutant: Any material entering the environment that has undesired effects. 

Polychlorinated biphenyls (PCBs): A group of manufactured organic compounds made up of 

carbon, hydrogen, and chlorine. They were used in the manufacture of plastics and as insulating 

fluids for electrical equipment. Because they are very stable and fat-soluble, they accumulate in 

ever-higher concentrations as they move up the food chain. Their use was banned in the 

United States in 1979. 

Polycyclic aromatic hydrocarbons (PAHs): Aromatic hydrocarbons containing more than one 

fused benzene ring. PAHs are a carcinogenic component of the tar sands and oil shale. PAHs are 

commonly formed during the incomplete burning of coal, oil and gas, garbage, or other organic 

substances. 

Population: A group of individuals of the same species occupying a defined locality during a 

given time that exhibit reproductive continuity from generation to generation. 

Potable water: Water that can be used for human consumption. 
Final OSTS PEIS 9-22 

Preference right lease areas: In the context of the BLM’s ongoing oil shale research, 

development, and demonstration (RD&D) program, an area reserved by the holder of an RD&D 

lease for future leasing for the commercial development of oil shale, subsequent to review and 

approval by the BLM.

Prevention of Significant Deterioration (PSD) Program: An air pollution permitting program 

intended to ensure that air quality does not diminish in attainment areas. 

Processing technologies: See Retorting. 

Programmatic Agreement: A document that records the terms and conditions agreed upon to 

resolve the potential adverse effects of a federal agency program, complex undertaking, or other 

situations in accordance with Section 800.14(b), “Programmatic Agreements,” of 36 CFR 

Part 800, “Protection of Historic Properties.” 

Public land: Any land and interest in land (outside of Alaska) owned by the United States and 

administered by the Secretary of the Interior through the BLM. 

Public Land Order (PLO): An order affecting, modifying, or canceling a withdrawal or 

reservation that has been issued by the Secretary of the Interior pursuant to powers of the 

President delegated to the Secretary by Executive Order 9146 of April 24, 1942, or 9337 of 

April 24, 1943. 

Putrescible waste: Solid waste that contains organic matter that can rot or decompose. 

Pyrolysis: Chemical decomposition by the action of heat. 

Raptor: Bird of prey. 

Reasonably Foreseeable Future Action: A projection of activities (industrial and minerals 

development, recreational activities and development, wildlife management, air and water 

resource management, urban development, transportation, etc.) within a defined geographic area 

and for a specified time frame. Reasonably foreseeable future actions are defined by available 

information on resource occurrences, past and present activities or uses and trends, economics, 

existing project proposals and other reliable indications of anticipated activities, and other 

identified factors specific to the area of analysis. 

Recharge: The addition of water to an aquifer by natural infiltration (e.g., rainfall that seeps in 

to the ground) or by artificial injection through wells. 

Reclamation: Returning disturbed lands to a form and productivity that will be ecologically 

balanced and in conformity with a predetermined land management plan. 
Final OSTS PEIS 9-23 

Recreation Opportunity Spectrum (ROS) Class: A tool commonly used by federal land 

management agencies to determine the level of development, the types of facilities that are 

appropriate, and the type of recreational opportunities that one will experience. Six recreation 

opportunity classes have been developed: primitive, semiprimitive nonmotorized, semiprimitive 

motorized, roaded natural, rural, and urban. 

Refugium: An area where special environmental circumstances have enabled a species or a 

community of species to survive after extinction in surrounding areas. 

Region of influence (ROI): Consists of the counties in each of the three states (Colorado, Utah, 

and Wyoming) in which each oil shale and tar sands resource is located. 

Relict: A remnant or fragment of the vegetation of an area that remains from a former period 

when the vegetation was more widely distributed. 

Research Natural Areas: Areas designated or set aside by Congress or by a public or private 

agency to protect natural features or processes for scientific and educational purposes. 

Resource Conservation and Recovery Act (RCRA): Regulates the storage, treatment, and 

disposal of hazardous and nonhazardous wastes. 

Resource Management Plan (RMP): A land use plan that establishes land use allocations, 

multiple use guidelines, and management objectives for a given planning area. The RMP 

planning system has been used by the BLM since about 1980. 

Retort: A device or process used for extraction or distillation of valuable resources from 

complex mixtures. In oil shale processing, a retort is a mechanical device in which mined and 

sized oil shale is heated to cause the pyrolysis of its kerogen organic fraction to produce organic 

liquids known as raw shale oil. 

Retorting: Processing technologies for separating valuable resources from their parent ores or 

extracting them from their natural settings. Retorting of oil shale involves removing kerogen 

from the oil shale, usually by burning or heating the shale, and subsequent chemical conversion 

of the kerogen into synthetic crude oils. Retorting can be carried out in surface vessels (surface 

retorting) or underground in fractured shale. Chemical treatment processes also may be applied. 

Aboveground retorting (AGR) technologies are used to process mined oil shale; the retorting 

processes are typically preceded by a variety of pretreatment activities, including crushing, 

sizing, and sorting. By-products of aboveground retorting of oil shale include flammable lowmolecular weight organic gases and “spent shale” (that which is left of the original oil shale after 

kerogen has been removed). 

Riffle: A rapid, turbulent flow of water over a shallow area in a stream. Riffles add oxygen to the 

water as water is churned and provide habitat for many invertebrates. 

Right-of-way (ROW): A legal right of passage over another person’s land; public land 

authorized to be used or occupied pursuant to a ROW grant. 
Final OSTS PEIS 9-24 

Right-of-way corridor: A designated parcel of land, either linear or areal in character, that has 

been identified through the land use planning process as the preferred location for existing and 

future ROW grants and would accommodate more than one type of ROW or one or more ROWs 

that are similar, identical, or compatible. 

Right-of-way grant: The authorization to use a particular parcel of public land for specific 

facilities for a definite time period; authorizes the use of a ROW over, upon, under, or through 

public lands for construction, operation, maintenance, and termination of a project. 

Riparian: Relating to, living in, or located on the bank of a river, lake, or tidewater. 

Rolling footprint: Development that occurs incrementally so that, at any given time, some 

portion of a lease area is involved in active development, another portion is involved in 

preparation for a future development phase, another portion is undergoing restoration after 

development, and the remainder of the lease area is essentially undeveloped. Ultimately, the 

entire lease will be developed and then restored, but the amount of acreage that is disturbed at 

any given time is a subset of the entire lease. 

Room-and-pillar entries: Refers to a system of mining in which typically flat-lying beds of coal 

or ore are removed from haulage-ways (entries) and selected areas called rooms. Pillars of 

unmined coal are left between the rooms to support the roof. 

Run-of-mine: Refers to ore in its natural, unprocessed state; pertaining to ore just 

as it is mined. 

Safe Drinking Water Act (SDWA): This Act authorizes development of maximum 

contaminant levels for drinking water applicable to public water systems (i.e., systems that serve 

at least 25 people or have at least 15 connections). 

Salt: Any compound formed by the reaction of an acid and a base. The sodium salts formed in 

saline lakes are typically the reaction products of carbonic acid (H2CO3) with sodium derived 

from the weathering of any number of minerals containing sodium. Carbonic acid is formed 

when atmospheric carbon dioxide dissolves in water. 

Sandstone: A sedimentary rock composed primarily of sand-sized (0.0025 to 0.08 in.) grains. 

Savannah: A flat grassland of tropical and subtropical regions usually having distinct periods of 

dry and wet weather. 

Scrubbers: Any of several forms of chemical/physical devices that remove sulfur compounds 

formed during coal combustion. 

Section 7 of the Endangered Species Act: Requires all federal agencies, in “consultation” with 

the USFWS, to ensure that their actions are not likely to jeopardize the continued existence of 

listed species or result in destruction or adverse modification of critical habitat. 
Final OSTS PEIS 9-25 

Sedges: Perennial nonwoody plants that resemble grasses in that they have relatively narrow 

leaves. They are common to most freshwater wetlands. 

Sediment: Materials that sink to the bottom of a body of water, or materials that are deposited by 

wind, water, or glaciers. 

Sedimentary rock: Rock formed at or near the earth’s surface from the consolidation of loose 

sediment that has accumulated in layers through deposition by water, wind, or ice, or deposited 

by organisms. Examples are sandstone and limestone. 

Sedimentation: The removal, transport, and deposition of sediment particles by wind or water. 

Seeps: Wet areas, normally not flowing, arising from an underground water source. Any place 

where liquid has oozed from the ground to the surface. 

Seismic: Pertaining to any earth vibration, especially that of an earthquake. 

Sensitive species: A plant or animal species listed by the state or federal government as 

threatened, endangered, or as a species of special concern. The list of BLM-sensitive species 

varies from state to state, and the same species can be considered sensitive in one state but not in 

another. 

Seral: The state of development in ecological succession. 

Shakedown tests: Tests conducted to demonstrate that equipment is operational and meets 

performance requirements. 

Shale oil: A crude liquid hydrocarbon obtained from oil shale by distillation. The shale oil may 

be refined into normal petroleum products such as gasoline and diesel fuel. 

Shortite: Sodium calcium carbonate [Na2Ca2(CO3)3]. 

Shrub steppe: Habitat composed of various shrubs and grasses. 

Silt: Sedimentary material consisting of fine mineral particles intermediate in size between sand 

and clay. 

Siltation: The deposition or accumulation of silt. 

Siltstone: A sedimentary rock composed primarily of silt-sized (0.00016 to 0.0025 in.) grains. 

Slash: Any treetops, limbs, bark, abandoned forest products, windfalls, or other debris left on the 

land after timber or other forest products have been cut. 
Final OSTS PEIS 9-26 

Sludge: A dense, slushy, liquid-to-semifluid product that accumulates as an end result of an 

industrial or technological process designed to purify a substance; A semisolid residue from any 

of a number of air or water treatment processes; can be a hazardous waste. 

Solid Waste Disposal Act: An act that regulates the treatment, storage, or disposal of solid, both 

hazardous and nonhazardous waste, as amended by RCRA and the Hazardous and Solid Waste 

Amendments of 1984. 

Sound pressure level: The level, in decibels, of acoustic pressure waves. Very loud sounds have 

high sound pressure levels; soft sounds have low sound pressure levels. A 3-dB increase in sound 

doubles the sound pressure level. Zero decibels is the threshold of human hearing. The maximum 

level of human hearing is around a 120-dB sound pressure level, which is the level where people 

begin to experience pain because of the high sound pressure levels. 

Special areas: Areas of high public interest and containing outstanding natural features or 

values. BLM special areas include National Wild and Scenic Rivers, National Wildernesses, 

National Conservation Areas, National Scenic Areas, National Recreation Areas, National 

Monuments, National Outstanding Natural Areas, National Historic Landmarks, National 

Register of Historic Places, National Natural Landmarks, National Recreational Trails, National 

Scenic Trails, National Historic Trails, National Backcountry Byways, Areas of Critical 

Environmental Concern, Research Natural Areas, Important Bird Areas, United Nations 

Biosphere Reserves, and World Heritage Sites. 

Special Recreation Management Areas (SRMAs): An area that possesses outstanding 

recreation resources or where recreation use causes significant user conflicts, visitor safety 

problems, or resource damage. 

Special Status species: Includes both plant and animal species that are proposed for listing, are 

officially listed as threatened or endangered, or are candidates for listing as threatened or 

endangered under the provisions of the ESA; those listed by a state in a category such as 

threatened or endangered, implying potential endangerment or extinction; and those designated 

by each BLM State Director as sensitive. 

Species of Special Concern: A species that may have a declining population, limited 

occurrence, or low numbers for any of a variety of reasons. 

Spent shale: By-product of aboveground retorting of oil shale, that is, what is left of the original 

oil shale after kerogen has been removed; spent shale is typically disposed of as a waste or used 

in reclamation of the oil shale mine. 

Split estate lands: Lands where the owner of the mineral rights and the surface owner are not 

the same party in interest. The most common split estate is federal ownership of mineral rights 

and other-interest ownership of the surface. The federal government can lease the oil and gas 

rights without surface owner consent, where such a condition occurs. 
Final OSTS PEIS 9-27 

Spoilbank: A pile of soil, subsoil, rock, or other material excavated from a drainage ditch, pond, 

or other cut. A deposit at the surface of the mine of mined material (e.g., coal). 

State Historic Preservation Officer (SHPO): The state officer charged with the identification 

and protection of prehistoric and historic resources in accordance with the National Historic 

Preservation Act. 

State Implementation Plan (SIP): A plan for controlling air pollution and air quality in that 

state; each state must develop its own regulations to monitor, permit, and control air emissions 

within its boundaries.

Steppe: See Shrub-steppe. 

Stipulation: A provision that modifies standard lease rights and is attached to and made a part of 

the lease. 

Strata: Single, distinct layers of sediment or sedimentary rock. 

Strategic Petroleum Reserve (SPR): The largest stockpile of government-owned emergency 

crude oil in the world. It was established in 1975 in the aftermath of the 19731974 oil embargo 

to provide emergency crude oil supplies for the United States. The oil is stored in underground 

salt caverns in Texas and Louisiana. 

Stratification: Separating into layers. Stratification refers to the division of water in lakes and 

ponds into layers with different temperatures and oxygen content. 

Stratigraphy, subsurface: The arrangement (in layers) of different types of geologic materials 

located below the surface of an area. 

Subalpine: The growing or living conditions in mountainous regions just below the timberline. 

Substation: Consists of one or more transformers and their associated switchgear. A substation 

is used to switch generators, equipment, and circuits or lines in and out of a system. It is also 

used to change ac voltages from one level to another. 

Sulfur dioxide (SO2): A gas formed from burning fossil fuels. Sulfur dioxide is one of the six 

criteria air pollutants specified under Title I of the CAA. 

Sulfur oxides (SOx): Pungent, colorless gases that are formed primarily by fossil fuel 

combustion. Sulfur oxides may damage the respiratory tract, as well as plants and trees. 

Surface mining: Removal of a mineral by stripping off the overburden, removing the mineral, 

and then replacing the overburden and topsoil. 

Surface retorting: See Retorting.
Final OSTS PEIS 9-28 

Surface water: Water on the earth’s surface that is directly exposed to the atmosphere, as 

distinguished from water in the ground (groundwater). 

Switchgear: A group of switches, relays, circuit breakers, etc., used for controlling distribution 

of power to other distribution equipment and large loads. 

Syncline: A downward, trough-shaped configuration of folded, stratified rocks. 

Syncrude: Synthetic crude oil. 

Talus: Rock debris accumulated at the base of the cliff or slope from which they have broken 

off. 

Tar sands: Also referred to as “oil sand” or “bituminous sand,” tar sand is a sedimentary 

material composed primarily of sand, clay, water (in some deposits) and organic constituents 

known as bitumen. Processing of tar sands involves separating the bitumen fraction from the 

inorganic materials and subsequently upgrading the bitumen through a series of reactions to 

produce a synthetic crude oil feedstock that is suitable for further refining into distillate fuels in 

conventional refineries. 

Terrace: A step-like surface, bordering a valley floor or shoreline, that represents the former 

position of a floodplain, lake, or seashore. 

Terrestrial: Belonging to or living on land. 

Thermal maturity: The amount of heat, in relative terms, to which a rock has been subjected. A 

thermally immature rock has not been subjected to enough heat to begin the process of 

converting kerogen to oil and/or gas. A thermally overmature rock has been subjected to enough 

heat to convert it to graphite. These are the two extremes, and there are many intermediate stages 

of thermal maturity. 

Threatened species: Any species that is likely to become an endangered species within the 

foreseeable future throughout all or a significant portion of its range. Requirements for declaring 

a species threatened are contained in the ESA. 

Timing limitations (seasonal restriction): Prohibits surface use during specified time periods to 

protect identified resource values. The stipulation does not apply to the operation and 

maintenance of production facilities unless the findings of analysis demonstrate that there is the 

continued need for such mitigation and that less stringent, project-specific mitigation measures 

would be insufficient. 

Topography: The shape of the earth’s surface; the relative position and elevations of natural and 

human-made features of an area. 

Total dissolved solids (TDS): The dry weight of dissolved material, organic and inorganic, 

contained in water. The term is used to reflect salinity. 
Final OSTS PEIS 9-29 

Total Maximum Daily Load (TMDL): The sum of the individual wasteload allocations for 

point sources, load allocations for non-point sources and natural background, plus a margin of 

safety. TMDLs can be expressed in terms of mass per time, toxicity, or other appropriate 

measures that relate to a state’s water quality standard. 

Toxic Substances Control Act (TSCA): An Act authorizing the EPA to secure information on 

all new and existing chemical substances and to control any of these substances determined to 

cause an unreasonable risk to public health or the environment. 

Transformer: A device for transferring electric power from one circuit to another in an 

alternating current system. Transformers are also used to change voltage from one level to 

another. 

Transponder: A device that transmits and responds to radio waves. 

Trona: Soda ash; a major source of sodium minerals [Na2(CO3)(HCO3)2H2O]. 

Turbidity: A measure of the cloudiness or opaqueness of water. Typically, the higher the 

concentration of suspended material, the greater the turbidity. 

Understory species: Plants that grow beneath a forest canopy. 

Unfossiliferous: Not fossil bearing. 

Undissected: A plateau or other relatively level surface that has not been deeply cut by streams. 

U.S. Environmental Protection Agency (EPA): The independent federal agency, established in 

1970, that regulates federal environmental matters and oversees the implementation of federal 

environmental laws. 

Valid existing rights: Legal interests that attach to a land or mineral estate that cannot be 

divested from the estate until that interest expires or is relinquished. 

Viewshed: The total landscape seen or potentially seen from all or a logical part of a travel route, 

use area, or water body. 

Visitor days: One visitor day equals 12 visitor hours at a site or area. 

Visual impact: The creation of an intrusion or perceptible contrast that affects the scenic quality 

of a landscape. 

Visual Resource Management (VRM) classes: VRM classes identify the degree of acceptable 

visual change within a particular landscape. A classification is assigned to public lands based on 

the guidelines established for scenic quality, visual sensitivity, and visibility (see Section 3.8). 
Final OSTS PEIS 9-30 

Visual Resource Management System: Procedures and methods that support decision-making 

for planning activities and reviews of proposed developments on BLM-administered lands. 

Visual resources: Refers to all objects (man-made and natural, moving and stationary) and 

features such as landforms and water bodies that are visible on a landscape. 

Vitrinite: A type of organic material found in coal. 

Vitrinite reflectance (R0): A measure of the percentage of incident light reflected from a 

polished surface of vitrinite. It is a measure of the thermal maturity of a sedimentary rock 

containing kerogen. It is an indicator of whether a source rock has been heated enough to 

produce oil, oil and gas, or gas only. 

Volatile organic compounds (VOCs): A broad range of organic compounds that readily 

evaporate at normal temperatures and pressures. Sources include certain solvents, degreasers 

(benzene), and fuels. Volatile organic compounds react with other substances (primarily nitrogen 

oxides) to form ozone. They contribute significantly to photochemical smog production and 

certain health problems. 

Wastewater: Water that typically contains less than 1% concentration of organic hazardous 

waste materials. 

Water quality: The condition or purity of water with respect to the amount of impurities in it. 

Watershed: An area from which water drains to a particular body of water. Watersheds range in 

size from a few acres to large areas of the country. 

Wetlands: Areas that are soaked or flooded by surface or groundwater frequently enough or 

long enough to support plants, birds, animals, and aquatic life. Wetlands generally include 

swamps, marshes, bogs, estuaries, and other inland and coastal areas and are federally protected. 

Wild and Scenic Rivers (WSR) Act: Primary river conservation law enacted in 1968. The Act 

was specifically intended by Congress to balance the existing policy of building dams on rivers 

for water supply, power, and other benefits, with a new policy of protecting the free-flowing 

character and outstanding values of other rivers. 

Wild Horse and Burro Act: Act passed by Congress in 1971 giving BLM the responsibility to 

protect, manage, and control wild horses. 

Wild Horse and Burro Adoption Program: BLM program that offers excess animals for 

adoption to qualified people. After caring for an animal for 1 year, the adopter is eligible to 

receive title, or ownership, from the federal government. 
Final OSTS PEIS 9-31 

Wild horses and burros: Unbranded and unclaimed horses or burros roaming free on public 

lands in the western United States and protected by the Wild Free-roaming Horse and Burro Act 

of 1971. They are descendants of animals turned loose by, or escaped from, ranchers, 

prospectors, Indian Tribes, and the U.S. cavalry from the late 1800s through the 1930s. 

Wilderness Areas: Areas designated by Congress and defined by the Wilderness Act of 1964 as 

places “where the earth and its community are untrammeled by man, where man himself is a 

visitor who does not remain.” Designation is aimed at ensuring that these lands are preserved and 

protected in their natural condition. 

Wilderness Study Areas (WSAs): Areas designated by a federal land management agency as 

having wilderness characteristics, thus making them worthy of consideration by Congress for 

wilderness designation. 

Wind rose: Weather map showing the frequency and strength of winds from different directions. 

A wind rose for use in assessing consequences of airborne releases also shows the frequency of 

different wind speeds for each compass direction. 

Xeric: Low in moisture. 

 
Final OSTS PEIS 9-32 

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Final OSTS PEIS A-1 

APPENDIX A: 

OIL SHALE DEVELOPMENT BACKGROUND AND TECHNOLOGY OVERVIEW 
Final OSTS PEIS A-2 

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Final OSTS PEIS A-3 

APPENDIX A: 

OIL SHALE DEVELOPMENT BACKGROUND AND TECHNOLOGY OVERVIEW 

 This appendix describes the geology of the oil shale resource area, the resource, and the 

history of oil shale development in the western United States, and it provides an overview of the 

technologies that have been applied to oil shale development. Technologies that may be 

employed in future developments on U.S. Department of the Interior (DOI), Bureau of Land 

Management (BLM)-administered lands are introduced. Technologies that are addressed in the 

Draft Programmatic Environmental Impact (PEIS) and Possible Land Use Plan Amendments for 

Allocation of Oil Shale and Tar Sands Resources on Lands Administered by the Bureau of Land 

Management in Colorado, Utah, and Wyoming include those used for recovery (i.e., mining), 

processing (i.e., retorting and pyrolysis of the hydrocarbon fraction), and upgrading of oil shale 

resources.1 Assumptions regarding these technologies were developed to support analyses in the 

PEIS and are also presented in this appendix. Finally, Attachment A1 provides an analysis of 

how the refinery industry may adjust to the availability of syncrude feedstocks derived from oil 

shale. 

Currently, there is no commercial production of oil from oil shale being undertaken in the 

United States. While recently there has been a great deal of interest in the potential of oil shale 

resources, utilization of this material is still in the research and development mode. Recent 

technological developments have proven to be of great interest, and those developments, along 

with technologies that were developed during the last wave of interest in oil shale, are now being 

considered for application in tapping this potential resource. 

 Development of oil shale resources is expected to proceed gradually and to be led by 

activities on the nine sites located in Colorado and Utah (see Section 1.4.1 of the main text of 

the PEIS) that are included in the BLM’s oil shale research, development, and demonstration 

(RD&D) program. Chapter 9 of the PEIS provides a glossary of technical terms, including 

geologic terms, used in the PEIS and its appendices. 

A.1 DESCRIPTION OF GEOLOGY 

Oil shale is a term used to cover a wide range of fine-grained, organic-rich sedimentary 

rocks. Oil shale does not contain liquid hydrocarbons or petroleum as such but organic matter 

derived mainly from aquatic organisms. This organic matter, kerogen, may be converted to oil 

through destructive distillation or exposure to heat. 

 

1 Retorting and pyrolysis are key steps in oil shale processing. Retorting is a process that causes thermal 

decomposition of the organic fraction of the oil shale (kerogen). The recovered organic fraction is then distilled, 

or pyrolyzed, to produce three products: crude shale oil, flammable gases (including hydrogen), and char 

(deposited on spent shale). These processes are described further in Section A.3.2. 
Final OSTS PEIS A-4 

Numerous deposits of oil shale are found in the United States. The most prospective shale 

deposits are contained within sedimentary deposits of the lacustrine Green River Formation of 

Eocene age. These deposits exist in the greater Green River Basin (including Fossil Basin and 

Washakie Basin) in southwestern Wyoming and northwestern Colorado, the Piceance Basin in 

northwestern Colorado, and the Uinta Basin in northeastern Utah.2 Because of the deposits’ size 

and grade, most investigations have focused on the oil shale deposits in these basins. As 

discussed in Section 1.2 of the main text of the PEIS, in defining the scope of analysis for the 

PEIS, the BLM identified the most geologically prospective areas for oil shale development on 

the basis of the grade and thickness of the deposits. For the purposes of this PEIS, the most 

geologically prospective oil shale resources in Colorado and Utah are defined as those deposits 

that are expected to yield 25 gal of shale oil per ton of rock (gal/ton) and are 25 ft thick or 

greater. In Wyoming, where the oil shale resource is not of as high a quality as it is in Colorado 

and Utah, the most geologically prospective oil shale resources are those deposits that are 

expected to yield 15 gal/ton or more shale oil and are 15 ft thick or greater. Figure A-1 shows the 

Green River Formation basins, which were mapped on the basis of the extent of the Green River 

Formation, and the most geologically prospective oil shale resources within those basins.3 

In addition to limiting the scope of analyses to the most geologically prospective 

resources, the BLM has determined that, for the purposes of establishing a commercial leasing 

program for oil shale development on public lands, oil shale resources that are covered by more 

than 500 ft of overburden would not be available for application for leasing using surface mining 

technologies under the scope of this PEIS. This limitation is based on the assumption that 500 ft 

is about the maximum amount of overburden where surface mining can occur economically, 

using today’s technologies. Figure A-1 shows the areas within the three-state region where 

surface mining would be considered under the commercial leasing program on the basis of the 

overburden thickness.4 Although some of the oil shale resources outcrop in Colorado and have 

overburden thicknesses of less than 500 ft, the distribution of these areas presents a relatively 

 

2 The Piceance Basin is not referred to or described consistently in published literature. Some publications 

describe the Piceance Basin as an area encompassing more than 7,000 mi2 and consisting of a northern province 

and a southern province, separated approximately by the Colorado River and Interstate 70 (I-70). Other 

publications refer to the southern province as the Grand Mesa Basin. Oil shale is present in both provinces, with 

the richest oil shale deposits in the north, and smaller, isolated deposits in the south. Various authors have used 

the terms “Piceance Basin” and “Piceance Creek Basin” to refer to either the overall basin or the northern area. 

In this PEIS, the focus is on the northern province, where the richest and thickest reserves are located, and the 

study area will be referred to as the “Piceance Basin.” 

3 Numerous sources of information were used to define the boundaries of the Green River Formation basins and 

the most geologically prospective oil shale resources. The basin boundaries were defined by digital data 

provided by the U.S. Geological Survey (USGS) taken from Green (1992), Green and Drouillard (1994), and the 

Utah Geological Survey (2000). The most geologically prospective oil shale resources in the Piceance Basin 

were defined on the basis of digital data provided by the USGS taken from Pitman and Johnson (1978), Pitman 

(1979), and Pitman et al. (1989). In Wyoming, the most prospective oil shale resources were defined on the basis 

of detailed analyses of available oil shale assay data (Wiig 2006a,b). In Utah, the most prospective oil shale 

resources were defined by digital data provided by the BLM Utah State Office. 

4 The areas within the most geologically prospective oil shale areas where the overburden is 0 to 500 ft thick were 

mapped on the basis of a variety of sources of information. In Colorado, the area was defined on the basis of data 

published in Donnell (1987). In Utah, the area was mapped on the basis of data provided by the Utah Geological 

Survey (Tabet 2007). In Wyoming, the area was mapped on the basis of data provided by Wiig (2006a,b). 
Final OSTS PEIS A-5 

FIGURE A-1 Green River Formation Basins in Colorado, Utah, and Wyoming; Most 

Geologically Prospective Oil Shale Resources; Areas Where the Overburden above the Oil Shale 

Resources is ≤500 ft 
Final OSTS PEIS A-6 

narrow band of lands within which it would be difficult to assemble a logical mining unit; 

therefore, surface mining projects in Colorado are not evaluated in this PEIS. 

A.1.1 Depositional Environment 

 The Green River Formation was originally deposited in two basins that were later warped 

into four large structural basins and then elevated several thousand feet above mean sea level 

(MSL). The major streams and their tributaries traversing the region have eroded much of the 

sediments from these exhumed basins. The stream erosion has exposed the oil shale on cliffs 

and ledges in many places. Gentle folds and minor faults deform the deposits locally, but the 

sedimentary rocks of the oil shale areas as a whole are remarkably undisturbed structurally. 

Exceptions occur in the areas where the strata are steeply tilted on the flanks of the Uinta Mountains 

in Utah and Wyoming and along the Grand Hogback in Colorado. 

Lacustrine sediments of the Green River Formation that have become oil shale were 

deposited in two large lakes that occupied 24,000 mi2 in several sedimentary structural basins in 

Colorado, Wyoming, and Utah during early through middle Eocene time (40 to 65 million years 

ago). These basins are separated by the Uinta Mountain uplift and its eastward extension, the 

Axial Basin anticline. The Green River lake system was in existence for more than 

10 million years during a time of a warm-temperate to subtropical climate. The two large lakes 

initially were freshwater but became quite saline with time. 

Fluctuations in the amount of inflowing stream waters caused large changes in the areal 

extent of the lakes as evidenced by widespread intertonguing of marly (clay and carbonate-rich) 

lacustrine strata with beds of land-derived sandstone and siltstone. During arid times, the lakes 

contracted in size and the lake waters became increasingly saline and alkaline. The lake-water 

content of soluble sodium carbonates and chloride increased, while the less soluble calcium, 

magnesium, and iron carbonates were precipitated with organic-rich sediments. 

During the driest periods, the lake water reached salinities sufficient to precipitate the 

sodium minerals nahcolite, halite, and trona. The water filling the pore spaces in the sediments 

was also sufficiently saline to precipitate disseminated crystals of nahcolite, halite, and 

dawsonite along with a host of other carbonate and silicate minerals (Milton 1977). In Wyoming 

(Lake Gosiute), trona was precipitated. In Colorado (Lake Uinta), the minerals halite, nahcolite, 

and dawsonite were precipitated. Why the two lakes precipitated different mineral salts is 

unknown, but the resulting deposits of trona, nahcolite, and dawsonite constitute an immense 

potential mineral supply. 

The warm, alkaline waters of the Eocene Green River lakes provided excellent conditions 

for the abundant growth of blue-green algae (cyanobacteria) that is thought to be the major 

precursor of the organic matter in the oil shale. During times of freshening waters, the lakes 

hosted a variety of fishes, rays, bivalves, gastropods, ostracods, and other aquatic fauna. Areas 

peripheral to the lakes supported a large and varied assemblage of land plants, insects, 

amphibians, turtles, lizards, snakes, crocodiles, birds, and numerous mammals (McKenna 1960; 
Final OSTS PEIS A-7 

MacGinitie 1969; Grande 1984). These areas where saline minerals are intermixed with oil shale 

are referred to in this document as “multimineral zones.” 

A.1.2 Piceance Basin, Colorado 

The Piceance Basin is located mainly in the Colorado Plateau physiographic province. 

The overall basin is more than 100 mi long and 60 mi wide, with an area more than 7,000 mi2. 

The Piceance Basin is simultaneously a structural, depositional, and drainage basin. The 

structural basin is downwarped and surrounded by uplifts resulting from the Laramide Orogeny. 

This tectonic activity created a depositional basin that filled with sediments from the surrounding 

uplands, mainly during the Tertiary period. The basin has a northern province and a southern 

province (Topper et al. 2003) separated approximately by the Colorado River and I-70. Oil shale 

is present in both provinces. 

Within the Piceance Basin, the upper bedrock stratigraphy consists of a series of basinfill sediments from the Tertiary period (Topper et al. 2003). The uppermost unit is the Uinta 

Formation, which consists of up to 1,400 ft of Eocene-age sandstone, siltstone, and marlstone. 

Below the Uinta Formation is the Eocene Green River Formation, which can be up to 5,000 ft 

thick and includes four members: the Parachute Creek (keragenous dolomitic marlstone and 

shale), the Anvil Points (shale, sandstone, and marlstone), the Garden Gulch (claystone, 

siltstone, clay-rich oil shale, and marlstone), and the Douglas Creek (siltstone, shale, and 

sandstone). The Eocene-Paleocene Wasatch Formation underlies the Green River Formation 

and is approximately 6,900 ft thick near the town of Rifle, Colorado. Exposed Wasatch rocks 

include clays and shales with some interbedded sandstone and are found in the lowest elevations 

between the base of the cliffs and the major streams (the Colorado River, Government Creek, 

and Parachute Creek). The Wasatch Formation is a significant oil and natural gasproducing 

unit in the region. Below the Wasatch are the Cretaceous Mesaverde Group (sandstone and 

shale), the Cretaceous Mancos Shale, and older sedimentary formations atop Precambrian rock. 

The Mesaverde Group is the major oil- and gas-producing formation in the Piceance Basin. 

The main oil shale members of interest in the Piceance Basin are the Parachute Creek and 

Garden Gulch Members. The grade of oil shale varies with location and depth, but the Parachute 

Creek Member has the richest material and includes the Mahogany Zone. 

Elsewhere in the region, the Grand Hogback exposes Paleozoic and Mesozoic 

sedimentary bedrock units that dip steeply to the west and southwest. Tertiary basalt flows cover 

much of the higher-elevation areas south of the Colorado River (i.e., Battlement Mesa) and the 

White River Plateau to the northeast. Quaternary alluvium occurs as a broad belt along the lower 

reaches of Parachute, Rifle, and Government Creeks and along the Colorado River 

(Widmann 2002). Quaternary alluvium of varying thickness is present in the significant 

drainages of the basin. 

Although the oil shale deposits in Colorado cover the smallest geographical area, they are 

the richest, thickest, and best-known deposits. In addition, natural gas production is prolific from 

formations located stratigraphically below the oil shale, with 4 of the top 35 natural gas fields in 
Final OSTS PEIS A-8 

the United States located in the southern Piceance Basin. 

Substantial quantities of saline minerals (halite, dawsonite, and 

nahcolite) are intermixed or intermingled with oil shale in certain 

zones in the northern half of the basin. Three layers of nahcolite 

are present near the base of this saline zone, and two halitebearing strata exist in the upper part of the zone. The dawsonite 

and other saline minerals are finely disseminated in and 

associated with beds of oil shale, which are up to 700 ft thick 

near the center of the basin. Dyni (1974) estimated the total 

nahcolite resource at 29 billion tons. Beard et al. (1974) 

estimated nearly the same amount of nahcolite and 17 billion 

tons of dawsonite. Both minerals have value for soda ash and 

aluminum, respectively. Dawsonite has potential value for its 

alumina content and most likely would be recovered as a byproduct of an oil shale operation. One company is presently 

solution mining about several hundred thousand tons/yr of 

nahcolite in the northern part of the Piceance Basin at depths of 

about 1,970 ft (Day 1998). The BLM has identified an area in the 

Piceance Basin, referred to as the Multimineral Zone, where 

development of nahcolite, dawsonite, or oil shale cannot result in 

destruction of another resource. 

About 80% of the potential oil shale resources of the 

Green River Formation, or about 1.2 trillion bbl of oil equivalent, 

is found in west-central Colorado’s Piceance Basin. Of the total 

potential resource, about 480 billion bbl are contained in deposits 

averaging at least 25 gal/ton. The higher-grade shale sections 

range from 10 ft to more than 2,000 ft in thickness and may be 

covered with overburden ranging up to 1,600 ft thick. 

A.1.3 Uinta Basin, Utah 

In Utah, oil shale deposits are found in the Parachute Creek 

Member of the Green River Formation, which intertongues with 

but generally occurs above the Douglas Creek Member. As many 

as eight oil shale zones have been identified in the Parachute 

Creek Member; the richest oil shale is found in the Mahogany 

Zone, which contains up to 100 ft or more of rock that averages 

15 gal/ton. Figure A-2 is a generalized stratigraphic section of 

the rich and lean oil shale zones of the Parachute Creek Member 

of the Green River Formation in the Uinta Basin, Utah. The 

thickness of the different zones shown in the stratigraphic section 

is not constant but varies across the basin. No single 

comprehensive and modern study of the oil shale resources of the 

entire Uinta Basin has been carried out. An early study of the 

FIGURE A-2 Generalized 

Stratigraphic Section of the 

Parachute Creek Member of 

the Green River Formation in 

the Uinta Basin, Utah (“R” = 

rich oil shale zone; “L” = lean 

oil shale zone [adapted from 

Young 1995])
Final OSTS PEIS A-9 

Uinta Basin (Cashion 1967), based on less data than are available today, yielded a potential 

resource estimate for the Mahogany Zone that is at least 15 ft thick and contains an average yield 

of at least 25 gal/ton of 26.8 billion bbl (Table A-1). A more recent study (Trudell at al. 1973), 

based on a greater amount of drilling data but limited to the southeastern portion of the Uintah 

Basin, estimated that within the Mahogany Zone, which is at least 25 ft thick and contains an 

average of 25 gal/ton, there is a resource of at least 31 billon bbl (Table A-2). This upward 

resource revision indicates that the early estimate provided by Cashion (1967) is conservative, 

and that more work is necessary to comprehensively define the oil shale resource potential of the 

entire Uinta Basin. 

A major fault, the Uinta Basin boundary fault, lies in the subsurface near the northern 

margin of the Uinta Basin (Campbell 1975). In the Wasatch Plateau along the western margin of 

the Uinta-Piceance Province, several north-south fault systems that are an eastward extension of 

basin and range-style tectonism disrupt the geologic units. The Uinta Basin is filled by as much 

as 17,000 ft of Upper Cretaceous and Paleogene lacustrine and fluvial sedimentary rocks 

(Bradley 1925; Cashion 1967; Fouch 1985). On the Douglas Creek arch, which separates the 

Uinta Basin from the Piceance Basin, the Green River Formation has been eroded away. 

Uppermost Cretaceous and lowermost Tertiary strata dip 4 to 6 toward the axis of the Uinta 

Basin. The younger Uinta and Duchesne River Formations of late Eocene to earliest Oligocene 

age dip less steeply. The Green River Formation reaches a maximum depth of 20,000 ft along the 

basin axis in the north-central part of the Uinta Basin. The Green River Formation lies below the 

Altamont-Bluebell oil field (Fouch et al. 1994). The Green River Formation contains significant 

oil- and gas-producing reservoirs in the Uinta Basin, including those at Altamont-Bluebell, 

Cedar Rim, Brundage Canyon, Monument Butte, Eight Mile Flat North, Uteland Butte, Pariette 

Bench, Natural Buttes, Horseshoe Bend, and Red Wash fields. The eastern Uinta Basin also 

hosts significant gas-producing reservoirs in deeper Tertiary and Cretaceous reservoirs over 

much of the same area containing valuable oil shale deposits in the Green River Formation. 

Conflicts with conventional oil and gas development in the Uinta Basin may be an obstacle to the 

future development of Utah’s oil shale deposits. 

TABLE A-1 Estimated In-Place Oil Shale Resources in the Southeastern Portion of 

the Uinta Basin Based on a Minimum Thickness of 15 ft and Various Expected Yields 

(in gal/ton)a

Green River Formation 

Mahogany Zone Acreage 

Average Resource 

(bbl/acre) 

Total In-Place Resource 

(million bbl) 

 

At depths <3,000 ft below the surface 

 Average yield of 30 gal/ton 293,787 63,485 18,651 

 Average yield of 25 gal/ton 361,990 74,093 26,821 

 Average yield of 15 gal/ton 426,507 117,126 49,955 

a 1 bbl shale oil = 42 gal. 

Source: Cashion (1967); higher yield portions are subsets of the 15 gal/ton resource. 
Final OSTS PEIS A-10 

TABLE A-2 Estimated In-Place Oil Shale Resources in the Southeastern Portion of the 

Uinta Basin Based on a Minimum Expected Yield of 25 gal/ton and a Minimum Thickness 

of 25 fta

Green River Formation Acreage 

Average Resource 

(bbl/acre) 

Total In-Place Resource 

(million bbl) 

 

At depths <3,000 ft below the surface 

 Parachute Creek Member, Mahogany Zone 410,400 75,707 31,080 

 

Total 31,080 

a 1 bbl shale oil = 42 gal. 

Source: Trudell et al. (1973). 

The largest areal extent of the oil shalebearing Green River Formation occurs in Utah. 

The richest shales in Utah occur in the east-central part of the Uinta Basin, at depths ranging 

from 0 ft at the outcrop to 4,800 ft below the surface. These rich deposits contain more than 

300 billion bbl. The existence of sodium minerals has been shown in a few Utah core holes; the 

extent of these minerals, however, has not been defined. The potential for conflicts between the 

development of sodium minerals and oil shale in the Green River Formation would need to be 

analyzed on a site-specific basis. The eastern Uinta Basin also contains significant deposits of the 

solid hydrocarbon gilsonite, which has been mined there for about 100 years and is processed 

and used in inks, paints, oil well drilling muds and cements, asphalt modifiers, and a wide variety 

of chemical products. These vertical gilsonite dikes strike between 40o and 70o west of north, 

have strike lengths ranging from less than 1 mi to nearly 14 mi, range in width from a fraction of 

1 in. up to 18 ft, and are generally found in the strata above the Green River Formation (Verbeek 

and Grout 1992). Conflicts may exist between the existing development of gilsonite and the 

future development of oil shale in the Uinta Basin. 

A.1.4 Green River and Washakie Basins 

The Eocene Green River Formation of southwestern Wyoming was deposited in 

Lake Gosiute, which occupied parts of the present-day Green River, Fossil Butte, Bridger, Great 

Divide, Washakie, and Sand Wash Basins, which are referred to here as the Green River and 

Washakie Basins, as shown in Figure A-1. Lake Gosiute existed for about 4 to 8 million years 

during Eocene time. The lake history is characterized by two major high-water stands separated 

by a low-water stand; these correspond to the Tipton, Wilkins Peak, and Laney Members of the 

Green River Formation (Bradley 1964). 

Lake Gosiute formed in a basin bounded by uplifted Precambrian, Paleozoic, and 

Mesozoic rocks that were uplifted to form mountains rising to about 6,500 ft above MSL 

(Bradley 1963). Initially, several thousand feet of fluvial sediments were deposited in the basin 

during the Paleocene and early Eocene. These deposits constitute the main body of the Wasatch 
Final OSTS PEIS A-11 

Formation, which probably accumulated on a fairly featureless alluvial plain. Continued downwarping of the basin relative to surrounding mountains caused the area to become poorly 

drained, and Lake Gosiute formed in the center of the basin, gradually expanding to an area of 

several thousand square miles (Bradley 1964). The lacustrine Green River Formation was 

deposited in the central part of the basin and the fluvial Wasatch Formation along the basin 

margins. The two formations interfinger in such a way as to demonstrate three major stages in 

the history of Lake Gosiute. The lower Tipton Member of the Green River Formation was 

deposited during a high stand, when a large, relatively freshwater lake occupied the Basin 

(Bradley 1964; Wolfbauer 1971). The overlying Wilkins Peak Member, however, accumulated 

in a playa-lake complex that occupied a much smaller area (Eugster and Surdam 1973; 

Bradley 1973; Eugster and Hardie 1975). The lake expanded following Wilkins Peak time, and 

the Laney Member of the Green River Formation was deposited during this high-water stand 

(Surdam and Stanley 1979). Lake Gosiute occupied the basin for several million years during the 

early and middle Eocene, and the Laney stage of the lake may have lasted about 1 million years 

on the basis of potassium/argon dating of tuff beds in the Wilkins Peak and Laney reported by 

Mauger (1977). Subsequently, this basin was deformed into the Bridger, Washakie, Great 

Divide, and Sand Wash Basins by post-middle and pre-late Eocene uplifts (Pipiringos 1961). 

Additional oil shale resources are also found in the Washakie Basin east of the Green 

River Basin. Trudell et al. (1973) report that several members of the Green River Formation on 

Kinney Rim on the west side of the Washakie Basin contain sequences of low- to moderategrade oil shale. Two sequences of oil shale in the Laney Member, 36 and 138 ft thick, average 

17 gal/ton and represent as much as 67,908 bbl/acre of in-place shale oil. A total estimate of the 

resource in the Washakie Basin was not reported for lack of subsurface data. 

In general, Wyoming oil shales tend to be thin and of only moderate quality. The oil shale 

beds tend to be almost flat, and each bed shows the same basic characteristics throughout most of 

the deposit. Most of the known Wyoming deposits of higher-grade oil shale occur in the Green 

River Basin and are estimated to contain 30 billion bbl of shale oil. Leaner shales exist over a 

wider area, including the entire Washakie Basin. Overburden depth ranges from 400 to 3,500 ft. 

Trona and halite are associated with or adjacent to the shallow oil shale deposits in the Green 

River Basin of Wyoming; however, the amount and extent of dawsonite and other saline 

minerals have not been established. Tables A-3 and A-4 show estimated oil shale resources of 

the Green River and Washakie Basins, respectively. 

The Wilkins Peak Member of the Green River Formation in the Green River Basin in 

southwestern Wyoming contains not only oil shale but also the world’s largest known resource 

of natural sodium carbonate, known as trona. The trona resource is estimated at more than 

115 billion tons in 22 beds ranging from 4 to 32 ft in thickness (Wiig et al. 1995). In 1997, trona 

production from five mines was 16.5 million tons (Harris 1997). Trona is refined into soda ash, 

which is used in the manufacture of bottle and flat glass, baking soda, soap and detergents, waste 

treatment chemicals, and many other industrial chemicals. One ton of soda ash is obtained from 

about 2 tons of trona ore. Wyoming trona supplies about 90% of U.S. soda ash needs. About 

one-third of the Wyoming soda ash is exported. Natural gas is also present in the Green River oil 

shale deposits in southwestern Wyoming, but in unknown quantities. 
Final OSTS PEIS A-12 

TABLE A-3 Estimated In-Place Oil Shale Resources in the Green River Basin Based on a 

Minimum Expected Yield of 15 gal/ton and a Minimum Thickness of 15 fta,b

Formation Acreagec

Average Resource

(bbl/acre) 

Total In-Place Resource 

(million bbl) 

 

At depths ≤500 ft below the surface 

 Laney Member 147,085 59,912 8,812 

 Wilkins Peak Member 248,003 163,515 40,552 

 Tipton Member 54,247 100,346 5,443 

 

 Total 54,808 

At depths >500 ft and <3,000 ft below the surface 

 Laney Member 670,730 87,725 58,840 

 Wilkins Peak Member 1,105,165 144,943 160,185 

 Tipton Member 1,066,047 138,222 147,351 

 

 Total 366,377 

a 1 bbl shale oil = 42 gal. 

b Totals may be off because of rounding. 

c Total acreages shown do not account for overlap of the classifiable oil shale zones among the different 

formation members. 

Source: Wiig (2006c). 

A.2 HISTORY OF OIL SHALE DEVELOPMENT 

The worldwide history of oil shale applications reaches far back in time. For example, 

Speight (1990) reports that oil shales were sources of fuel as early as 800 A.D., oil shale deposits 

in what is now the British Isles were worked during Phoenician times, and applications of oil 

shale as fuel in Austria have been recorded as early as 1350 A.D. Commercial production of 

shale oil as a fuel is said to have begun in France in 1838 (Kilburn 1976; Speight 1990). 

In the United States, use of oil shale as a fuel is reported to have occurred in the 1800s. 

The first retort for processing oil shale in the United States is reported to have been constructed 

in 1917 near Debeque, Colorado (Kilburn 1976). Mining and processing of oil shale occurred in 

Elko, Nevada, as early as 1921 when the Catlin Oil Company attempted to distill organic 

materials from oil shale with the aid of water from nearby hot mineral springs (Garside and 

Schilling 1979). In collaboration with Shell Oil Company, Fishell developed a detailed 

chronology of oil shale development in western Colorado (interested readers should refer to 

Fishell and Shell Oil Company 2003). A history of the Federal Prototype Oil Shale Leasing 

Program is provided in a report published by the U.S. Congress Office of Technology 

Assessment (OTA) (1980a). The establishment of the U.S. Naval Oil Shale Reserve by the 

U.S. Government was likely the inaugural event in oil shale’s more formally directed and 

extensively documented developmental history. 
Final OSTS PEIS A-13 

TABLE A-4 Estimated In-Place Oil Shale Resources in the Washakie Basin Based on a Minimum 

Expected Yield of 15 gal/ton and a Minimum Thickness of 15 fta,b

Formation Acreagec

Average Resource 

(bbl/acre) 

Total In-Place Resource 

(million bbl) 

 

At depths ≤500 ft below the surface 

 Laney Member 25,218 177,179 4,468 

 Wilkins Peak Member 0 0 0 

 Tipton Member 4,086 31,681 129 

 Luman Tongue 13,636 188,067 2,564 

 

 Total 7,162 

At depths >500 ft and <3,000 ft below the surface 

 Laney Member 184,137 232,802 42,867 

 Wilkins Peak Member 2,893 21,504 62 

 Tipton Member 46,189 36,419 1,682 

 Luman Tongue 52,388 68,199 3,573 

 

 Total 48,184 

a 1 bbl shale oil = 42 gal. 

b Totals may be off because of rounding. 

c Total acreages shown do not account for overlap of the classifiable oil shale zones among the different 

formation members. 

Source: Wiig (2006c). 

The history of the development of oil shale as a commercial fuel in the United States 

is characterized by boom and bust cycles, tied most directly in time to the availability of 

economical supplies of conventional crude oil, both foreign and domestic. The period 

immediately following the Arab Oil Embargo of 1973 is generally considered to be the period 

of most intense interest in oil shale and the period during which the majority of technological 

advancements took place. During this period, numerous projects were undertaken, most 

occurring on government land with government involvement in both technical direction and 

subsidy. When the price and availability of conventional crude oil stabilized around 1982, 

interest in oil shale development dropped precipitously and, with the exception of a few minor 

research ventures, all field activities of a commercial nature, and most complementary 

technology developments, virtually ceased. 

During and immediately after this intense period of oil shale RD&D, numerous 

comprehensive technology evaluations were published, either as progress reports for individual 

government-sponsored projects or as overviews of the industry sector in general. Environmental, 

economic, engineering, and social footprints were exhaustively defined. Operating data from 

pilot plants and laboratory simulation studies were extrapolated to characterize and compute the 

environmental impacts that could be expected from the most probable types and scales of future 
Final OSTS PEIS A-14 

commercial oil shale ventures. Complementary investigations were conducted in laboratories on 

the chemistries of kerogen, the organic fraction of oil shale, and the products of its modification 

to produce conventional fuels through pyrolysis and upgrading activities. Thermodynamics, 

reaction mechanisms, and kinetics of kerogen pyrolysis were defined, and relationships between 

conditions during pyrolysis and the chemical composition of the resulting “crude shale oil” were 

established. 

 With the introduction of mass production of automobiles and trucks in the United States 

in the early 1900s, a temporary shortage of gasoline encouraged the exploitation of oil shale 

deposits for transportation fuels. Many companies were formed to develop the oil shale deposits 

of the Green River Formation in the western United States, especially in Colorado. Thousands of 

oil placer claims were filed on public lands in the western United States. However, the discovery 

and development of large deposits of conventional oil in West Texas led to the demise of these 

early oil shale enterprises by the late 1920s (Dyni 2003). 

In 1967, the DOI began an aggressive program to investigate the commercialization of 

the Green River Formation oil shale deposits. The dramatic increase in petroleum prices resulting 

from the Organization of Petroleum Exporting Countries (OPEC) oil embargo of 1973 triggered 

another resurgence of oil shale activities during the 1970s and into the early 1980s. In 1974, 

several parcels of public lands overlying oil shale resources in Colorado, Utah, and Wyoming 

were put up for competitive bid under the Federal Prototype Oil Shale Leasing Program. Under 

this program, oil companies leased four tracts on public lands (two in Colorado referred to as C-a 

and C-b and two in Utah referred to as U-a and U-b). In addition to these four federal projects, 

several projects were initiated on private lands. These projects are summarized below by state. 

A.2.1 Colorado Activities 

• Atlantic Richfield Company (ARCO), Ashland Oil, Shell Oil, and The Oil 

Shale Corporation (TOSCO) leased Tract C-b, in 1976, following the 

withdrawal of ARCO and TOSCO from the venture, Ashland and Shell 

submitted the first detailed development plan to the Oil Shale Project Office. 

It outlined a conventional underground room-and-pillar method of mining 

with surface retorting of the mined shale. In 1977, after a 1-year suspension to 

resolve technical issues, Shell had dropped out and Occidental Oil Shale, Inc. 

(OOSI) joined Ashland to develop the resource using OOSI’s modified in situ 

(MIS) process. The MIS method of oil shale mining deviated from the plan 

first described and offered enhanced recovery and a possible solution to some 

of the technical problems that formed the basis for suspension. Ashland 

withdrew from the project in April 1979 and Tenneco joined OOSI in 

September 1979 to form the Cathedral Bluffs Oil Shale Company (CBOSC). 

Tract operations began that year. Production, service, and ventilation/escape 

shafts were sunk to a depth of 1,969 ft, holding ponds were completed, and 

office facilities were constructed, along with a mine power substation, natural 

gas supply building, sewage treatment plant, and a manway and utility 

tunnels. In 1981, CBOSC announced a project reassessment, and major plan 
Final OSTS PEIS A-15 

construction was put on hold. In 1983, CBOSC applied for and received 

financial assistance from the U.S. Synthetic Fuels Corporation (SFC), a 

government-funded entity established to foster development of an oil shale 

industry. A revised plan of development was submitted to produce 14,100 bbl 

of shale oil per day. The detailed development plan proposed an underground 

room-and-pillar mine, an aboveground oil shale retort, mine and surface 

processing facilities, and an oil upgrading facility. None of this occurred, 

however. In 1984, SFC board members stepped down, and, as a result, no 

contract with SFC was secured. In 1985, CBOSC continued negotiations with 

SFC. At the same time, a bill was passed in the House to abolish SFC. A 

similar amendment in the Senate failed, 43 to 40. President Reagan signed 

Public Law 99-190, which provided, as part of overall appropriations, for the 

termination of SFC within 120 days, and the rescindment of all funds not yet 

committed. In 1986, negotiations for the suspension of the Tract C-b lease and 

shaft pumping cessation were initiated. The suspension was granted in 1987. 

Pumping on the production and maintenance shafts stopped in 1991, and the 

headframe was removed in 2002. No shale oil was ever produced from this 

federal lease. 

• Occidental Oil Shale, Inc., used the Logan Wash facility as a testing site for 

the MIS process planned at Colorado lease Tract C-b and considered for 

Tract C-a. The 10-mi2 site was purchased from private sources in 1972. 

Mining began in 1972, and by 1981, six retorts were developed and burned 

to produce a total of 94,500 bbl of shale oil. Initial in-situ retorts on the site 

consisted of three experimental-size operations, each producing 1,200 to 

1,600 bbl of shale oil in total. Three considerably larger retorts, Retorts 7, 8, 

and 8x, were constructed at Logan Wash. Retorts 7 and 8 were fired and 

successfully produced nearly 58,300 bbl of shale oil from the 3-year, 

$29 million program. About 450 people were employed at the Logan Wash 

site. 

• Union Oil Company of California began acquiring oil shale properties in 

Colorado around 1921 in the Parachute Creek area of the Piceance Basin north 

of the town of Parachute in Garfield County, Colorado. Union owned the 

mineral rights under nearly 50 mi2 of oil shale lands. From 1955 through 

1958, Union built and operated a surface retort on its Colorado properties. The 

facility produced about 800 bbl of shale oil per day using a unique upflow 

retort process. More than 13,000 bbl of this shale oil were successfully 

processed into gasoline and other products at a Colorado refinery. However, 

low crude oil prices in the 1960s prevented further process development. With 

the rapid rise in price and uncertain availability of foreign crude oil in the 

early 1970s, Union reactivated research and development (R&D) in its upflow 

retorting process. Continuing improvements were made in efficiency and 

product quality. In the fall of 1980, construction began on the first phase of 

Union’s 50,000-bbl/day oil shale facility. The first phase of the project called 

for surface retorting of raw shale retrieved from a room-and-pillar mine. 
Final OSTS PEIS A-16 

Union spent more than $1.2 billon, with substantial financial assistance from 

the federal government. Union began production in 1984 but did not ship its 

first barrel of oil until December 1986. Union was able to produce shale oil 

and upgraded this shale oil to syncrude at its commercial oil shale production 

facility at the Parachute Creek plant. Union began shipping synthetic crude 

from its Parachute Creek plant to a Chicago refinery and was producing about 

6,000 to 7,000 bbl/day in 1989 at its peak production, sustained by a federal 

subsidy. The Parachute Creek plant had approximately 480 workers and 

200 contract employees. The oil shale project was shut down in June 1991. 

• The Exxon-TOSCO Colony Project was established in 1963 as a joint venture 

among Sohio, the Cleveland Cliff Iron Company, and TOSCO. Beginning in 

1965, various companies acquired and sold an interest in the Colony Project, 

resulting by 1980 in ownership by Exxon Corporation (60%) and TOSCO 

(40%). The Colony Project controlled a 22-mi2 resource block. Starting in 

1964 and ending in the early 1970s, approximately 200,000 bbl of shale oil 

were produced experimentally at the TOSCO II Semi-Works Plant. In the 

1960s, a prototype mine and plant operation proved the viability of the 

underground mining plan with aboveground processing using the “TOSCO II” 

retort method. Plans called for the mining of oil shale processed through 

pyrolysis and the upgrading of facilities. Design and engineering work for a 

commercial plant progressed through various stages. The underground mine 

was to be worked with room-and-pillar methods, proceeding with the 

conventional cycle of drilling, charging, blasting, wetting of rock piles, 

loading, hauling, scaling, and roof bolting. Run-of-mine shale was to be 

crushed to the desired retort feed size in two stages. Retorting and upgrading 

facilities would recover upgraded shale oil, ammonia (NH3), sulfur, and coke 

from the crushed shale. Fuels produced for internal combustion would include 

treated fuel gas, a liquid carbon stream, fuel oil, and diesel fuel. The kerogen 

content of raw shale was to be converted into the above hydrocarbon vapors 

and liquids using six individual “TOSCO II” retorting trains. Upgrading 

included coking, gas recovery and treating, and hydrotreating. Exxon planned 

to invest up to $5 billion in a planned 47,000-bbl/day plant using a TOSCO 

retort design. After spending more than $1 billion, Exxon announced on 

May 2, 1982, that it was closing the project and laying off 2,200 workers. No 

shale oil was ever produced commercially. 

• Gulf Oil Company and Standard Oil Company of Indiana leased Federal 

Prototype Oil Shale Tract C-a from the DOI for $210.3 million. Tract C-a was 

the first federal tract to be leased as part of the DOI’s program to test the 

environmental and economic feasibility of oil shale development. Tract C-a 

was located in Rio Blanco County at the head of Yellow Creek on the western 

edge of the Piceance Creek Basin. Gulf and Standard later formed the 

Rio Blanco Oil Shale Company (RBOSC), a 50:50 general partnership, to 

develop the 5,100-acre tract. Originally, Tract C-a was to be developed as an 

open pit mine. However, the DOI did not make additional federal land 
Final OSTS PEIS A-17 

available for off-tract disposal of processed shale and overburden. There were 

also air quality issues and other constraints with the pit mining concept. After 

a 1-year suspension of operations, RBOSC decided to develop the tract by 

underground MIS methods. In February 1979, the company purchased OOSI’s 

MIS technology. In the commercial phase, plans called for shale oil to be 

transported to existing Gulf or Standard corporate refineries. Tract C-a was a 

one-level operating mine, with driftwork essentially completed for three 

underground demonstration retorts. A conventionally sunk production shaft, 

vent shaft, service shaft, and production shaft were built. Approximately 

500 people were employed during the construction phase of this project. In 

October 1980, RBOSC ignited the first of three demonstration MIS retorts. 

The burn was scheduled to last 9 weeks. The demonstration retort was ignited 

at the top, some 670 ft below the earth’s surface. This was the first burn in the 

company’s $140-million program to demonstrate commercial feasibility of the 

MIS technology; 1,750 bbl of oil were recovered from the first retort. Two 

additional burns were conducted in 1981, which recovered approximately 

23,000 bbl of shale oil. The retorts were prematurely flooded in 1984 because 

of pump failure, and the company was unable to resume operations. 

Approximately 150 people were employed during the operational phase of this 

project. 

• TRW, Inc.’s Naval Oil Shale Reserves (NOSR) Project was conducted under 

the direction of the Secretary of Energy and included three sections of land 

known as NOSR 1, 2, and 3. NOSR 1 and 3 were located in Colorado and 

NOSR 2 was located in Utah. In 1977, TRW was chosen to be the prime 

engineering and management contractor for the project, which involved 

performing a 5-year, $62 million resource, technology, environmental, and 

socioeconomic assessment to advise DOE on what should be done with the 

NOSR. The TRW, Inc., team included Gulf Research and Development 

Company, TOSCO, C.F. Braun and Company, and Kaiser Engineers. The 

assessment was to be completed in 1984. In September of 1980, DOE released 

a draft EIS that discussed other fuel alternatives to oil shale and explored five 

NOSR development approaches ranging from leasing to industry to a 

government-owned facility. The report recommended that the biggest return to 

the federal government would be through production of the natural gas 

reserves. 

• Multi Minerals Corporation (MMC), a subsidiary of the Charter Company, 

signed an agreement in April 1979 to operate a U.S. Bureau of Mines research 

tract known as Horse Draw. MMC hoped to offset much of the expense of 

mining oil shale by recovering nahcolite and dawsonite, two potentially 

valuable minerals found within the shale. The company also hoped to prove 

that its Integrated In Situ recovery method was environmentally acceptable; 

this process reportedly did not produce spent shale residue on the surface, nor 

did it use or contaminate surface water. In 1977 and 1978, the U.S. Bureau of 

Mines opened an experimental mine that included a 2,370 ft-deep shaft with 
Final OSTS PEIS A-18 

several room-and-pillar entries in the northern part of the Piceance Basin to 

conduct research on the deeper deposits of oil shale, which are commingled 

with nahcolite and dawsonite. Large-scale process testing began in mid-1981, 

when construction of the company’s adiabatic retort in Grand Junction was 

completed. The company’s experimental mining involved room-and-pillar 

mining in a bedded nahcolite and shale zone about 8 ft thick, averaging about 

60% nahcolite. The shafts were used to obtain geologic and hydrologic data in 

the deeper end of the Piceance Basin. The site was closed in the late 1980s. 

• Equity Oil Company and DOE launched a project known as the BX In Situ 

Oil Shale Project in 1977 to test a method of in situ retorting that frees the 

kerogen from the shale by injecting superheated steam into the permeable 

leached zone underlying a site owned by Equity, Exxon, and Atlantic 

Richfield southwest of Meeker in Rio Blanco County, Colorado. Project field 

tests began in June 1979 and continued for 2 years on a 1-acre site within the 

1,000-acre tract owned by Equity and its partners. Steam injections for a 

sustained period began in June 1980. By August, the formation showed signs 

of continued and steady heating. By August 1981, 625,000 bbl of waterturned-steam had been injected into 8 project wells, and approximately 

100 bbl of shale oil had been recovered. Equity’s principle oil shale interest 

focused on the leached zone; the only zone in the Piceance Basin that has 

native permeability sufficient to initiate in situ recovery without fracturing 

or premining of bedrock. The injected steam process evolved from both 

laboratory and fieldwork begun in the 1960s. These tests used natural gas 

rather than steam. Laboratory results showed that the oil recovered was 

superior in quality to that produced in conventional surface retorts, possibly 

because of lower temperatures and the absence of any oxidizing gases. While 

evaluating the project in 1970, Equity determined that superheated steam 

could be used to lower costs. Beginning in April 1971, the BX project was 

converted to steam, and injections were performed almost continuously until 

the research project was suspended for financial reasons 4 months later. From 

this latest research, Equity determined that water from the leached zone may 

be used, thus eliminating the need to import water. Equity also found that a 

minimum amount of surface disruption results from the construction and 

operation of the process. With only minor alterations, the existing BX oil 

shale site was utilized for the reactivated program in 1977. Achieving the 

needed temperatures and pressures required a reasonably sophisticated steamgenerating plant, water storage facilities, and an instrumentation system to 

monitor both equipment and project performance. 

• Chevron Shale Oil Company’s (Chevron) historic involvement with oil shale 

in Colorado involves the work of three corporations: Chevron Corp, Texaco 

Inc., and Getty Oil Company. Texaco merged with Getty in 1984, and 

Chevron and Texaco merged in 2001. Properties were acquired by the 

companies beginning in the 1930s, and today the combined oil shale acreage 

totals about 100,000 acres in Mesa and Garfield Counties. The lands are 
Final OSTS PEIS A-19 

managed by Chevron Shale Oil Company, a division of Chevron USA, Inc. 

Early work by Chevron was mainly resource evaluation and mapping. In the 

1970s, Chevron and Texaco participated in a consortium of companies that 

supported the Paraho Oil Shale Project at the Anvil Points facility, west of 

Rifle, Colorado. The surface retort produced more than 100,000 bbl of shale 

oil for the U.S. Navy. In 1981, Chevron Shale Oil Company and Conoco 

Shale Oil, Inc., began the Clear Creek project on a 25,000-acre tract of private 

land north of DeBeque. Chevron Shale Oil Company was the operator. The 

goal of the project was to produce 100,000 bbl of shale oil by the mid-1990s. 

The oil shale was to come from an underground mine, which started 

construction in 1981. The company developed a second-generation surface 

retorting process called the Staged Turbulent Bed at its Richmond, California, 

laboratory. Tests were made using a 1-ton/day and a 4-ton/day plant. The next 

phase was the Semi-Works Development Project. A 350-ton/day retort was 

constructed and successfully tested at the Chevron refinery near Salt Lake 

City, Utah. Crushed rock was moved to the retort by rail. A small amount 

of shale oil was produced, but because of the drop in oil prices, mine 

construction was halted in 1984. The commercial phase of the project was 

not reached, and the mine has remained closed. 

A.2.2 Utah Activities 

In Utah, six oil shale projects were planned that progressed to various stages of 

development. The six projects are described below (DOE 1981). From 1954 through 1990, 

several companies and governmental agencies drilled at least 200 oil shale exploration wells in 

the Uinta Basin and conducted Fischer assays on the oil shale core samples. In addition to the 

core samples, the USGS had an oil shale program from the late 1950s through the 1970s that 

collected cutting samples from more than 400 oil and gas wells penetrating the oil shalebearing 

portion of the Green River Formation. Fischer assays also were conducted on those samples. 

Data on the thickness, depth, and Fischer assay information exist for the oil shale interval in the 

Parachute Creek Member of the Green River Formation from more than 600 wells spread across 

the Uinta Basin, but mainly from the southeastern quarter of the basin. 

• Geokinetics, Inc., was originally organized in 1969 as a minerals 

development company; it was reorganized in 1972 as a joint venture with a 

group of independent oil companies to develop an in situ technique to extract 

shale oil. The company began design and cost studies of a horizontal modified 

in situ process in preparation for the anticipated Federal Prototype Oil Shale 

Lease Program sale. Small-scale pilot tests in steel retorts were carried out to 

simulate the horizontal process in 1974 and early 1975. Starting in April 1975, 

field tests of the in situ method were carried out, and by late 1976 the basic 

parameters for an in situ process were established. From 1977 through 1979, 

the process was scaled up substantially from early tests, and rock-breaking 

designs for the underground retorts were improved and tested. From 1980 

through 1982, Geokinetics, funded in part by DOE, blasted 24 experimental 
Final OSTS PEIS A-20 

underground retorts and tested them. These tests cumulatively produced 

15,000 bbl of oil. By 1982, the company had settled on a 2,000-bbl/day design 

for its commercial retort and had acquired 30,000 acres of nonfederal leases, 

with an estimated resource of 1.7 million bbl of oil (averaging 20 gal/ton). 

Between 1972 and 1982, the company drilled at least 32 core holes on its 

leases in the Uinta Basin and conducted Fischer assays on oil shale samples 

from those wells. 

• Magic Circle Energy Corporation acquired the 76,000 acres of State of Utah 

leases composing the Cottonwood Wash properties from the Western Oil 

Shale Corporation in July 1980 through an exchange of stock. The 

Cottonwood Wash properties contained an estimated 2.1 billion bbl of oil with 

a grade in excess of 15 gal/ton, and at a depth between 1,500 and 2,000 ft. 

Magic Circle spent more than $1 million to perform feasibility studies, initiate 

permit applications, and perform initial coring for resource definition, mine 

design, and environmental evaluation, but no mine or plant construction or oil 

shale production took place on this project. 

• Paraho Development Corporation was organized in Grand Junction, 

Colorado, in 1971, to develop oil shale technology. The company acquired 

leases along the White River in Utah near the border with Colorado, but no 

work was performed on the property. The company conducted several retort 

research projects in Colorado with several other industry partners to achieve 

an oil recovery averaging 90% of the in-place oil. On the basis of this 

research, the company was contracted by DOE to produce 100,000 bbl of 

shale oil. Paraho used the Anvil Points facility to conduct a 105-day 

continuous-stream operation in the late 1970s that produced the contracted 

amount of shale oil with 96% oil yields. The oil market deteriorated before a 

commercial plant could be permitted and built on the Utah leases. 

• Syntana-Utah was a joint venture of the Synthetic Oil Corporation and 

Quintana Minerals Corporation that was formed in late 1980. This venture 

acquired a State of Utah lease on Section 16, T9S, R25E, on which it planned 

to construct an underground mine and surface retort operation that could 

produce 24,500 tons/day of 25 gal/ton oil shale. Limited effort was spent 

identifying the depth, thickness, and grade of the oil shale to quantify the oil 

shale resource on the lease. Two, and perhaps more, drill holes were 

completed on the property to facilitate mine and retort engineering design. 

• TOSCO Development Corporation acquired 29 separate State of Utah oil 

shale leases totaling 14,688 acres of land about 35 mi south of Vernal, Utah. 

These leases were generally located in T9S and T10S, and R21E and R22E. 

Between 1977 and 1981, TOSCO drilled eight or more core holes to help 

define the oil shale resource and to initiate basic actions leading to a sitespecific EIS for a 66,000-ton/day mine with a production capacity of 

47,000 bbl/day employing multiple TOSCO II retort facilities. Subsequent 
Final OSTS PEIS A-21 

deterioration of oil prices led to the cancellation of the project before final 

permitting and construction began. 

• White River Shale Oil Corporation (WRSOC) was a joint venture of three 

major oil companies: Phillips, Sohio, and Sunoco. Sunoco and Phillips were 

the successful bidders for the 5,120 acres composing the U-a federal lease 

tract that sold for $75.6 million at the 1974 Federal Prototype Oil Shale Lease 

Program sale. Shortly after the first sale, Sohio joined the venture and the 

WRSOC was formed. In 1975, the group paid an additional $45.1 million and 

acquired the 5,120-acre U-b tract that was adjacent to the U-a tract. Between 

1974 and 1976, the WRSOC drilled 18 wells on its leases and created a 

detailed development plan that was submitted to the federal government in 

mid-1976. The development plan called for a 179,000-ton/day mine that 

would be supported by a 100,000-bbl/day surface retort at full commercial 

operation. Later that year, the leases were suspended because of 

environmental and land title issues and remained suspended until the early 

1980s. Once these issues were resolved, the venture ultimately constructed 

mine service buildings, water and sewage treatment plants, and a 

1,000-ft-deep vertical shaft and inclined haulage way to the high-grade 

Mahogany Zone of oil shale. Several tens of thousands of tons of oil shale 

were extracted to test mining conditions and retort technology and economics. 

The project was abandoned before commercial operations were achieved 

when market conditions deteriorated in the mid-1980s. 

Although the six Utah oil shale projects reached various stages of completion during the 

late 1970s and 1980s, none were able to reach commercial operation. Both mining with surface 

retort and in situ recovery methods of shale oil were investigated in Utah. The legacy of the 

surge of interest in oil shale development in the late 1970s and early 1980s is a wealth of 

resource, engineering, and baseline environmental data that will be useful in future efforts to 

develop oil shale resources. 

A.3 TECHNOLOGY OVERVIEW 

With the cessation of commercial development, there have been some minor 

evolutionary changes to oil shale development technologies, but some ongoing research has the 

potential of precipitating major revolutionary changes in oil shale development technologies. 

Notwithstanding these recent research initiatives, the technology evaluations conducted at the 

end of the zenith of oil shale development activities are still largely valid, despite the majority of 

them being produced more than 20 years ago. The few technology evaluation updates that have 

been published in more recent years rely primarily on the data and conclusions from those 

original evaluations and are unique only to the extent that they incorporate the results of the few 

ongoing research projects and anticipate the technology transfers that would likely be made from 

other mining and energy sectors. The information provided in this section brings forward the 

most relevant data and conclusions from the most comprehensive and reliable previous reviews. 
Final OSTS PEIS A-22 

Development of oil shale resources fundamentally occurs in three major steps: 

(1) recovery or extraction from the natural setting, (2) processing to separate organic and 

inorganic constituents, and (3) upgrading the organic components in anticipation of further 

refining into conventional fuels. The physical and chemical features of oil shale deposits and 

other circumstantial factors associated with their deposition compose the economic and 

engineering parameters that dictate the most appropriate development schemes. Typical 

development schemes always involve each of the above major steps, although many 

permutations of these steps are possible and many interim steps may also be necessary. This 

appendix provides descriptions of each of these major actions, the technologies that have been 

developed for each, their advantages and disadvantages, and their potentials for environmental 

impact. 

A.3.1 Recovery of Oil Shale 

A variety of technologies have been developed and commercially applied to oil shale 

recovery or extraction, and others are in the R&D phase. Other technologies that have proven 

their worth in other mining industry sectors conceptually apply to oil shale, but have yet to be 

applied at commercial scales. Efforts to recover oil shale resources have the potential to be both 

the most energy intensive and most environmentally problematic steps of oil shale development; 

advancements in recovery technologies ensure that greater portions of resources will be 

economically recoverable, operating costs will be minimized, and recovery efficiencies will be 

maximized. Resource extraction techniques can be generally categorized as direct or indirect 

recovery. Direct recovery involves the removal of the oil shale from its formation for ex situ 

processing. Indirect or in situ recovery involves some degree of processing of the oil shale while 

it is still in its natural depositional setting, leading ultimately to the removal or extraction of just 

the desired organic fraction. Additional aboveground processing of that fraction is still typically 

required. 

A.3.1.1 Direct Recovery Mining Technologies 

Surface mining techniques (e.g., strip mining and/or pit mining) as well as subsurface 

mining techniques (e.g., room-and-pillar mining, longwall mining, and other derivatives) have 

been successfully employed in the recovery of oil shale. For oil shale deposits relatively close to 

the surface, conventional strip mining technologies could be employed to retrieve the oil shale. 

As discussed in Section A.1, the BLM has limited its evaluation of the impacts of surface mining 

for oil shale to areas within the most geologically prospective oil shale areas where the 

overburden ranges in thickness from 0 to 500 ft. The areas where the overburden is 0 to 500 ft 

that potentially will be made available for application for leasing using surface mining 

technologies are limited to part of the Uinta Basin in Utah and parts of the Green River and 

Washakie Basins in Wyoming (Figure A-1). Surface mining will not be considered in Colorado 

because the distribution of areas where the overburden thickness is less than 500 ft is dispersed 

enough as to make it difficult to assemble a logical mining unit. In Utah, about 133,194 acres of 

land within the most geologically prospective oil shale area have an overburden thickness of 0 to 

500 ft. In Wyoming, the corresponding area includes about 380,220 acres. 
Final OSTS PEIS A-23 

 Conventional strip mining techniques and equipment developed in other mining industry 

sectors, primarily coal, can be applied directly to strip mining of near-surface oil shale deposits. 

Most oil shale deposits have distinct bedding planes. Experience has shown that shear strengths 

along these bedding planes are substantially less than across the planes, thereby ensuring that, in 

many instances, strip mining techniques using draglines and/or shovels will be successful 

without additional efforts to fracture the formation (e.g., through the use of explosives) 

(DOE 2004a).5 However, enhancement of natural fractures through the use of explosives 

(typically ammonium nitrate/fuel oil mixtures) or high-pressure water injection (hydrofracturing) 

is still commonly employed in strip mining operations. Depending on the formation thickness, 

strip mining may proceed through excavation of a series of “benches,” each 30 to 50 ft deep. 

Both strip mining and pit mining can be successfully applied to near-surface deposits 

with generally flat formation orientations. Both methods use similar types of equipment: shovels, 

bucket-wheel excavators, draglines, conveyors, trucks, scrapers, etc. The most probable 

combination of mining equipment would involve diesel-powered shovels loading materials into 

haul trucks ranging in size from 240- to 400-ton capacity. 

Pit mining does not typically require any ventilation or special considerations for the 

presence of methane (CH4); it does, however, typically utilize explosives to rubblize the 

formation before removal. Both surface mining methods impact significant land areas. Both 

require separate areas for temporary storage of overburden. Strip mines are often developed in 

such a manner that previously evacuated areas can be used to receive processing waste (retort 

ash); however, operations involving pit mines must utilize a separate area for retort ash disposal. 

According to Nowacki (1981), technological benefits of surface mining can include: 

• Low cost (over the life of the operation) and high productivity relative to other 

mining techniques; 

• Flexibility to adjust to changes in formation geometries; 

• High production tonnages (i.e., high resource recovery efficiencies); 

• Previously mined areas that provide storage areas for future overburdens or 

disposal areas for spent shale; and 

• Technologies that are well established, and operating logistics that have been 

optimized. 

However, environmental impacts can be significant, including: 

• Substantial land areas disturbed, loss of habitat (both at the working face and 

at stockpile areas); 

 

5 This same engineering feature of low shear strength in the bedding planes can also preempt the successful 

application of room-and-pillar mining techniques. 
Final OSTS PEIS A-24 

• Substantial amounts of overburden and spent shale requiring management; 

• Potential for ground and surface water impacts (pollution as well as altered 

drainage patterns); 

• Potential for air quality impacts from fugitive dust as well as from operation 

of equipment, much of which utilizes internal combustion engines; 

• Noise impacts from equipment vehicle operations, especially crushing and 

grinding operations and the use of explosives to loosen materials before 

removal (when necessary); 

• Initial capital investment that may be high (necessarily very large 

mining/haulage equipment) to ensure high productivity; and 

• Land reclamation programs that may extend well beyond cessation of mining 

operations (adapted from Nowacki 1981). 

Although surface mining techniques are well established and may be the most 

economical, they are accompanied by significant environmental impacts to the land and 

groundwater and surface waters and the ecosystems that rely on them, as well as impacts to 

visual resources (Nowacki 1981). Consequently, while these extraction techniques were among 

the first investigated for oil shale development, they quickly fell out of favor by 1977 in 

deference to subsurface mining or in situ recovery techniques for resource extraction, and only a 

handful of field tests or large-scale operations were actually conducted by utilizing surface 

mining techniques (Nowacki 1981). All but one of the projects under consideration as part of the 

BLM’s oil shale RD&D program (see Section A.5.3) focus on in situ processing rather than 

surface extraction and ex situ processing, suggesting that surface mining has a lower likelihood 

of being part of future development proposals. 

For deeper deposits where surface mining is infeasible or prohibitively expensive, or for 

deep deposits that are accessible through outcrops along erosion faces, room-and-pillar mining 

techniques such as those used in coal mining have been successfully applied. The typical cycle 

of activities in room-and-pillar mining involves drilling, charging, blasting, wetting, crushing, 

loading, hauling, scaling, and roof bolting (DOE 1982). 

Ventilation is necessarily continuous in virtually all room-and-pillar mining operations 

to provide for worker safety and is essential in “gassy” mines where explosive methane gas is 

present at concentrations greater than 1%. The excavated rooms are typically 60 ft wide by 90 ft 

high. Pillars (undisturbed formations) are 30 to 45 ft thick, depending on the engineering 

parameters of the particular formation and structural support demands dictated by the amount 

and type of overburden. In general, as much as 75% of the shale can be recovered by using this 

technique, especially in shallower formations (DOE 1982). Access to the mine is either by shaft, 

decline, adit, or a combination thereof. 
Final OSTS PEIS A-25 

Infrastructure necessary to support underground mining includes systems for both process 

and potable water, conveyor systems, crushing systems, and haulage systems. Mixtures of 

ammonium nitrate and fuel oil are typically used to rubblize the formation prior to crushing. 

Typically, primary and even secondary crushing are conducted within the mine before oil shale 

is brought to the surface. Pumping systems to manage formation water are also typically present. 

Electric power and vehicle/equipment fuels (typically diesel) are also required. A variation on 

this technique, chamber-and-pillar mining, has also been advanced. In chamber-and-pillar 

mining, chambers are cut perpendicular to the main entry shaft. This technique offers particular 

advantages to oil shale mining in that the chamber heights can be variable, in accordance with 

formation geometries, and, once excavated, the chamber may serve as a convenient disposal area 

for spent oil shale. Essentially the same types of support equipment are required for chamberand-pillar mining as for room-and-pillar mining. 

A.3.1.2 Indirect or In Situ Recovery Techniques 

Much attention has been paid to the development of in situ or indirect retrieval or 

extraction techniques in which just the kerogen fraction is actually recovered from the formation. 

Under normal conditions of temperature and pressure in the formation, kerogen is immobile. 

This fact is irrelevant and even beneficial if direct recovery techniques are employed. However, 

it becomes the most significant limiting factor when direct recovery is not possible or 

economical. To address these limitations, numerous indirect recovery techniques have been 

developed. In its simplest manifestation, an indirect recovery technique causes decomposition of 

kerogen to liquid and gaseous organic fractions of value that have sufficient mobility to “flow” 

through the formation for removal by conventional oil and gas recovery techniques. The two 

primary indirect recovery techniques, true in situ recovery (TIS) and MIS, both transfer heat to 

the formation; they differ, however, in the actions that are taken before formation heating is 

attempted. TIS involves introducing heat without prior efforts to significantly alter the 

formation’s permeability. MIS involves first altering the natural formation by increasing the 

extent of formation fracturing, thus theoretically improving the efficiency of formation heating 

and facilitating the movement of mobilized kerogen to points of retrieval. 

For any in situ process, some minimal amount of formation disturbance is required to 

provide a path through which to introduce the heat source and through which kerogen 

decomposition products can flow to points of recovery. For TIS, such intrusions are minimal and 

typically involve no more than installing a collection of conventionally sized wells.6 Heat can 

then be introduced into the formation by a variety of mechanisms, sometimes by injection of 

steam or other materials into either vertically or horizontally oriented boreholes or wells, but also 

by the application of alternative energy technologies such as microwave heating, radio-frequency 

(RF) heating, or electric resistance heating. Typically, the same pathways into the formation by 

which heat is introduced are used to recover the heated, mobilized kerogen by using 

conventional liquid extraction technologies. 

 

6 However, depending on the natural degree of fracturing, the permeability of the formation may still need to be 

enhanced through the use of explosives or by hydrofracturing. Even when these steps are taken, the extraction 

technique may still be called TIS. 
Final OSTS PEIS A-26 

Intrusion into and alteration of the formation are somewhat greater for MIS techniques. 

Typically, explosives are introduced to enhance the degree of natural fracturing, thus facilitating 

the flow of kerogen decomposition products to points of extraction. Subsequently, anywhere 

from 10 to 30% (by volume) of the formation is mined by conventional techniques (and later 

processed above ground) to create voids in the formation that serve as retorting chambers from 

which the formation is heated and at or near which the mobilized kerogen is accumulated and 

extracted. First-generation in situ heating technologies were designed to mobilize the kerogen in 

the formation by reducing its viscosity while not changing its chemical composition. However, 

the majority of investigations into in situ heating technologies focused not only on the 

mobilization of kerogen, but also its pyrolysis. Such in situ pyrolysis techniques are discussed in 

Section C.3.2. 

Enhanced oil recovery (EOR) technologies developed for the conventional crude oil and 

tar sands industries also have potential application to oil shale recovery. Both secondary and 

tertiary techniques have been developed. Secondary techniques essentially involve mechanical 

displacement of oil by the use of high-pressure immiscible gases or water. Waterflooding and 

high-pressure gas flooding are examples. Tertiary EOR techniques can be grouped into two 

categories: miscible techniques and thermal techniques. Miscible techniques involve the 

introduction of materials that dissolve the oil, increasing its ability to move through the 

formation to a recovery well. Thermal techniques introduce heat, lowering the oil’s viscosity, 

thus facilitating its movement through the formation. Solvent flooding may involve the use of 

such materials as raw naphtha, a collection of light molecular weight aliphatic hydrocarbons, 

that is a principal feedstock for gasoline or other products of partial crude oil refining. Tertiary 

techniques often follow or are superimposed upon secondary techniques. For example, the 

injection of high-pressure steam combines a secondary displacement technique with a tertiary 

thermal technique. Many of these techniques have also been successful in enhancing the 

recovery of bitumen7 from tar sands. While most of these techniques are typically applied near 

the end of the useful life of a conventional crude oil deposit, they can be used for dislodging or 

mobilizing kerogen in the early phases of formation development, either alone or in conjunction 

with the conventional heating technologies discussed above. Overviews of some of the most 

promising EOR technologies are provided below. More detailed discussions of EORs can be 

found in Enhanced Oil Recovery; Secondary and Tertiary Methods (Schumacher 1978) or any 

of the numerous other technical publications on these technologies. 

• Steam Injection Technologies. Steam injection has been used for decades to 

enhance recovery of crude oil or to mobilize heavy oils for retrieval. One such 

technology adapted to recovery of bitumen from tar sand, cyclic steam 

stimulation (CSS), may be applicable to oil shale recovery. CSS involves the 

injection of steam at high pressure and temperature into the deposit, causing 

the oil sand to fracture, simultaneously lowering the viscosity of the bitumen 

as it absorbs heat from the steam. The fluidized bitumen is then recovered by 

strategically placed conventional liquid recovery wells, together with steam 

 

7 Bitumen is the name commonly given to the organic fraction present in tar sands. Chemically it is a member of 

the asphaltene fraction of conventional crude oil. 
Final OSTS PEIS A-27 

condensates. Steam injections are repeated over time until all of the bitumen is 

recovered. 

A second widely used steam injection technology, steam-assisted gravity 

drainage (SAGD), is being used for retrieval of bitumen from tar sands in the 

vast deposits occurring in Alberta and Saskatchewan Provinces in Canada. 

SAGD is closely related to CSS in its technological approach; however, its 

mechanisms for recovery of mobilized/liquefied resources are unique. SAGD 

consists of two horizontal wells, a production well near the bottom of the 

formation and a steam injection well approximately 6 m above and aligned 

with the production well. Steam is circulated between the two wells, causing 

heating of the intervening formation by conduction. Once communication is 

achieved, the steam rises in the formation because of its relatively light 

density, heating the formation above the injection well. The heated oil, steam 

condensate, and formation water are then collected in the production well. 

• Waterflooding. As the name implies, waterflooding involves the injection of 

water at high pressure to mechanically displace oil from rock pores and 

fissures. The process can also enhance formation permeability by 

hydrofracturing (or hydraulic fracturing), causing additional fractures in the 

formation through increases in hydrostatic pressure. Waterflooding and 

hydrofracturing are relatively inexpensive but require extensive amounts of 

water. 

• High-Pressure CO2 Flooding. This technology applies carbon dioxide (CO2) 

at high pressures as a follow-on to in situ retorting and has two distinct 

advantages: displacement and removal of additional kerogen decomposition 

products not recoverable through conventional mining techniques or in situ 

heating techniques, and the possible sequestration of CO2 released from the 

operation of various combustion sources to produce process steam or power. 

One of the potential large environmental impacts from oil shale development 

is the release of copious amounts of CO2 during retorting and/or formation 

heating. Carbon dioxide has been used successfully in crude oil production as 

an effective enhanced recovery technique. After displacing crude oil from 

rock pores, the CO2 is bound indefinitely within those pores. Such 

sequestration may therefore be a valuable pollution control mechanism for oil 

shale development, while at the same time improving kerogen recovery 

efficiencies. 

• Solvent Flooding. Solvent flooding technologies are similar to steam injection 

technologies, substituting solvents for steam and relying on chemical 

dissolution of the kerogen rather than liquefaction through use of steam. 

Various organic solvents can be used. Solvent flooding is often performed 

with two horizontally oriented wells: an upper well into which the solvent is 

injected, and a lower well from which kerogen, diluted with solvent, and, in 

some cases, partially upgraded, can be recovered. Other well combinations for 
Final OSTS PEIS A-28 

solvent injection and product recovery have also proven successful. Solvent 

injection offers a number of important benefits over steam injection: (1) little 

to no processing water is required; (2) the technique involves lower capital 

costs since steam does not need to be produced, recovered, and recycled; 

(3) the solvent and potentially higher organic recovery rates are possible; and 

(4) partial upgrading of the kerogen may result from its interactions with the 

solvents selected. However, solvent injection also has some drawbacks. The 

solvent must be recoverable for the process to be economically viable, and 

any solvent not recovered represents a potential for groundwater 

contamination. 

• Electromagnetic Heating. Another family of technologies accomplishes 

formation heating through the application of electromagnetic energy. 

Electromagnetic energy at relatively low power levels was initially developed 

for formation imaging, relying on the different resistivities of rocks, formation 

water, and oil being observable as they absorb induced energies. At higher 

levels of applied power, electromagnetic energy can be used to heat the 

formation. Energies throughout the energy spectrum can be used—

low-frequency electric resistive heating to higher-frequency radio-wave and 

microwave heating. Electromagnetic heating technologies have potential 

applicability in those formations where more common steam injection 

technologies have limited success (e.g., low permeability formations, thin or 

highly heterogeneous formations, or especially deep formations) and may 

have an advantage in terms of delivering heat to greater depths in the 

formation. Electromagnetic heating is also particularly effective in reducing 

the viscosity of the organic phase; thus, it is especially applicable to the 

recovery of bitumen from tar sands and kerogen from oil shales, either as the 

primary technology or as a source of formation heating used in conjunction 

with, or prior to, other recovery technologies. The rates at which a formation 

must be heated by any of these technologies vary with formation 

characteristics, but typically the process can be expected to take 6 months to 

years of constant application of electromagnetic heating to create a sufficient 

temperature rise in the formation to dramatically increase organic retrieval 

efficiencies. 

Raytheon has successfully developed a RF heating technology for application 

to oil shale recovery (Cogliandro 2006; see also Raytheon 2006). Field 

experience indicates that this technology results in rapid heating and 

volatization of water, which, in turn, results in microfracturing of the 

formation, enhancing formation permeability and product recovery. 

Consequently, no preliminary steps designed to remove the majority of free 

formation water are necessary. Experience to date indicates that the Raytheon 

RF heating technique could be successfully applied to exploit formations with 

as little as 150 ft of overburden (the minimum thickness needed to prevent 

“bleeding” of induced RF energy at the surface). Applying the RF heating 

technique, Raytheon has obtained recovery rates of 75% of the oil shale’s 
Final OSTS PEIS A-29 

Carbon Dioxide Sequestration and Its Role in Oil Shale Development 

Carbon sequestration is the isolation of carbon dioxide (CO2) from the biosphere in what are 

called “natural carbon sinks.” The primary “sinks” are the oceans and growing vegetation that consumes 

CO2 by the process of photosynthesis. However, sequestration of CO2 in underground rock formations is 

also possible. In geological sequestration, the CO2 can be effectively held in small pore spaces in mineral 

deposits for millions of years. Injecting CO2 under high pressure into mature crude oil formations, a 

process known as CO2 flooding, has long been employed as an enhanced oil recovery (EOR) technique 

to enhance crude oil recovery capabilities in mature fields. In CO2 flooding, it is believed that the CO2

displaces crude oil from mineral pore spaces into formation fractures where it is more easily recoverable. 

A February 2006 initiative launched by the U.S. Department of Energy’s (DOE’s) Office of Fossil 

Energy is specifically aimed at research into the use of CO2 to enhance domestic oil and gas recovery 

and simultaneous CO2 sequestration (see the Web site below). A similar mechanism of kerogen 

displacement is possible for oil shale formations, many of which are naturally fractured to equal or 

greater extent than typical crude oil–bearing rock formations. 

 In addition to a simple mechanical “trapping” of CO2 in mineral pores, scientists believe 

that in some formations, a chemical reaction called “carbonation” occurs, converting the CO2 to 

thermodynamically stable carbonates, ensuring that the sequestration is virtually permanent. Such 

reactions are actually acid-base neutralizations; thus, minerals containing alkali or alkaline earth metals 

are most inclined to engage in carbonation. Natural reaction kinetics of such carbonations are slow, 

however, so such reactions must be artificially encouraged by the introduction of heat and or pressure 

before becoming effective CO2 control mechanisms. In addition to their thermodynamic stability, the 

carbonates formed are relatively insoluble to ground or surface waters with typical pH values. Thus, the 

carbonates are relatively immobile and unreactive in the environment; therefore, the CO2 sequestration 

is not easily reversed. There is a substantial amount of research ongoing on carbon sequestration. The 

following Web sites and the links therein are recommended for further study: DOE-sponsored Carbon 

Sequestration research: http://cdiac2.esd.ornl.gov/. DOE’s Carbon Dioxide Sequestration Initiative 

(February 2006): http://www.netl.doe.gov/publications/press/2006/06008-EOR_Sequestration_ 

Initiative.html. Carbon Capture and Sequestration Technologies at MIT: http://sequestration.mit.edu/. 

The North American Carbon Program: http://www.nacarbon.org/nacp/agencies.html. The following 

literature review and the references therein on the mechanisms of CO2 sequestration in minerals are also 

recommended: http://www.ecn.nl/docs/library/report/2003/c03016.pdf.

Fisher assay value. Some upgrading of initial kerogen pyrolysis products has 

also been observed. However, in its latest form, the Raytheon RF heating 

technique is intended to be used in conjunction with the injection of 

supercritical CO2 to enhance product recovery. Coupling those technologies 

has resulted in recovery rates as high as 90 to 95%.8

• Chemically Assisted Recovery Techniques. Various chemicals have been 

used successfully to enhance the recovery of crude oils. The chemicals 

selected perform various functions, acting as surfactants, electrolytes, mobility 

buffers, diluents, or blocking agents that effectively block exchange sites in 

the formation for which oil molecules have an affinity. The selection of 

chemicals is based on a number of factors, including cost and availability of 

 

8 See http://www.Raytheon.com/newsroom/feature/oil_shale06/. 
Final OSTS PEIS A-30 

the chemicals, compatibility of the chemical with the formation, and various 

other logistical factors. Chemicals such as hydrazine and hydrogen peroxide 

have been used to initiate thermal recovery, while quinoline, sodium 

hydroxide, and toluene have been used to enhance thermal recovery initiated 

by other means (Schumacher 1978). 

Experience using chemicals to enhance kerogen recovery is much more 

limited than it is for crude oils, but some of the concepts on which these 

chemically enhanced recovery technologies are based may be relevant to oil 

shale recovery. DOE-sponsored research carried out at Argonne National 

Laboratory investigated the specific manner in which kerogen molecules were 

bound to minerals in oil shale. Understanding the nature of this bonding 

would allow development of chemically enhanced recovery methods, since 

chemical attack of such bonds would, in theory, release the kerogen 

(Vandegrift et al. 1980). Follow-up investigations at the University of 

Colorado, Boulder, conducted laboratory-scale recovery of kerogen using 

solutions of 10% hydrogen chloride, 80% steam, and 10% CO2 injected into 

shale samples at moderate pressures (Ramirez 1989). Some of the results were 

promising, producing yields of 80% and, in one instance, better than 90% of 

the Fisher assay value for the kerogen. The researchers concluded that 

chemically assisted recovery had promise, but that a key to its success was a 

dynamic flushing of the formation rather than a simple saturation of the 

formation with the chemical solution selected. No further research using 

similar solutions has been undertaken, however. 

A.3.2 Processing Oil Shale 

Processing oil shale involves two steps: (1) retorting to separate the organic and inorganic 

fractions and cause initial chemical transformations in the organic fraction (Section A.3.2), and 

(2) upgrading the resulting organic retorting products through additional chemical reactions until 

materials generally equivalent to conventional fuels are produced (Section A.3.2). Myriad 

physical, chemical, logistical, and environmental issues must be understood and managed for any 

given process to be technologically successful. Numerous technologies have been advanced for 

retorting and subsequently upgrading oil shale. However, the heterogeneous nature of oil shale 

virtually guarantees that no one retorting technology will be best in all circumstances, and further 

guarantees that a technology’s performance at one location depends on a variety of site-specific 

factors. In addition to their impact on the yield and quality of final products, many technological 

issues also greatly influence economics. Availability of support resources such as electric power, 

heat, processing water, and reactants for use in upgrading reactions, as well as the nature of 

resulting environmental impacts and requirements for their control or mitigation, greatly impact 

the overall success, practicability, and cost of any given technology. Energy and environmental 

efficiencies of oil shale processing technologies play as important a role as the richness and 

accessibility of the oil shale resource. 
Final OSTS PEIS A-31 

The following discussions provide brief descriptions of the technologies that have been 

identified for oil shale processing and focus on their overall effectiveness and anticipated 

environmental impacts. No endorsements are implied and no warranty is given that the 

discussions below represent a comprehensive array of technologies. Attempts were made to 

develop the evaluations below in terms of resource extraction, retorting, and upgrading. 

However, the technological approach to oil shale development is more sophisticated than those 

simplistic, separable steps would imply, as it occurs in a very integrated fashion. Although such 

integration of distinct steps would result in greater overall efficiencies, each technology is 

discussed separately in this appendix. 

When the oil shale resource is extracted from its formation for ex situ processing, a 

certain number of preliminary preparatory steps may be required before retorting or upgrading 

can occur. These might involve separating the oil shale from other extraneous materials and free 

water and crushing it to the uniform particle size specified by the retorting process being used. 

Primary and secondary crushing can take place within a subsurface mine before the materials are 

brought to the surface. Uniform particle size of oil shale results in better retorting efficiencies 

and better overall efficiencies in materials management. When the raw resource has been 

retrieved from its formation as a liquid through in situ formation heating or other in situ recovery 

technologies, crushing and sizing are obviously not required; however, other actions such as 

separation of water (e.g., the small amount of formation water that entered the retort zone after 

heating commenced, as well as the water produced in kerogen pyrolysis and condensate that 

results when steam is used to heat the formation) and removal of entrained fine particulates are 

necessary prior to any retorting. All such crushing, sizing, and separating technologies are 

considered to be generic to resource mining and are not otherwise mentioned in the following 

discussions of particular retorting or upgrading technologies unless they have been shown to play 

especially critical roles in that technology’s overall performance. 

Organic fractions of oil shale are separated from the mineral fraction through a process 

known as retorting. During retorting, kerogen is released from the mineral surface to which it is 

adsorbed and subsequently undergoes chemical transformations in a process known as pyrolysis. 

When direct recovery methods are used (e.g., surface or subsurface mining), retorting the 

recovered oil shale causes thermal desorption of the organic fractions from the mineral fractions 

and the subsequent destructive distillation or pyrolysis of kerogen, which produces three product 

streams: crude shale oil (a collection of condensable organic liquids); flammable hydrocarbon 

gases; and char, a solid fraction of organic material that typically remains adsorbed to the 

mineral fraction of the shale. The char has limited value as an energy source for production of 

distillate fuels and is typically not further processed, although some retort designs call for it to be 

burned as a heat source for processing subsequent batches of mined oil shale. The liquid and 

gaseous products from retorting undergo additional processing to make them suitable for further 

refining off the mine site or for use on-site as fuel to sustain the mining and retorting operations. 

When recovery techniques are employed, only the kerogen or its pyrolysis products are 

recovered, and any subsequent aboveground retorting is conducted simply to complete kerogen 

pyrolysis. As will be discussed later, some MIS techniques have been specifically designed to 

accomplish in situ pyrolysis of kerogen. The extent to which that pyrolysis occurs in situ will 

determine the need for further ex situ processing of recovered organic materials. 
Final OSTS PEIS A-32 

A.3.2.1 Aboveground Retorting Technologies 

Initial attempts at oil shale pyrolysis were conducted in aboveground retorts (AGRs) by 

using designs and technical approaches that had been adapted from technologies developed for 

other types of mineral resource recoveries. There are numerous configurations for AGRs; these 

are differentiated by the manner in which they produce the heat energy needed for pyrolysis, how 

they deliver that heat energy to the oil shale, the manner and extent to which excess heat energy 

is captured and recycled, and the manner and extent to which initial products of kerogen 

pyrolysis are used to augment subsequent pyrolysis. Technologies include both direct and 

indirect heating of the oil shale. In direct heat retorting, some of the oil shale, char-bearing 

spent shale from previous retorting cycles, or some other fuel is combusted to provide heat 

for pyrolysis of the remaining oil shale, with the flame impinging directly on the oil shale 

undergoing retorting. Indirect heating, the more widely practiced alternative, involves the use of 

gases or solids that have been heated externally using a separate imported fuel or energy source 

and then introduced into the retort to exchange heat with the oil shale. Indirect heat sources 

include hot combustion gases or ashes from combustion of an external fuel, ceramic balls that 

have been heated by an indirect source, or even the latent heat contained in retort ash from 

previous retort cycles. The flammable hydrocarbon gases and hydrogen produced during 

retorting are also sometimes burned to support the heating process. While all retorts will produce 

crude shale oil liquids, hydrocarbon gases, and char, some have been designed to further treat 

these hydrocarbon fractions to produce syncrude. Other retorting processes contain auxiliary 

features to treat problematic by-products such as nitrogen- and sulfur-containing compounds; in 

some cases, they even convert these compounds to saleable by-products. 

Comprehensive technical reviews of AGRs are contained in numerous reports published 

by or on behalf of various federal agencies, including DOE, the U.S. Environmental Protection 

Agency (EPA), and the U.S. Congress OTA (DOE 1982, 1983, 1988, 2004a,b; EPA 1977, 1979; 

NTIS 1979; OTA 1980a). Other technical reviews of AGRs also exist in the open literature 

(Heistand and Piper 1995). 

Government-sponsored work in the development of AGRs specifically designed for oil 

shale was conducted in the 1960s under the direction of the U.S. Bureau of Mines. The gas 

combustion retort (GCR) was the design originally selected by U.S. Bureau of Mines for initial 

development of the Green River Formation oil shale at its demonstration mine at Anvil Points, 

Colorado. The GCR was a counterflow direct combustion retort. In addition to a relatively 

simple design and generally high production efficiencies, the most important advantage of GCRs 

is that they do not require cooling water, which makes them an excellent fit for the arid regions 

in which the majority of the Green River Formation oil shale exists. The U.S. Bureau of Minesled project to develop the GCR involved a consortium of six commercial oil corporations: Mobil 

Oil, Humble Oil, Pan American, Sinclair, Phillips, and Continental Oil. The U.S. Bureau of 

Mines GCR designs were the models for many commercial direct combustion counterflow 

retorts, including the Paraho Direct Mode Retort. Development of the GCR was completed in 

1967, before the promulgation of the National Environmental Policy Act (NEPA). Consequently, 

while some environmental impacts of the GCR were identified and measured, a comprehensive 

appreciation of its environmental impact was not established. However, environmental impacts 
Final OSTS PEIS A-33 

from direct descendants of the GCR, such as the Paraho Direct Mode Retort, have been 

extensively defined and quantified. 

AGRs have typically assumed the names of the RD&D projects in which they were 

developed, the corporation that conducted the RD&D, or their original inventors. At least eight 

separate retort designs have been developed to pilot stages, while only a few have reached 

commercial-scale applications. The following text, taken largely from the most recent DOE 

review (DOE 2004a) and from an EPA review (EPA 1979), provides information on a 

representative cross section of AGR technologies previously developed for application in the oil 

shale industry. The AGRs that collectively compose a representative sample of AGR technology 

include Union B, TOSCO II, Paraho (both direct and indirect modes), the Lurgi-Ruhrgas 

process, and Superior Oil’s circular grate retort. Also included is a description of the Alberta 

Taciuk Process (ATP) technology, which was originally developed for processing tar sands but is 

currently being proposed for use in oil shale development. 

A.3.2.1.1 Union B Retort. This retort was developed by the Union Oil Company of 

California (Unocal). It is an example of hot inert gas retorting. Crushed shale (0.32 to 5.08 cm 

[0.13 in. to 2.00 in.]) is fed through two chutes to a solids pump that moves shale upwards 

through the retort. The shale is heated to retorting temperatures by interaction with a counterflow 

of hot recycle gas [510 to 538C (950 to 1,000F)], resulting in the evolution of oil shale vapor 

and gas. Heat is supplied by combustion of the organic matter remaining on the retorted oil shale 

and is transferred to the (raw) oil shale by direct gas-to-solids exchange. The process does not 

require cooling water. This mixture is forced downward by the flow of recycle gas and cooled by 

contact with cold shale entering the retort in the lower section of the retort. Gas and condensed 

liquids are captured and separated at the bottom of the retort. Liquids are removed. Gases are 

sent to a preheater and returned to the retort for recovery of heat energy by burning. The captured 

liquids are further treated for removal of water, solids, and arsenic salts. Once the system reaches 

equilibrium, no external fuel is required; heat is supplied by the combustion of hydrocarbon 

gases produced during retorting. Pollution control devices are integrated into the design for 

removal of hydrogen sulfide (H2S) gas and NH3 gas produced during retorting and for treatment 

of process waters recovered from oil/water separations. Treated waters are recycled, used for 

cooling the spent shale, or delivered to mining and handling operations and used to moisten the 

shale for fugitive dust controls. 

The Union B Retort design offers particular advantages. The reducing atmosphere 

maintained in the retort results in the removal of sulfur and nitrogen compounds through the 

formation of H2S and NH3 gas, respectively, both of which are subsequently captured. Forcing 

the hot, newly formed oil vapors to immediately contact the cooler shale entering the retort 

results in their rapid quenching. This is thought to minimize polymer formation among the 

hydrocarbon fractions, improving not only the overall yield of crude shale oil but also its quality. 

Additional treatment of the initially formed shale oil and the removal of heavy metals, such as 

arsenic, results in a final product recovered from the retort that can be used directly as a 

low-sulfur fuel or delivered to conventional refineries for additional refining. 
Final OSTS PEIS A-34 

A.3.2.1.2 TOSCO II Retort. The TOSCO II Retort, developed by The Oil Shale 

Corporation, is more correctly described as a retorting/upgrading process. Its design is unique in 

two respects: it is one of only a few retorts that have operated in the United States that employ a 

solid-to-solid heat exchange process, and it is the only process that fully integrates oil shale 

retorting and shale oil upgrading steps to produce an upgraded syncrude, as well as liquefied 

petroleum gas (LPG) and saleable sulfur, NH3, and coke by-products. Although they are 

independent of each other, the retort and the various upgrading units are designed to work 

together. 

Crushed and sized (nominally to 1/2 in.) raw oil shale is preheated to 500F by 

interaction with flue gases from a ceramic ball heater. The preheated shale is introduced into a 

horizontal rotary kiln together with 1.5 times its weight in previously heated ceramic balls. The 

temperature of the shale is raised to its minimal retort temperature of 900F. The kerogen is 

converted to shale oil vapors that are withdrawn and fed to a fractionator for hydrocarbon 

recovery and water separation. Spent shale and the ceramic balls are discharged and separated; 

the ceramic balls are returned to their heater; and the spent shale is cooled, moistened for dust 

control, and removed for land disposal. The fractionator separates the shale oil hydrocarbon 

vapors into gas, naphtha,9 gas oil, and bottom oil. The gas, naphtha, and gas oil are sent to 

various upgrading units, while the bottom oil is sent to a delayed coking unit, where it is 

converted to lighter fractions and by-product coke. Gas oil and raw naphtha are both upgraded in 

separate hydrogenation units through reaction with hydrogen at high pressure. The hydrogen is 

actually produced on-site from steam reforming of the fuel gas originally recovered from the 

retort. In addition to improving the H/C ratio of the hydrocarbons, the hydrogenation units also 

convert any sulfur present to H2S and any nitrogen present to NH3. The NH3 is captured for sale, 

while the H2S is sent for further treatment, where it is converted to saleable sulfur. Other 

saleable products from the hydrogenation units include LPG and butane. 

A.3.2.1.3 Paraho Retorts. The Paraho retorts, developed by Development Engineering, 

Inc., have been in service in oil shale fields in both Colorado and Brazil. Two versions exist, 

direct mode and indirect mode, both utilizing vertical retorting chambers. In the direct mode 

retort, some of the raw shale is ignited in the combustion zone of the retort to produce the heat 

that pyrolyzes the remaining oil shale present in higher zones. The Paraho direct mode retort is 

an example of the U.S. Bureau of Mines GCR. In the indirect mode retort, heat is generated in a 

separate combustion chamber and delivered to lowermost portion of the retorting chamber. 

In the direct mode Paraho retort, crushed and sized oil shale is fed into the top of the 

vertical retorting vessel. At the same time, spent shale (previously retorted oil shale that contains 

solid carbonaceous char) is ignited in a lower level of the retort. Hot combustion gases rise 

through the descending raw shale to pyrolize the kerogen. Oil vapors and mists formed in the 

uppermost portion of the retort are removed. The liquid fraction is captured for further upgrading 

 

9 “Naphtha” is a general term applied to refined or unrefined petroleum products, not less than 10% of which 

distill below 347F (175C) and not less than 95% of which distill below 464F (240C) when subjected to 

standardized distillation methods (Sax and Lewis 1987). 
Final OSTS PEIS A-35 

in independent facilities. The gaseous fraction is cleaned for sale, while a small portion is 

returned to the retort and combusted together with the spent shale. 

In the indirect mode Paraho retort, the portion of the vertical retorting chamber that was 

used for oil shale combustion in the direct mode is now the region of the retort chamber into 

which externally heated fuel gas is introduced. No combustion occurs within the retorting 

chamber. That separate combustion process is typically fueled by commercial fuels (natural gas, 

diesel, propane, etc.) that are often augmented with a portion of the fuel gas recovered from the 

retorting operation. While they are very similar in operation, the direct and indirect mode Paraho 

retorts offer sufficiently different operating conditions so as to change the composition of the 

recovered crude shale oils and gases. Oil vapors and mists leave the direct mode retort at 

approximately 140F, while the vapors and gases in the indirect mode leave the retorting vessel 

at 280F and have as much as nine times higher heating values than gases and vapors recovered 

from the direct mode retort (102 Btu/scf vs. 885 Btu/scf, or 908 kcal/m3 vs. 7,560 kcal/m3) 

(EPA 1979). This is thought to be due principally to the fact that oil vapors and mists recovered 

from the direct mode are “diluted” with combustion gases from the combustion of the spent shale 

at the bottom portion of the retort. Characteristics of the recovered raw shale oil are somewhat 

different for the direct and indirect mode retorts, but each has characteristics similar to shale oils 

recovered from other retorts using similar shale heating mechanisms (direct vs. indirect). Retort 

gases also differ from the two modes. Gases from indirect mode retorts have much lower levels 

of CO2 (due to the lack of dilution by gases from direct combustion) but generally higher levels 

of H2S, NH3, and hydrogen, which are thought to be the result of the indirect mode retort having 

much less of an oxidizing environment than the direct mode retort (EPA 1979). Finally, the 

Paraho retort can also be operated in a direct/indirect hybrid mode. 

A.3.2.1.4 Lurgi-Ruhrgas Process. The Lurgi-Ruhrgas technology was developed in 

Germany for the production of pipeline-quality gas through the devolatilization of coal fines. 

The technology has operated at commercial scales for the devolatilization of lignite fines, the 

production of char fines for briquettes from sub-bituminous coal, and the cracking of naphtha 

and crude oil to produce olefins. As with the Paraho process, the Lurgi-Ruhrgas process was 

designed from its inception not only to retort kerogen but also to refine the resulting 

hydrocarbons into saleable liquid and gaseous petroleum fractions. 

In this process, crushed and sized (–0.25 in.) oil shale is fed through a feed hopper and 

mixed with as much as six to eight times its volume of a mixture of hot spent shale and sand with 

a nominal temperature of 1,166F and conveyed up a lift pipe. This mixing raises the average 

temperature of the raw shale to 986F, a temperature sufficient to cause the evolution of gas, 

shale oil vapor, and water vapor. The solids mixture is then delivered to a surge hopper to await 

additional processing in which more residual oil components will be distilled off. The sand, 

introduced as a heat carrier, is recovered and recycled. The mixture is then returned to the bottom 

of the lift pipe and allowed to interact with hot combustion air at 752F. The carbonaceous 

fraction is burned as the mixture is raised pneumatically up the lift pipe and transferred to a 

collection bin where the spent shale fines are separated from gases. The hydrocarbon gases and 

oil vapors are processed through a series of scrubbers and coolers to eventually be recovered as 

condensable liquids and gases. Because the shale particle size is initially so small, management 
Final OSTS PEIS A-36 

of fines is critical throughout the process and involves the use of sedimentation and centrifuging 

as well as numerous cyclones and electrostatic precipitators. 

A.3.2.1.5 Superior Oil’s Circular Grate Retorting Process. One retort design 

advanced by Superior Oil theoretically offers substantial environmental advantages over other 

retorting processes. The design is a counterflow, gas-to-solid heat exchange process conducted in 

an enclosed circular grate. Shale in a relatively wide range of sizes (0.25 to 4.0 in.) is added, 

rotated to the first segment of the retort, and heated by a continuously circulating gas medium. 

Volatilized oil (mists) mixes with the circulating gas and, together with water, is periodically 

removed from the gas stream. The partially pyrolyzed shale rotates to the next segment of the 

retort where it is partially oxidized to complete the kerogen pyrolysis and oil evolution. The 

spent shale cools in the next segment of the grate as it yields heat to the circulating gas. 

Additional heat is added to the first segment of the grate where initial pyrolysis of raw shale 

takes place either through direct or indirect combustion of gases recovered from previous shale 

retorting. This design has been used for many years in the processing of various ores, including 

iron ores, and consequently has a relatively high reliability factor. 

Only pilot-scale experiences exist for this retort when applied to oil shale. However, 

numerous tests have identified critical control parameters and optimized operations resulting in 

oil recovery yields greater than 98% Fisher assay results. From an environmental perspective, 

the circular grate holds great promise, since it is essentially a sealed operation with hooded 

enclosures above the grate, to capture hydrocarbon gases and oil mists, and water seals 

(water troughs) below the grate, where spent shale is discharged. The water seals prevent gas and 

mist leakage and also provide for the moistening of the spent shale that is necessary for its safe 

handling and disposal. 

Another unique aspect to the Superior circular grate retort is that it was designed to be 

operated in conjunction with subsystems for the recovery of alumina and soda ash. Thus, this 

design appears well suited for applications where saline deposits coexist with oil shale or are 

present above or below the shale. In the Superior Oil circular grate process, spent shale is 

delivered to subsystems that convert the saline minerals to saleable products. For example, 

commonly encountered dawsonite [NaAl(OH)2CO3] can be converted to alumina (aluminum 

oxide [Al2O3] and soda ash [NaCO3]). Further, conditions during kerogen retorting are favorable 

for the simultaneous conversion of nahcolite (NaHCO3) to soda ash, CO2, and water. 

Technical advantages to this retort include the circumstance that the circulating shale is 

independent of the circulated gas above it and that considerable experience with this type of 

retort has identified and resolved the major operational problems. Although designed to operate 

continuously, the unit can be quickly shut down and restarted. Temperature control is excellent, 

resulting in high hydrocarbon recovery rates and relatively minor amounts of sintering of the 

inorganic phase of the shale (Nowacki 1981). 

A.3.2.1.6 Alberta Taciuk Process. The ATP is an AGR technology originally 

researched and designed for the extraction of bitumen from tar sands in Canadian tar sands 
Final OSTS PEIS A-37 

deposits, some of the largest and richest deposits of their kind in the world. The ATP was 

developed by UMATAC Industrial Processes, a division of UMA Engineering, Ltd., which 

supplies the technology under license agreements. 

The ATP Processor is the primary processing component of the technology and it works 

in conjunction with a number of ancillary subsystems that, together, make up the ATP System. 

As with many of the retorting technologies discussed above, the ATP System provides more than 

simple retorting; the Processor, together with its subsystems, can provide primary upgrading of 

the initial retort products, as well as capture and control of problematic by-products.10 The ATP 

is a dry thermal process involving indirect heating of oil shale using countercurrent gas-solid 

heat exchange as well as the generation of process heat by combustion of coke (carbon present 

on retorted oil shale solids) in the combustion zone of the kiln. The ATP has been successfully 

applied to retorting oil shale and has achieved improved yields of raw shale oil and combustible 

gases over other retorting technologies developed and used specifically for the oil shale industry. 

The ATP provides high heat-transfer efficiencies and integral combustion of coke for process 

heat demands, which minimizes the amount of residual coke remaining on spent shale. This 

combination minimizes CO2 release per ton of shale processed and reduces the potential for 

environmental contamination from improper spent shale disposal (DOE 2004a). 

A schematic flow diagram of the ATP System is shown in Figure A-3. A pictorial 

representation of the functioning of the ATP Processor is shown in Figure A-4. 

The ATP System also represents the likely direction of future AGR equipment in that it is 

fitted with environmental control equipment to lessen the impact of air emissions and water 

effluents typically resulting from retorting. The ATP technology has successfully operated at 

semicommercial demonstration scale in Australia and is to be used commercially in China. There 

is evidence to suggest that the ATP System will also continue to be applied to future oil shale 

development.11

A.3.2.2 In Situ Retorting 

First attempts at in situ formation heating were pursued with the intention of mobilizing 

the kerogen to facilitate its movement through the formation for extraction by conventional 

pumping/extraction devices. However, the objectives of in situ formation heating investigations 

quickly expanded to include in situ pyrolysis of the kerogen.12 Both TIS and MIS recovery 

techniques have been explored for their compatibility with in situ retorting. While most past 

 

10 Many other AGRs could also be fitted with air pollution control equipment. 

11 The Oil Shale Exploration Company (OSEC) was one of the original applicants whose project was approved as 

part of the BLM’s oil shale RD&D program. In 2011, the OSEC RD&D project was acquired by Enefit 

American Oil. OSEC had proposed to use a modified version of the ATP system for oil shale development in the 

Uinta Basin in Utah; Enefit will use its own retorting technology. Additional details of the Enefit/OSEC RD&D 

initiative, as well as the other five RD&D initiatives, are provided in Section A.4. 

12 In situ retorting is said to have been attempted in Estonia in the 1940s (EPA 1979). 
Final OSTS PEIS A-38 

FIGURE A-3 ATP System Flow Diagram Processor (Source: UMATAC Industrial Processes; 

reprinted with permission) 

FIGURE A-4 Pictorial Representation of ATP Processor (Source: UMATAC Industrial Processes; 

reprinted with permission) 
Final OSTS PEIS A-39 

research has utilized MIS techniques, recently proposed research has begun to pursue techniques 

that can more properly be described as TIS. 

 Myriad in situ retorting designs have been proposed. As a result of his literature review, 

Lee (1991) has suggested three fundamental design dimensions on which to categorize in situ 

retorting technologies: (1) the mechanism by which heat is introduced into or produced within 

the formation, (2) the manner and extent to which the technology modifies natural fracturing 

patterns in the formation to ensure adequate permeability, and (3) whether the technology 

employs a TIS or MIS approach to recovery of organics. Lee further notes that most in situ 

technologies that have undergone field testing qualify as MIS and involve altering the formation 

by enhancing fracturing and/or by creating voids that would serve as retort chambers. 

Differences in approaches among MIS technologies center on the manner in which formation 

voids are formed, the shape and orientation of such voids (horizontal vs. vertical), and the actual 

retorting and product recovery techniques employed. Retorting techniques can include controlled 

combustion of rubblized shale, or formation heating by alternative means such as the 

introduction of electromagnetic energy. Product recovery techniques have included steam 

leaching, chemically assisted or solvent leaching, and displacement by high-pressure gas or 

water injection. Some of these formation sweeping techniques also can be seen as aiding or 

promoting additional refining of the initial retorting products. It is beyond the scope of this 

summary to discuss in detail all or even a majority of the designs that have been developed; 

Lee (1991) has provided a comprehensive listing of the patents that have been issued for these 

designs. 

Hydrocarbon products of successful in situ heating are similar in character to the products 

recovered from AGRs: petroleum gases, hydrocarbon liquids, and char. Field experiences with 

the first generation in situ retorts indicate that the petroleum gases tend to be of lesser quality 

than gases recovered by AGRs.13 The condensable liquid fraction, however, generally tends to 

be of better quality than the liquid hydrocarbon fractions recovered from AGRs with higher 

degrees of cracking of the kerogen macromolecules and elimination of substantial portions of the 

higher boiling fractions typically produced in AGRs. Overall yields with any in situ retorting 

tend to be lower than yields from equal amounts of oil shale of equivalent richness processed 

through AGR (EPRI 1981). Various explanations have been advanced for these observed 

differences. Some of the loss of quality for recovered gases may be the dilution that results when 

heat is introduced to the formation by injection of combustion gases and/or steam, by 

advancement of a flame front as a result of combustion of some portion of the shale, or when 

high-pressure gases are used to sweep retorting products from the formation to recovery wells. 

The quality improvements for the liquid fraction may be due to the relatively slow and more 

even heating that can be attained in a properly designed and executed in situ retorting process. 

Such quality improvements also may be indicative of further refining of initial retorting products 

when sweep gases such as natural gas or hydrogen are used. Finally, and importantly from an 

environmental perspective, the char and the mineral fraction to which it is adsorbed are not 

recovered but remain in the formation, significantly reducing (but not completely eliminating) 

 

13 However, gases recovered from in situ retorting that does not involve combustion are expected to be equivalent 

in quality to gases recovered from AGRs. 
Final OSTS PEIS A-40 

collateral environmental impacts from solid by-product wastes. Limited evidence collected by 

the EPA suggests that groundwater quality impacts may still result from in situ spent shale. 

Experience with AGRs clearly demonstrated that the conditions maintained during 

pyrolysis significantly influence the composition, quality, and yield of recovered products, 

including unwanted by-products, much more so than does the initial composition of the oil 

shale. Establishing and maintaining such strict controls in situ is a significant engineering 

challenge. Overcoming this challenge requires significant effort, but the ultimate return is 

equally significant. There are unique and substantial operational and environmental advantages 

to in situ recovery, and even more and greater advantages result from successful in situ retorting, 

including the following: 

• Simplified material handling requirements (only the retorted organic fraction, 

roughly less than 15% by weight of the parent oil shale, would need to be 

recovered from the formation); 

• Greater portions of the deposit would be accessible for economical kerogen 

recovery (albeit perhaps at a lower overall recovery efficiency); 

• Spent shale from conventional retorting, a significant solid waste issue, would 

be virtually eliminated; 

• Overall energy efficiencies may increase over conventional retrieval and AGR 

methods; 

• Air pollution potential would be significantly reduced; 

• Noise pollution would be severely reduced; 

• Impacts on ecosystems and fugitive dust potential would be reduced because 

of the smaller aerial extent of surface industrial activities and the reduced land 

area required for material stockpiles and solid waste disposal; and 

• Surface water quality impacts would be reduced because of the reduced size 

of land disposal areas and the reduced potential for stormwater pollution from 

interim material and waste pile runoff. 

In situ retorting also has some potential disadvantages. Intuitively, the overall success of 

any in situ retorting technology results from its ability to distribute heat evenly throughout the 

formation. Indiscriminate formation heating that allows portions of the formation to reach 

1,100F can result in technological problems, as well as the thermal decomposition of mineral 

carbonates and the formation and release of CO2. From an operational standpoint, such 

decompositions are endothermic and will result in the energy demands of such uncontrolled in 

situ retorting quickly becoming insurmountable. As noted above, environmental consequences of 

carbonate decomposition during in situ retorting can be expected to be mitigated to a large extent 

by the natural CO2 sequestrations that can also be anticipated. Nevertheless, the lack of precise 
Final OSTS PEIS A-41 

heat control will devastate both the yields and the quality of recovered hydrocarbons and must be 

avoided. However, in situ retorting with good thermodynamic controls can product pyrolysis 

products of equal or even greater quality than AGR. 

Another potential disadvantage to in situ retorting involves the time that it takes to heat 

substantial masses of formation materials to retorting temperature (on the order of months or 

years) and the energy costs over that period. Field experiences are limited, and, because every 

formation accepts heat differently, it is difficult to define a universal time line or perform 

precise, reliable energy balances except on a site-specific basis. 

Other largely unanswered questions involve long-term impacts from retorted segments of 

oil shale formations. Questions regarding long-term impacts include: 

• Will vacated pore spaces need to be filled to prevent surface subsidence? 

• Will groundwater flow patterns change significantly? 

• Will groundwater interactions with retorted shale minerals facilitate the 

leaching of heavy metals or other contaminants? 

• Will water produced from in situ combustion become a conduit for delivery of 

contaminants to existing groundwater aquifers? 

• Will CO2 produced in situ be safely sequestered indefinitely within the 

formation? 

While conceptual designs for in situ retorting are numerous, only limited field activities 

have been pursued, mostly undertaken as proof-of-concept exercises, but, in a few instances, 

with the intent of advancing the practical development and application of specific in situ retort 

designs. Field data on both the short- and long-term impacts of in situ retorting are therefore 

limited. Independent investigations were conducted as early as 1953. Government-sponsored 

research began in the 1960s. The following sections provide brief descriptions of the early 

research and a more extensive description of only the most prominent in situ retorting 

technology. Also included are brief descriptions of RD&D projects that have been recently 

proposed and approved by the BLM for further research and that also involve some form of 

in situ retorting. 

A.3.2.2.1 Early In Situ Retorting Experiments. Lee (1991) has provided the following 

brief summaries of some of the earliest research into in situ technologies: 

• Sinclair Oil and Gas. Sinclair’s experiments investigated one of the earliest 

uses of high-pressure air injected into the formation to sweep retort products 

to recovery wells. 
Final OSTS PEIS A-42 

• Equity Oil Company. Equity’s process used hot natural gas to both retort the 

shale and sweep the retort products to recovery wells. 

• Laramie Energy Technology Center (LETC). LETC sponsored some early 

research into in situ retorting in the early 1960s at Rock Springs, Wyoming. 

The purposes of this research were twofold: (1) establish the best mechanisms 

for enhancing the fracturing of the formation to increase its permeability, and 

(2) investigate the process by which in situ combustion of shale and the 

subsequent movement of a heat front through the formation could be made 

self-sustaining. 

• Dow Chemical. Dow Chemical’s research was conducted on eastern 

United States shale in Michigan, but much of the experience is transferable to 

western shales. Dow’s experiment was one of the earliest examples of TIS. It 

used explosives to enhance fracturing and electrical resistance heaters 

combined with propane-fired burners to effect in situ retorting. 

• Geokinetics, Inc. The Geokinetics process was one of the earliest uses of 

horizontally oriented retort voids in an MIS process. This DOE-sponsored 

research occurred near Grand Junction, Colorado, in the Parachute Member of 

the Green River Formation and also in the Mahogany Zone. Importantly, this 

research proved the value of horizontal retort chambers in relatively thin shale 

deposits. 

A.3.2.2.2 The Occidental Oil Shale MIS Retort Technology. OOSI conducted much 

of the pioneering investigations into in situ retorting under the auspices of a DOE contract, 

issuing its final report in January 1984. Although the operation was under the control of OOSI, 

personnel from DOE’s Sandia National Laboratories provided consultation services throughout 

the project and were instrumental in development of the final report (Stevens et al. 1984). The 

project was conducted in two phases near Logan’s Wash near Debeque, Colorado, and represents 

one of the most extensive research ventures into MIS vertical in situ retorting technology. 

The OOSI experiment was conducted in two phases and was intended to provide 

demonstrations of mining, rubblizing, ignition, and simultaneous processing of commercial-sized 

MIS retorts. Although the primary thrust of the research involved the development of design and 

operating parameters for the MIS in situ retort, support systems, including surface processing of 

retort products, were also investigated. 

The retorting technology involved creating a void in the oil shale formation using 

conventional underground mining techniques.14 Explosives (ammonium nitrate and fuel oil 

[ANFO]) were then introduced to cause the “rubblizing” of some of the shale on the walls of the 

 

14 In commercial application, numerous voids would be created, spaced throughout the formation and collectively 

representing a removal of 15 to 20% of the formation volume of shale that would be brought to the surface for 

conventional AGR. 
Final OSTS PEIS A-43 

void and to expand existing fractures in the formation, improving its permeability.15 Access to 

the void was sealed and a controlled mixture of air and fuel gas (or alternatively, commercial 

fuel such as propane or natural gas) was introduced to initiate controlled ignition of the rubblized 

shale. Combustion using this external fuel continued until the rubblized shale itself was ignited, 

after which external fuel additions were discontinued and combustion air continued to be 

provided to the void to sustain and control combustion of the shale.16 The resulting heat 

expanded downward into the surrounding formation, heating and retorting the kerogen. Retort 

products collected at the bottom of the retort void and were then recovered from conventional oil 

and gas wells installed adjacent to the void. Careful control of combustion air/fuel mixtures was 

the primary control over the rate of combustion occurring in the heavily instrumented and 

monitored void. Once recovery of retorted oil shale products equilibrated, a portion of the 

hydrocarbon gases was recycled back into the void to be used as fuel to sustain in situ 

combustion.17 Two separate retorts were constructed and operated during Phase II of the project, 

with the last two retorts shutting down in February 1983. 

Ultimately, oil recovery was equivalent to 70% of the yield predicted through Fisher 

assay. Design of the experiment was directed toward potential future commercial applications so 

numerous that such in situ retorts were operated simultaneously to demonstrate the practicability 

of an approach that would likely have been desirable in commercial development ventures. 

Conceptual views of the OOSI in situ retort and the expected movement of the heat front through 

the formation are displayed in Figures A-5 and A-6, respectively. 

From a technological perspective, the OOSI in situ retorting experiment was a success. 

Recovered crude shale oil has a specific gravity of 0.904 (American Petroleum Institute [API] 

gravity of 2518), a pour point of 70F, a sulfur content of 0.71% (by weight), and a nitrogen 

content of 1.50% (by weight). OOSI believes that crude shale oil meeting those specifications 

would be available for use as a boiler fuel without further processing or would certainly 

constitute acceptable refinery feedstock for additional refining to other conventional fuels. 

From an environmental perspective, many questions were raised regarding the type and 

scale of environmental impacts that would result from either the initial in situ retorting or from 

the subsequent use of the resulting shale oil in industrial boilers or furnaces, and some of those 

 

15 Although the original research utilized explosives, it can be anticipated that for some shale formations, sufficient 

alterations can be accomplished with the injection of high-pressure water (hydrofracturing). 

16 Phase II experimented with the use of hot inert gas to preheat the rubblized shale, followed by air to initiate 

combustion. 

17 Hydrocarbon gases recovered from this process are of only moderate quality, having been diluted by gases of 

combustion as well as CO2 from carbonate decomposition. Typically, the recovered gases had a heating value of 

less than 65 Btu/scf. In the OOSI design, the fraction of the gas that was not introduced back into the formation 

to support further combustion was used on-site for power and/or steam generation. 

18 The pour point is the temperature at which the petroleum liquid’s viscosity is sufficiently low to allow pumping 

and transfer operations with conventional liquid handling equipment. American Petroleum Institute (API) gravity 

is an arbitrary scale for expressing the specific gravity or density of liquid petroleum products. Devised by the 

API and the National Bureau of Standards, API gravity is expressed as degrees API. API gravities are the inverse 

of specific gravity. Thus, heavier viscous petroleum liquids have the lower API values. 
Final OSTS PEIS A-44 

FIGURE A-5 Conceptual Design of the 

Occidental Oil Shale, Inc., MIS Retorting 

Process (Source: EPA 1979) 

FIGURE A-6 Conceptual View of the Downward 

Movement of the Heat Front through the Formation 

in the Occidental Oil Shale, Inc., Vertical In Situ 

Retort (Source: EPA 1979) 

questions remain unanswered. As part of its development plan, OOSI identified as many as 

48 separate activities associated with this technology for which there could be an environmental 

impact. Environmental monitoring throughout the project and beyond was scheduled to verify 

and quantify those impacts. However, the magnitudes of many of OOSI’s anticipated impacts are 

disputed by the EPA. 

 First, the EPA disputes the OOSI claim of the magnitude of nitrogen oxides (NOx) 

emissions that would result from combustion of the recovered crude shale oil in an industrial 

boiler, believing that the amount would be much greater than that claimed. Second, it has not 

been reliably demonstrated that all of the CO2 generated during the retorting (from combustion 

sources as well as carbonate decomposition) would be successfully sequestered in the formation 

indefinitely. Thirdly, major water management problems exist. It was estimated that the volume 

of retort water created during retorting plus the amount of water used for surface processing 

(upgrading) of retort products and for fugitive dust control throughout the operational area is 

essentially equivalent to the volume of crude shale oil produced. Thus, a substantial volume of 

water may require treatment before discharge or recycling. Further, groundwater monitoring 

data appear to indicate that groundwater contamination had occurred, both during and after 

completion of retorting. The extent to which the retort water contains contaminants that would 

require proper treatment could not be reliably predicted, and it is not clear whether any or all of 

this water could be recycled for use in future processing. 
Final OSTS PEIS A-45 

Conclusions from a thorough analysis of water quality impacts from MIS retorts were 

summarized in the OOSI final report: 

• Total alkalinity, NH3, phenols, dissolved organic carbon, thiosulfate, and 

thiocyanide concentrations are significantly higher in retort water (i.e., waters 

recovered from retorts during operation) than in natural water; 

• Aluminum, magnesium, and calcium concentrations are lower in retort water 

than in natural water; 

• Monitoring data from wells near the retort operations showed no discernable 

trends that could be interpreted as contamination from the retorts; however, 

• Trends over time indicate that concentrations of constituents thought to be 

leaching from the retired retorted areas initially increase significantly from 

natural waters but also quickly equilibrated (in a matter of 2 years or less) to 

levels approximating the concentrations in natural waters without any 

intervention or remediation, suggesting that most leaching occurs from the 

initial flushing of retorted zones by infiltrating groundwater, but also that the 

amounts of leachable materials remaining in retorted zones appear to be 

limited. 

A.3.3 Upgrading Oil Shale 

Irrespective of the resource recovery and retorting technologies employed, kerogen 

pyrolysis products are likely to require further processing or upgrading before becoming 

attractive to oil refineries as feedstocks for conventional fuels. Upgrading crude shale oil to 

produce syncrude for delivery to refineries is analogous to the early steps of crude oil refining. 

The refining process is complex but nevertheless well understood and well documented. The 

discussions that follow provide only a cursory review of those aspects of refining that are most 

relevant to mine site upgrading of crude shale oil. 

Refining crude oil involves a great variety of reactions. Preliminary steps are taken to 

separate extraneous materials that may be present in the crude oil feedstock (e.g., water, 

suspended solids). Crude oil fractions are separated (fractionated) by their boiling points in 

atmospheric and/or vacuum distillations. Distillation fractions are subjected to heat, causing 

the thermal decomposition of large molecules into smaller ones (coking or cracking). Thermal 

cracking products are then subjected to a variety of chemical reactions designed to modify their 

chemical compositions either by removing hydrogen and other atoms to form compounds 

composed largely of carbon (e.g., delayed coking, fluid coking) or by adding hydrogen while 

removing hetero atoms, such as sulfur and nitrogen, to form organic compounds composed 

exclusively of carbon and hydrogen (catalytic or thermal hydrocracking, hydrotreating, 

desulfurization, and hydrogenation). Finally, various treatment reactions are conducted to 

remove contaminants or modify chemicals that would be the source of air pollution when the 

petroleum product is later consumed by combustion. Numerous other specialized reactions are 
Final OSTS PEIS A-46 

interspersed within this scheme, which is designed to reformulate organic molecules into 

chemicals that change the physical or chemical properties of the commercial fuel mixtures in 

which they are contained. 

Upgrading crude shale oil at the mine site might consist of all of the above steps, 

although hydrogen-addition reactions generally predominate, and reactions to produce specialty 

chemicals are not likely to occur at all. Upgrading is typically directed only at the gaseous and 

liquid fractions of the retorting products and is rarely applied to the solid char that remains with 

the inorganic fraction of the oil shale, although coking of that solid fraction is possible. The most 

likely end products will be refinery feedstocks suitable for the production of middle distillates 

(kerosene, diesel fuel, jet fuel, No. 2 fuel oil), although lighter weight fuel components such as 

gasolines can also be produced. In general, hydrotreating followed by hydrocracking will 

produce jet fuel feedstocks, hydrotreating followed by fluid catalytic cracking is performed for 

production of gasoline feedstocks, and coking followed by hydrotreating is performed with the 

intention of producing diesel fuel feedstocks (Speight 1997). 

Similar to the preliminary steps taken at refineries, prior to or coincident with crude shale 

oil upgrading reactions, there are also activities to separate water from both the gas and liquid 

fractions, to separate oily mists from the gaseous fraction, and to separate and further treat gases 

evolved during retorting to remove impurities and entrained solids and improve their combustion 

quality.19 Actions to remove heavy metals and inorganic impurities from crude shale oils also 

take place. 

Upgrading activities are dictated by factors such as the initial composition of the oil 

shale, the compositions of retorting products,20 the composition and quality of desired petroleum 

feedstocks or petroleum end products of market quality, and the business decision to develop 

other by-products such as sulfur and NH3 into saleable products.21 Product variety and quality 

issues aside, there are other logistical factors that determine the extent to which upgrading 

activities are conducted at the mine site. Most prominent among these factors is the ready 

availability of electric power and process water. In especially remote locations, factors such as 

these represent the most significant parameters for mine site upgrading decisions. 

The initial composition of the crude shale oil produced in the retorting step is the 

primary influence in the design of the subsequent upgrading operation. In particular, nitrogen 

 

19 Removal of entrained solids is typically accomplished by simple gravity or centrifugal separation techniques 

such as cyclone separators. However, other techniques have been developed, including high-gradient magnetic 

separation (Lewis 1982). 

20 The composition of retort products is dictated by conditions during retorting. In general, pyrolysis of kerogen at 

the lowest temperature possible yields the highest proportion of saturates over olefinic and aromatic constituents. 

Higher retorting temperatures yield increasingly greater amounts of aromatic compounds until, at the retorting 

temperature of 871C, Colorado Green River Formation shale can be expected to yield 100% aromatic 

compounds (Speight 1990). 

21 Elemental sulfur has widespread use in a wide variety of industry sectors: pulp and paper, rubber, 

pharmaceutical, detergents, insecticides, and explosives. Likewise, NH3 enjoys widespread industrial 

applications, such as agricultural fertilizers, textiles, steel treatment, explosives, synthetic fibers, and refrigerants. 
Final OSTS PEIS A-47 

compounds, sulfur compounds, and organometallic compounds dictate the upgrading process 

that is selected. In general, crude shale oil typically contains nitrogen compounds (throughout the 

total boiling range of shale oil) in concentrations that are 10 to 20 times the amounts found in 

typical crude oils (Griest et al. 1980). Removal of the nitrogen-bearing compounds is an essential 

requirement of the upgrading effort, since nitrogen is poisonous to most catalysts used in 

subsequent refining steps and creates unacceptable amounts of NOx pollutants when nitrogencontaining fuels are burned. 

Sulfur, also a poison to refinery catalysts, is typically present in much lower proportions 

as organic sulfides and sulfates. With respect to sulfur, crude shale oil compares favorably with 

most low-sulfur crude oils, which are preferred feedstocks for low-sulfur fuels that are often 

required by local air pollution regulations. Hydrotreating to the extent necessary to convert 

nitrogen compounds to NH3 is sufficient in most instances to simultaneously convert sulfur to 

H2S. Crude shale oil additionally contains much higher amounts of organometallic compounds 

than conventional crude oils. The presence of these organometallic compounds complicates the 

mine site upgrading, since they can readily foul the catalysts used in hydrotreating, causing 

interruptions in production and increased volumes of solid wastes requiring disposal, sometimes 

even requiring specialized disposal as hazardous wastes because of the presence of spoiled 

heavy-metal catalysts. 

Desired end products for mine site upgrading are typically limited to mixtures of organic 

compounds that are acceptable for use as conventional refinery feedstock; however, it is possible 

to produce feedstocks that are of higher quality and value to refineries than even crude oils 

having the most desirable properties. Since crude shale oils are typically more viscous than 

conventional crude oils, their yields of lighter distillate fractions such as gasolines, kerosene, jet 

fuel, and diesel fuel are typically low. However, additional hydrotreating can markedly increase 

the typical yields of these distillate fractions. 

Given the high capital costs involved in constructing and operating more sophisticated 

refining operations at remote mine sites, there is little incentive for mine operators to duplicate 

existing refinery capabilities, and most oil shale development business models will likely 

include only the upgrading that is minimally necessary for the end products to be acceptable 

to conventional refineries and capable of being transported to those refineries by existing 

conveyance technologies (i.e., sufficiently improved API gravities and pour points). Such a 

business model was endorsed by the Committee on Production Technologies for Liquid 

Transportation Fuels of the National Research Council in 1990 and is believed to still be 

applicable today (National Research Council 1990). 

All of the factors controlling upgrading are very site- and project-specific. At the PEIS 

level, it is not possible to precisely describe all of the actions that may be undertaken for the 

purposes of upgrading retorting products; however, a general overview of the nature of those 

reactions is provided below. An example of an explicitly defined upgrading scheme is provided 

in the BLM’s Final Environmental Impact Statement for the Proposed Development of Oil Shale 

Resources by the Colony Development Operation in Colorado, Volume I (BLM 1977). 
Final OSTS PEIS A-48 

Upgrading is designed to increase the relative proportion of saturated hydrocarbons over 

unsaturated hydrocarbons in the crude shale oil recovered from retorting and to eliminate the 

other compounds present that can interfere with further refining of the crude shale oil into 

conventional middle distillate fuels (primarily, compounds containing nitrogen or sulfur atoms). 

Hydrogen at high temperatures and pressures is used to create a reducing atmosphere in which 

olefinic or aromatic hydrocarbons are converted to alkanes (or saturates), and organic 

compounds containing sulfur or nitrogen are destroyed with the sulfur and nitrogen being 

converted to H2S and NH3, respectively, which are then captured and removed. As upgrading 

converts crude shale oil to syncrude, the physical properties change significantly. As a practical 

matter, the pour point and API gravity of the liquid fraction are substantially increased, making 

syncrude much easier to handle and transport than crude shale oil (typically another stated goal 

of mine site upgrading). Gaseous components are converted to fuel gas, LPG, and butanes,22 all 

becoming available for use as fuels to support further oil shale processing or as marketable 

materials for sale at the wholesale or retail level. Most probably, gases such as propane and 

propylene would be stored and receive an appropriate odorant gas (e.g., methyl mercaptan) for 

eventual sale as LPG, while any hydrogen produced as well as the butane/butylene fraction are 

more likely to be returned to the retorting process and consumed as supplemental fuel. 

A.4 SPENT SHALE MANAGEMENT 

An important component of surface mining and underground mining projects is spent 

shale management. Either surface mining or underground mining projects may opt to dispose of 

spent shale in surface impoundments or as fill in graded areas; for surface mining projects, it 

may be disposed of in previously mined areas. Disadvantages of surface disposal include the use 

of large land areas; labor-intensive requirements to revegetate the disposal area; dust-control 

prior to revegetation; and potential impacts on surface water, particularly salinity, from runoff 

water containing residual hydrocarbons, salts, and trace metals from the spent shale. 

While disposal of spent shale back into the underground oil shale mine or a preexisting 

mine appears initially attractive, various logistical issues may prevent or limit such disposals as 

well as cause potential problems unique to that disposal technique. For example, mine 

development design may prevent convenient access to retired portions while the mine is still 

active. Also, while the potential for leaching of toxic constituents from the spent shale as a result 

of precipitation or run-on surface water interactions is effectively eliminated, leaching as a result 

of interaction of groundwater can still be anticipated.23

 

22 Butanes formed during upgrading of shale oil are typically mixtures of butane and butylenes. Although 

potentially saleable products (generally within the boiling range of commercial LPG), these mixtures are more 

typically used as fuel at the plant site. 

23 It is reasonable to expect that mine dewatering efforts will continue throughout the operational period of the 

mine but will cease after the mine is shut down and that natural groundwater flow patterns will reestablish, 

notwithstanding the alterations to flow caused by modifications to the formation. Thus, contact of groundwater 

with emplaced spent shale can be expected to occur. 
Final OSTS PEIS A-49 

Regardless of the disposal option selected, a number of issues need to be addressed, 

including the structural integrity of emplaced spent shale, an increase in volume (and decrease in 

density) over raw shale, and the character of leachates from spent shale. Limited research has 

been conducted on each of these issues. 

Studies on the structural properties of spent shale have been performed on the spent 

shale from the Paraho Retorting project at Anvil Points, Colorado, and summarized in a paper 

presented at the 13th Oil Shale Symposium held in Golden, Colorado, in 1980 (Heistand and 

Holtz 1980). The studies concluded that properly wetted and compacted spent shale could be 

quite stable, even exhibiting the properties of low-grade cements and exhibiting no problems 

with respect to leaching, autoignition, or fugitive dusting.24 Average structural properties for 

spent shale from a Paraho AGR are shown in Table A-5. 

It has been reported in the literature that as much as 30% expansion in volume can occur 

in spent shales over the parent raw shale (DOE 1988; Argonne 1990). The exact reasons for this 

phenomenon are not fully understood. Certainly, some density changes could be expected after 

removal of the organic fractions. It may also be that CO2 is being released from decomposing 

carbonate minerals, and the gas expands the mineral structure as it escapes. 

Density changes can be expected to be slightly different for each specific retorting 

technology, but in all cases, densities of spent shale have decreased over the density of the parent 

oil shale. A plant producing 50,000 bbl/day from 30 gal/ton oil shale using surface or subsurface 

mining and AGR may need to dispose of as much as approximately 450 million ft3 of spent shale 

each year (DOE 1988). Regardless of the degree of compaction that can be accomplished during 

placement of spent shale, and assuming that the spent shale disposal strategy involves placement 

TABLE A-5 Structural Properties of Compacted Paraho AGR 

Spent Shale 

Parameter Ranges of Values Measured 

 

Compaction (dry density) 1,4001,600 kg/m3 (87106 lb/ft3) 

Permeability 1 × 1017 cm/s (0.1 ft/yr) 

Strength (unconfined, compressive) 1,480 kPa (215 psi) 

Classifications 

 Type Silty-gravel 

 Size 30–50% > 4.76 mm (4 mesh) 

 25–35% < 0.074 mm (200 mesh) 

Leaching/autoignition/dusting No problems identified 

Source: Heistand and Holtz (1980). 

 

24 Although the results of this study are encouraging with respect to the short- and long-term impacts of spent shale 

disposal, it is important to recognize that these results are specific to the spent shale and specific conditions 

evaluated in this study, and similar results of spent shale from other retorting technologies will not necessarily 

behave in the same manner. 
Final OSTS PEIS A-50 

in retired mine areas to reestablish the original grades and topographies of those areas, as much 

as 30% of the volume of spent shale would be left once those original grades and topographies 

were reestablished and would need to be disposed of in virgin areas. 

Field data evaluating the leachate character of spent shale have been collected by the 

EPA and others. Although the data are limited, there appears to be a clear indication that 

subjecting oil shale to retorting conditions can result in the mobilization of various ionic 

constituents contained in the mineral portion of the oil shale. Polar organic compounds with 

moderate to high water solubility formed during retorting and not successfully separated from 

the spent shale can also appear in spent shale leachates. Tables A-6 and A-7 show typical 

expected ranges of leachate constituents for spent shale from both in situ and aboveground 

retorting. 

Independent leachate studies have also been carried out on both spent shale disposal 

piles and piles of raw shale, with emphasis on the potential leachability of arsenic, selenium, 

molybdenum, boron, and fluorine (as the fluoride ion), all species that are relatively toxic to 

plants and can be expected to exist as soluble anions under the pH conditions normally 

encountered in waters interacting with spent shale disposal piles or raw shale stockpiles 

(i.e., 8 ≤ pH ≤12) (Stollenwerk and Runnells 1981). The results of these studies supported the 

predictions regarding the character of typical leachates from spent shale piles presented in 

Table A-7. 

Another study performed at the Anvil Points Oil Shale Facility in Rifle, Colorado, appeared 

to identify species that are unique to spent shale leachates and thus possibly useful for 

monitoring the movements of leachate from spent shale disposal areas (Riley et al. 1981). Soil 

extracts, surface waters, and groundwaters were analyzed for the presence of water-soluble 

organic compounds in a drainage area adjacent to a spent shale disposal pile. The C3–C6 

alkylpyridines25 were identified in alluvial groundwater samples and in surface waters below a 

seep and in moist subsoils adjacent to the alluvial sampling well. Extracts of raw shale, crude 

shale oil, and crude oil from Prudhoe Bay, Alaska, showed no alkylpyridines, however, 

suggesting that alkylpyridines may be produced during oil shale retorting and become unique 

constituents of the char on the spent shale. Thus, alkylpyridines may serve as excellent agents for 

monitoring leachate movements from spent shale piles. 

A.5 ONGOING AND EXPECTED FUTURE OIL SHALE DEVELOPMENT 

TECHNOLOGIES 

Limited research into future oil shale development technologies is ongoing, but more is 

currently being planned. The clear trend established near the end of the last period of major oil 

shale development activities involved the move to in situ technologies. 

 

25 The parent compound, pyridine, is a cyclic polar hydrocarbon with the formula C5H5N. It is a flammable liquid 

with moderate water solubility and a pungent odor. It is a severe eye irritant. Alkylpyridines are derivatives of 

the parent where one or more hydrogens is replaced by an alkyl group [CnH(n+1)]. 
Final OSTS PEIS A-51 

TABLE A-6 Summary of the Range of Leachate Characteristics of 

Simulated Spent Shale from In Situ Retorting and from Three AGRsa

Constituent Simulated In-Situ Retorts Surface Retortsb

 

General water quality measures 

 pH 7.812.7 7.811.2 

 Total dissolved solids 80>2,100 97010,011 

 

Major inorganics 

 Bicarbonate 2240 2038 

 Carbonate 30215 21 

 Hydroxide 2240 c

 Chloride 5.5 533 

 Fluoride 1.24.2 3.460 

 Sulfate 50130 6006,230 

 Nitrate (NO3) 0.22.6 5.15.6 

 Calcium 3.6210 42114 

 Magnesium 0.0028.0 3.591 

 Sodium 8.8235 1652,100 

 Potassium 0.7618 10625 

 

Organics 

 Total organic carbon 0.938 

 

Trace elements 

 Aluminum 0.0952.8 

 Arsenic  0.10 

 Boron 0.0750.14 212 

 Barium  4.0 

 Chromium 0.0021.8 

 Iron 0.00040.042 

 Lead 0.0140.017 

 Lithium 0.0200.42 

 Molybdenum trace 28 

 Selenium  0.05 

 Silica 2588 

 Strontium 0.0048.7 

 Zinc 0.0010.025 

a Concentrations are in mg/L unless otherwise noted. 

b TOSCO, U.S. Bureau of Mines, and Union Oil Company processes. 

c A dash indicates data not available. 

Source: EPA (1980). 
Final OSTS PEIS A-52 

TABLE A-7 Expected Characteristics of Leachates from Raw Shale 

Piles and Spent Shale Disposal Piles from Various AGRsa

Water Quality 

Parameter Raw Shale 

Spent Shale from 

Paraho Retort 

Spent Shale from 

TOSCO II Retort 

 

Total dissolved solids 18,000 28,000 55,000 

Mob 9 3 9 

Boronc 32 3 18 

Fluorided 16 10 19 

a Concentrations in milligrams per liter (mg/L) unless otherwise noted. 

b Molybdenum predicted to be present as MoO4

-2. 

c Boron predicted to be present as B(OH)3

0 and B(OH)4-1. 

d Fluorine predicted to be present as free F-1. 

Source: Stollenwerk and Runnells (1981). 

A.5.1 Shell Oil Mahogany Research Project 

Most of the in situ heating technologies have been in place since the mid-1980s, and early 

examples invariably involved the use of combustion strategies as sources of heat. There are, 

however, some novel ongoing resear ch projects that are exploring alternative formation heating 

techniques. One project of particular potential importance is research being conducted by Shell 

Exploration and Production (hereafter, Shell), a subsidiary of Shell Oil Corporation, on 

Shell-owned property located southeast of Rangely, Colorado, in Rio Blanco County. Since 

1996, Shell has been working in the Mahogany Zone of the Parachute Creek member of the 

Piceance Basin, thought to be the richest portion of the Green River Formation, to develop and 

field-test a novel approach to in situ heating called the in situ conversion process (ICP). ICP 

involves creating an “ice curtain” or “freeze wall” to isolate a vertically oriented column of the 

oil shale formation. This is done by encircling the focus area of the formation with wells into 

which piping is installed for recirculation of a heat-exchange fluid.26 The recirculating heatexchange fluid removes latent heat energy from the formation immediately adjacent to each of 

the wells. Ultimately (over a period of years) sufficient heat will be removed from the formation 

immediately surrounding each of these refrigeration wells so that naturally occurring water in the 

formation will freeze and form an ice curtain, thereby preventing the subsequent migration of 

groundwater into that portion of the formation. Then, after removal of any remaining liquid 

water within the bounded area, additional wells will be installed into which electric resistance 

heaters will be placed, and the formation will be slowly heated to 650 to 700F (over the course 

of 2 years or more). As the process name implies, the intent is to cause a relatively complete 

chemical conversion of the kerogen to petroleum gases and liquids that will be subsequently 

 

26 The initial research effort involved the use of a brine solution; however, future phases of research may use 

different heat exchange strategies, such as using aqueous NH3 solutions coupled with secondary cooling 

provided by anhydrous NH2. 
Final OSTS PEIS A-53 

recovered using conventional extraction technologies and that will require very little additional 

processing or modification before being delivered to conventional refineries. An initial review of 

this project was provided by DOE (2004a). 

An artist’s conceptual drawing of the ICP is shown in Figure A-7. Figure A-8 is a 

photograph of the Shell Mahogany Research Project site. 

Initial results are very promising. Shell’s fact sheet (Shell 2006) characterizes the 

attributes of this technology in the following manner: 

• The process is more environmentally friendly than previous oil shale efforts 

that were based on mining and retorting. 

• ICP has the potential to double the recovery efficiency, as it enables access to 

much deeper and thicker oil shale reserves. 

• ICP can potentially generate transportation fuel products that require 

considerably less processing. 

Early research data appear to support these claims. Recovered products have included gases 

(hydrogen, natural gas, other combustible gases); (approximately one-third by weight of the total 

amount recovered) as well as light oils of relatively high quality (typically API 36; 

approximately two-thirds by weight. Recovery rates as high as 62% (of recoverable oil) have 

been observed. Extrapolations from the test scale suggest potential yields (from oil shale deposits 

of equal richness) of as much as 1 million bbl/acre (i.e., heating of 1 acre of aerial extent of the 

FIGURE A-7 Cross Section of Shell’s Patented ICP Technology 

(Courtesy: Shell Exploration & Production; reprinted with 

permission) 
Final OSTS PEIS A-54 

FIGURE A-8 Shell’s Field Research in Rio Blanco County, Colorado (Courtesy: Shell 

Exploration & Production; reprinted with permission.) 

formation throughout the entire depth of the formation present within that 1-acre footprint) 

(Boyd 2006). 

Shell is currently preparing to integrate the research it has been conducting on the 

individual aspects of this technology (e.g., developing and maintaining a freeze wall, optimizing 

electric heater technology and rates of formation heating, optimizing product recovery 

techniques) into a larger-scale demonstration project under the auspices of an RD&D lease 

recently issued by the BLM. In 1996, Shell carried out a small field test on its Mahogany 

property in Rio Blanco County, Colorado, by using an in-ground heating process to recover oil 

and gas from the shale formation. Since then, Shell has carried out four additional field studies 

on private land near the towns of Rangely, Rifle, and Meeker, Colorado. The most recent test has 

produced 1,500 bbl of light oil plus associated gas from a relatively small plot. Shell’s research is 

continuing, and Shell has nominated three separate projects under the BLM’s oil shale RD&D 

program to further evaluate its process on public lands. 

 Progress at Shell’s Mahogany Isolation Test project with respect to groundwater 

protection was reported at the 31st Oil Shale Symposium in October 2011 (Hansen et al. 2011). 

Shell’s ICP operations and freeze wall groundwater protection technology ceased active 

production and began freeze wall melt in October 2004. Groundwater monitoring of ICP 

residuals in the tested formation conducted since that time show that ICP pyrolysis of oil shale 

did not result in an increase in arsenic levels above background levels measured in advance. 

BTEX compounds (benzene, toluene, ethyly benzene and xylene) were the only pyrolysisgenerated organic compounds detected in groundwater. Groundwater reclamation involving 

steam flushing and water recirculation conducted over 10 months reduced benzene and other 

residual concentrations sharply within a few months, sufficient to allow melting of the freeze 

wall. Continuous monitoring conducted since that time has shown that benzene concentrations in 

exterior monitoring wells fall below 5 μg/L within 250 ft in downgradient water-bearing zones. 
Final OSTS PEIS A-55 

A.5.2 Ambre Energy Partners (formerly Oil Tech, Inc.) 

Oil Tech, Inc., a small independent corporation, merged with Ambre Energy Partners in 

July 2008, when it acquired Oil Tech’s approximately 33,000 acres of oil shale leases in Utah. 

Oil Tech has been conducting research into aboveground retorting using electric resistance 

heating. The company maintains a small research site on approximately 2,600 acres of stateowned land approximately 20 mi east-northeast of Bonanza, Utah. This area is also underlain 

with Green River Formation shale at approximately a 1,000-ft depth but has never been mined. 

Approximately 70,000 tons of Mahogany Ridge oil shale that had been previously mined from 

the U-a research tract more than 20 years ago has provided the feedstock for this AGR research 

and development effort to date. Truckload quantities of run-of-mine shale are delivered 

periodically to the research site and stockpiled there. The shale is crushed on-site to nominal 

1/2-minus size before being introduced by a conveyor system to the vertical AGR. The AGR is 

of modular design, composed of a series of individual heating chambers, interconnected and 

stacked one upon the other, into which shale is loaded from the top. Heating rods extend into the 

centers of each of these chambers, transmitting heat to the shale in each chamber. Temperatures 

in each chamber are monitored and controlled by thermocouples. The temperature profile 

increases from top to bottom of the retort, culminating in the lowest heating chamber attaining a 

temperature of 1,000F. An induced draft fan exerts a slight vacuum simultaneously on all of the 

chambers through a common plenum, providing the principal means of extracting and collecting 

the gases and volatilized organic products of kerogen pyrolysis released from the shale by the 

process of fractional vaporization. Pyrolysis products are collected, filtered, and condensed. 

Spent shale is dumped by gravity from the bottom chamber, allowed to cool, and stockpiled for 

disposal. Shale moves from the top of the retort to the lowest heating chamber by gravity 

displacement. The design basis for this retort is 500 tons/h of shale input, resulting in a shale 

processing rate of approximately 24,000 yd3/day. 

The particular advantages of this retort include the following: 

• The modular design allows for relative portability and adaptability. 

• The process requires no water yet produces approximately 200 lb of water 

(kerogen pyrolysis as well as free water present in the feedstock) for every ton 

of shale retorted. 

• Heavily insulated enclosure and heating chambers maximize heating 

efficiency. 

• Product separation is easily accomplished. 

• Product quality is such that little additional upgrading is required. 

While initial results were promising, the company is currently monitoring opportunities 

to participate in oil shale development in the region. 
Final OSTS PEIS A-56 

A.5.3 Current and Proposed RD&D Projects on BLM-Administered Lands 

On June 9, 2005, pursuant to its authority to lease federal lands for oil shale development 

under Section 21 of the Mineral Leasing Act (United States Code, Title 30, Section 241 

[30 USC 241]), the BLM published a notice in the Federal Register (Volume 70, page 33753 

[70 FR 33753]) announcing a program wherein companies or individuals could submit proposals 

to lease 160-acre tracts of BLM-managed land for a period of up to 10 years for the purpose of 

RD&D of oil shale development technologies. Potential lessees were required to submit a 

detailed plan of operation development that addressed their proposed development scenario, 

including their approaches for complying with applicable laws and regulations and 

environmental protection. 

 The BLM reviewed each of the proposals that were submitted and selected six to receive 

further consideration. Upon successful completion of required environmental assessments (EAs), 

each of the six applicants was awarded a 160-acre lease on which to conduct RD&D of oil shale 

development technology for a period of up to 10 years, with the potential to extend the lease for 

another 5 years. Assuming that the RD&D efforts are successful, each RD&D leaseholder will 

be given the opportunity to exercise a preference right lease, expanding the areal extent of its 

BLM lease to a maximum of 5,120 acres, thus facilitating transition from research-scale to 

commercial-scale operations. In 2010, the BLM issued a second-round solicitation for RD&D 

proposals and received three new proposals, two of which have been recently approved, and one 

of which is currently being evaluated. The second-round proposals were limited to a 160-acre 

lease, with potential expansion under a preference right lease to a maximum area of 640 acres. 

Figure A-9 shows the locations of the six ongoing, two recently approved, and one remaining 

proposed RD&D (Aurasource) tracts and the associated preference right lease areas. The 

following sections provide overviews of the six ongoing projects on the basis of information 

published in the EAs (BLM 2006ac, 2007) and of the two recently approved projects, based on 

information provided in plans of operation (ExxonMobil 2011; Natural Soda Holdings 2011). 

Table A-8 lists the hazardous materials, hazardous wastes, and wastewater streams associated 

with these projects.27

A.5.3.1 Chevron U.S.A., Inc. (Chevron) 

 The Chevron RD&D project is located in the Piceance Basin of Colorado; information 

presented here regarding this project is taken from the EA of the proposed activities 

(BLM 2006a). Progress made and the status of the project as of early 2012 are summarized 

from a review of RD&D projects conducted by INTEK, Inc. and DOE (Crawford et al. 2012). 

Chevron employs an in situ process for shale oil recovery and production that is facilitated by 

applying drilling, fracturing, and in situ heating technologies. This methodology entails drilling 

wells into the oil shale formation and applying a series of horizontal fracturing technologies. 

The process generates hot gases via the in situ combustion of the remaining organic matter in 

 

27 The following discussions are based on detailed plans of development submitted by each of the RD&D 

leaseholders. It is understood that those places may be refined or amended (with BLM approval) as research 

progresses. 
FIGURE A-9 Locations of Eight Current and One Proposed RD&D Tracts and Associated Preference RAreas
Final OSTS PEIS A-58 

TABLE A-8 Hazardous Materials and Wastes, Other Wastes, and Wastewater Associated with the 

RD&D Projects 

Hazardous Materials and Wastes in RD&D Operations 

• Fuels and various working and maintenance fluids for vehicles and industrial equipmenta

• Chemicals used in management, purification, and upgrading of gaseous and liquid products 

• Spent shale (at the Enefit, formerly Oil Shale Exploration Company [OSEC], site) 

• Sludges from purification and sanitary wastewater treatment 

• Herbicides 

• Containers, dunnage, packaging materials, miscellaneous wastes 

• Office-related wastes 

• Decommissioning wastes, including fluids for cleaning of industrial equipment, storage containers, 

and transfer piping 

• Products from both in-situ and AGR retorting, including aqueous, gaseous, and organic liquid 

phases and suspended solids 

• Caustic agents, flocculants, and other chemicals common to treatment of industrial wastewaters 

• Ammonia chemicals used in the refrigeration system of the Shell sites 

• Sulfur compounds generated during the retorting and during secondary processing (hydrotreating) 

• Spent catalysts from the hydrotreatment process at the Enefit site 

Wastewater from RD&D Initiatives 

• Sanitary wastewater 

• Formation water (for 5 sites using in situ retorting) 

• Process water in the formation (a product of kerogen pyrolysis for 5 sites using in situ retorting) 

• Spent drilling fluid and drill cuttings 

• Pyrolysis water (or sour water) with suspended solids, sulfur, heavy metals, and water-soluble 

organics from retort operation 

• Equipment cleanout activities and boiler blowdown and steam condensate treatments (at those sites 

where boilers are operated) 

• Wastewaters from well installations 

• Water from mine dewatering (Enefit site) 

a Fuels for vehicles and equipment (including diesel and possibly gasoline for emergency power generators), 

fuels for industrial and comfort heating furnaces, boilers, or other external combustion sources (diesel and/or 

propane stored in aboveground tanks, or natural gas delivered by pipeline), and vehicle and equipment 

maintenance fluids (lubricating oils, glycol-based antifreeze, battery electrolytes, hydraulic, transmission, and 

brake fluids). Fluids are those typically used for maintenance of vehicles and equipment. For on-road 

vehicles, on-site maintenance is expected to be limited to fluid level maintenance. More substantial 

maintenance activities (e.g., oil changes, repairs, etc.) would occur at off-site facilities. Also included are 

dielectric fluids, miscellaneous cleaning solvents, miscellaneous welding gases, and corrosion control 

coatings (e.g., exterior-grade oil-based paints, two-part epoxy coatings and sealants). 
Final OSTS PEIS A-59 

previously heated and depleted zones. These hot gases are then introduced into the fractured 

zone to decompose the kerogen into producible hydrocarbons. 

The location of the 160-acre lease parcel granted for Chevron’s R&D activities is shown 

in Figure A-9. Access to the proposed project area is via Colorado State Highways 13 and/or 

64 and County Roads 5 (Piceance Creek), 26, 29, and 69. The lease parcel is situated adjacent to 

County Road 69 on Hunter Ridge at an elevation of 6,560 to 6,660 ft. 

 Chevron’s methodology for shale oil recovery applies to an oil shale deposit that is 

approximately 200 ft thick. This methodology entails drilling wells into the oil shale formation 

and applying a series of controlled horizontal fractures within the target interval induced by 

injecting CO2 gas into discrete areas of the target interval to effectively rubblize the production 

zone in a horizontal plane. If necessary, propellants and/or explosives might be directed into the 

specific horizontally and vertically limited area to facilitate further rubblization of the production 

zone in order to prepare it for heating and in-situ combustion. 

The seven phases of the process, as described in the EA for the project (BLM 2006a), are 

summarized below; some of the activities have since been completed: 

• Phase 1. A core would be extracted for use in developing a more 

comprehensive site-specific understanding of the geology, mineralogy, 

hydrogeology, and geophysical properties of the formation. 

• Phase 2. Activity would be directed at identifying and avoiding the existing 

natural fracture network. 

• Phase 3. One or more additional test wells would be drilled to confirm and 

verify the extent of the fracture network. 

• Phase 4. Additional fracturing of the shale would be facilitated by subjecting 

the formation to thermal cycles using hot CO2 gas brought in by CO2 tanker 

trucks. 

• Phase 5. The formation heating process would be initiated by circulating 

pressurized heated gas through the fractured interval of the formation. 

• Phase 6. This phase would involve the decomposition of the kerogen and 

production of shale oil. Before the formation reached the kerogen 

decomposition temperature, equipment would be installed to collect and 

process the produced water, gas, and shale oil. 

• Phase 7. After the recoverable kerogen was extracted from the initial wells, 

the proposed RD&D program would include integrating the heating process 

by drilling a new well pattern adjacent to the first and repeating the fracture 

process. Hot gases from in situ combustion of the residual organic material 

remaining in the oil shale would be used to heat the newly fractured zone. 
Final OSTS PEIS A-60 

Chevron believes that these fractured zones would have a predominantly horizontal 

component that would allow for the maintenance of barriers between the production zone and 

the upper and lower water-bearing units. The detection and avoidance of the natural vertical 

fractures within the formation is a key component of the proposed technology. 

A.5.3.1.1 Groundwater and Surface Water Management. As many as 20 groundwater 

monitoring wells will be drilled into both the upper and lower water-bearing units as part of a 

comprehensive groundwater monitoring program incorporated into the design of the proposed 

process. Additional observation wells may be installed as necessary to further monitor the 

process. 

A.5.3.1.2 Produced Shale Oil and Gas. Storage tanks and facilities will separate the 

produced gases from the shale oil and water, and liquid streams would then be trucked off-site to 

separate processing or disposal facilities. Preliminary estimates suggested production rates of 

5 or more barrels per day after 1 year of initiating the heating process. 

A.5.3.1.3 Storage and Disposal of Materials and Waste. The products used on-site 

will be typical of the products used in the oil and gas industry (lubricants, diesel fuel, gasoline, 

lubricating oils, solvents, and hydraulic fluid) and would be used, stored, and disposed of in 

accordance with all industry standards and practices, as well as in compliance with all federal, 

state, and local regulations. Smaller quantities of other materials, such as herbicides, paints, and 

other chemicals, will be used during facility operation and maintenance. Any produced water 

and/or flush water will be routed to 500-bbl storage tanks for transport off-site to an appropriate 

disposal facility. Spent caustic will be stored in 50-bbl tanks and transported off-site for disposal. 

No process wastewater is anticipated in the preliminary phases of the proposed project, but it is 

expected in the later phases of the program. Drilling fluid returns will be processed by a 

modularized solids control system to minimize spent drilling fluid generation. This system will 

produce relatively dry cuttings with minimal associated drilling fluid. The drilled cuttings and 

fluids will be collected in plastic-lined earthen pits approximately 100 ft by 100 ft with 6 ft of 

usable depth (8 ft deep). One pit for each of the four proposed well patterns (each of which 

would consist of 1 producer, 4 injectors, and 12 groundwater wells) would be anticipated. These 

pits will be kept clean and free of oil and other harmful constituents, constructed in accordance 

with industry regulations and BLM Gold Book standards and guidelines (DOI and USDA 2006), 

and designed to meet BLM specifications to deter and/or prevent migratory birds and other 

wildlife from accessing the contents. Used oil will be handled in accordance with Title 40, 

Part 279 of the Code of Federal Regulations (40 CFR Part 279). A used oil recycler will be 

contracted to handle all used oil. The proposed in-situ process will not include any aboveground 

retort activities; therefore, no spent shale will be brought to the surface as a waste product. 

 The management, maintenance, and disposal of sanitary wastewaters will be contracted 

through local providers. Solid waste products will be stored in closed, animal-proof containers so 

as not to attract wildlife and to prevent trash from being blown off-site. All solid waste will be 

managed, collected, and disposed of in accordance with existing laws and regulations by a local 
Final OSTS PEIS A-61 

contract provider. Other waste products will be collected and 

disposed of in accordance with existing laws, stipulations, and 

regulations. 

 The proposed in-situ process will not include any 

aboveground retort activities; therefore, no spent shale will be 

brought to the surface as a waste product. 

 Gas produced as a result of the proposed process will be 

burned as fuel or flared. Produced shale oil would be stored in 

100-bbl tanks and transported off-site for processing and 

subsequent delivery to consumer markets. 

A.5.3.1.4 Water Requirements. Table A-9 gives the 

amount of water consumed; water use will be limited to mixing 

additives and drilling mud, suppressing dust, and various purposes 

by personnel. The water required for construction and operation of 

the proposed process will be purchased from local permitted 

sources and trucked to the site. 

A.5.3.1.5 Staffing. The construction, drilling, and fracturing (Phases 1 through 4) of the 

proposed process would require from 10 to 100 contractors and employees. 

A.5.3.1.6 Utilities. Portable diesel generators will be used to provide the needed power 

during the preliminary phases of Chevron’s proposed RD&D project. Rights-of-way (ROWs) for 

power, communications, and natural gas will be constructed only if the fracturing phase was 

considered successful. The power line will be installed on elevated poles along with 

communication lines. The natural gas pipeline will be installed underground and will enter the 

proposed lease site by using the same 65-ft-wide combined ROW. 

A.5.3.1.7 Noise. The noise generated by this technology will fluctuate with the alternate 

construction and operation phases of the project. The construction, well drilling, and fracturing 

phases would generate noise for 2 to 4 months or longer, depending on the success of initial 

operations. The active retorting phases of the proposed project will generate less noise, but that 

noise will occur 24 hours a day over the life of the project. The noise-generating equipment for 

this process will be diesel and gas generators. 

Noise generated during the testing phase of the project will be from drill rigs installing 

monitoring wells and the heating/production wells. Equipment used will be designed to meet 

applicable Colorado Oil and Gas Conservation Commission allowable noise levels, which are 

expected to be 50 to 55 A-weighted decibels (dbA) for the tract in a rural/agricultural setting. 

Noise readings would be taken at the site during operations to verify noise levels. 

TABLE A-9 Estimated 

Water Needs per Year for 

Chevron RD&D Site 

 

Estimated Water 

Needs per Year 

Year bbl ac-ft 

 

2006 36,320 4.68 

2007 134,725 17.36 

2008 29,445 3.79 

2009 254,410 32.79 

2010 9,135 1.18 

2011 2,135 0.28 

2012 233,755 30.13 

2013 3,890 0.5 

 

Total 703,185 90.71 

Source: BLM (2006a). 
Final OSTS PEIS A-62 

A.5.3.1.8 Air Emissions. Air pollutant emissions will occur during construction (due to 

surface disturbance by earthmoving equipment, vehicle traffic fugitive dust, drilling activities, 

facility construction, and vehicle engine exhaust) and during production (including power 

generation, product and CO2 processing, and engine exhausts). 

The air pollution emission estimates were based on the best available engineering data 

assumptions and scientific judgment. However, where specific data or procedures were not 

available, reasonable but conservative assumptions were incorporated. For example, the air 

emission estimates assumed that project activities would operate at full production levels 

continuously (i.e., with no downtime). 

A.5.3.1.9 Transportation. The proposed RD&D project will not create additional access 

onto BLM lands; it would, however, increase traffic on existing roadways and contribute to 

fugitive dust along the unpaved county roads necessary for access to the site. 

Progress on the project as of early 2012 includes the following milestones: 

• By 2009, Chevron had completed geological and hydrological tests on the 

RD&D site. 

• In 2011, Chevron had drilled, logged, and cased one core hole; completed 

core studies and geological tests; drilled 15 groundwater monitoring wells; 

and performed various low-temperature recovery tests. Chevron continued to 

process cross-well tomography data and was developing a basin-wide 

hydrology model. 

A.5.3.1.10 Project Update. In March of 2012, Chevron announced that the company 

would discontinue lease activities and divest its BLM lease. 

A.5.3.2 AMSO, LLC (formerly EGL)28

 Information presented here regarding AMSO’s RD&D project was taken from the EA of 

the proposed activities (BLM 2006b) and the plan of development (AMSO 2009). Progress made 

and the status of the project as of early 2012 is summarized from a review of RD&D projects 

conducted by INTEK, Inc. and DOE (Crawford et al. 2012). The AMSO project will use an 

in situ retorting technology to test a 500-ft section of illite-rich oil shale, below the saline zone of 

the Green River Formation in the Piceance Basin of Colorado, at a depth of more than 2,000 ft. 

The AMSO tract is located approximately 27 mi west-northwest of Rio Blanco, Colorado, on a 

ridge between Ryan Gulch and Black Sulphur Creek at elevations ranging from 6,795 to 6,965 ft 

(Figure A-9). Both streams are tributaries of Piceance Creek. Vegetation is 48% rolling loam 

 

28 American Oil Shale, LLC, was formerly called EGL in the 2008 OSTS PEIS. 
Final OSTS PEIS A-63 

sagebrush and 52% pinyon-juniper. Construction of the RD&D facilities will be accompanied by 

clearance of 28 acres of rolling loam vegetation and 8 acres of pinyon-juniper vegetation. 

 AMSO made two major modifications to its RD&D program after submitting its initial 

Plan of Operations (Crawford et al. 2012). The amended plan of development (AMSO 2009) has 

been approved by the BLM. The first major change was to target a deeper oil shale formation, 

after concerns about protecting groundwater arose after preliminary research and analysis. 

Instead of the R-6 and R-7 (Mahogany) zones of the Parachute Creek Member of the Green 

River Formation originally targeted, the company is now targeting deeper illite shale resources in 

the R-1 and R-0 zones, which are isolated from groundwater resources by a nahcolite-rich 

caprock layer above, a condition AMSO intends to demonstrate in its RD&D efforts. The second 

major modification to AMSO’s program is to use a downhole heater to induce thermalmechanical fracturing of the formation, rather than a surface heater to heat circulated fluids. 

The new approach would reduce heat loss and protects intervening groundwater. A portion of 

produced liquids would be recirculated as before to enhance refluxing in the oil shale formation. 

As of April 2012, all of the analysis-phase operations planning and environmental assessment 

work for the project was complete; six tomography wells were drilled; heater and production 

wells were near completion; instrumentation was installed in heater, monitor, and production 

wells; production well casing was complete; and a full pilot test was awaiting resolution of 

problems with downhole equipment incurred in testing in late 2011. AMSO expects to complete 

performance testing of its technology by 2016. 

A single inclined heater-producer well will be used in the Pilot Test to determine the 

critically important aspects of vertical and lateral retort growth and confinement during the 

heating process. Any number of fluids (steam, gases, certain liquids) could be heated on the 

surface using boilers or other methods to heat the fluids. These hot fluids would be circulated to 

a heat exchanger submerged in the boiling pool. 

To introduce the heating fluids into the oil shale deposit, cased wells would vertically 

penetrate nearly the full length of the oil shale deposit to be tested. Once near the bottom of the 

oil shale zone, the wells will be drilled horizontally for a distance of about 2,000 ft to the 

opposite side of the pattern. 

AMSO’s technology is known as the Conduction, Convection, Reflux (CCRTM) retorting 

process. The CCRTM process uses a boiling pool of shale oil in the bottom of the retort in contact 

with a heat source. Hot vapors evolving from the boiling shale oil heat the surrounding shale 

with both direct sensible heat and latent heat of condensation as the vapors circulate through the 

underground retort. As the oil shale nearest the evolving hot vapors reach the retorting 

temperature (about 630°F), kerogen is retorted. Thermal expansion, in combination with 

geomechanical confinement of the surrounding rock formation, also causes the shale to break 

apart at the retort boundary. The fracturing of the adjacent rock causes additional shale to be 

exposed to the hot vapors, repeating the process and resulting in retort enlargement. 

The heat source will be an electric heater located in the underground retort, supplemented 

by circulating electrically heated hot fluids from the surface to the retort. The shale oil products 
Final OSTS PEIS A-64 

will be drawn to the surface through a production well, which may be the same as the heater well 

or through an adjacent well. 

The proposed surface facilities will consist of a separation/processing plant to handle the 

produced liquid and vapor streams generated from the retort. Produced liquids and gases will be 

directed to a thermal oxidizer. The production streams may contain up to 15% hydrogen sulfide 

(H2S) by weight. The H2S control by the oxidizer is designed to be 99.99% efficient. Retort 

products will fuel the oxidizer, and propane will be utilized during periods of startup, shutdown, 

and standby modes. Liquid streams include (1) stripped naphtha, (2) gas oil, (3) slop oil, and 

(4) sour water. A small fixed-roof tank will handle each liquid stream (four tanks total). Slop oil 

is a mixture of stripped naphtha and gas oil. This tank provides storage of off-run-conditions 

liquid product prior to destruction at the oxidizer. The sour water may contain 1.5% (by wt) H2S 

and 1.8% (by wt) ammonia (NH3); vapors from the sour water tank will also be directed to the 

thermal oxidizer. The other tanks will be vented to the atmosphere. 

A.5.3.2.1 Groundwater Management. To reduce the amount of groundwater 

infiltrating into the oil shale zone that would be heated, AMSO will establish a dewatered zone 

in the retorting zone. This will be accomplished with four to eight pumping wells surrounding 

the subsurface retort area. Extracted groundwater will be reinjected downgradient into the same 

aquifer intervals in order to maintain the regional water table and avoid disturbing baseflow to 

nearby streams. 

Upgradient and downgradient multilevel monitoring wells will be installed to 

characterize the structure and properties of local aquifers, establish predevelopment baseline 

groundwater conditions, better define the geology of the oil shale resource, and monitor water 

quality. 

After project completion, pumping and treating of contaminated groundwater will 

continue until groundwater quality meets applicable regulatory standards. 

A.5.3.2.2 Produced Shale Oil. The anticipated production rate for the R&D test phase is 

approximately 23 bbl/day, or about 2,000 bbl over the life of the R&D test run. 

A.5.3.2.3 Storage and Disposal of Materials and Waste. Wastewater from the site, 

including retort water (up to 50 bbl/day), boiler blowdown, and drilling waste, would be initially 

stored in tanks at the site and then trucked to a licensed disposal facility. 

A variety of materials typical of the oil and gas drilling and production operations 

prevalent in the Piceance Basin could be on-site during construction and operations, including 

lubricants, diesel fuel, gasoline, lubricating oils, solvents, and hydraulic fluid. Smaller quantities 

of other materials, such as herbicides, paints, and other chemicals, could be used during facility 

operation and maintenance. These materials could be used to control noxious weeds, facilitate 
Final OSTS PEIS A-65 

revegetation on disturbed areas, and operate and maintain the facility during the life of the 

project. 

Solid waste (human waste, garbage, etc.) will be generated during construction activities 

and during operation of the oil shale RD&D facility. Trash will be collected in animal-proof 

containers and periodically hauled to a sanitary landfill in Rio Blanco County. All other wastes 

will be collected and disposed of in a manner consistent with existing laws and regulations. 

A.5.3.2.4 Water Requirements. Start-up, dust suppression, personnel requirements, and 

drilling operations will require limited amounts of water that will be purchased and trucked to 

the site from local sources. Makeup water will be required for the boiler to compensate for minor 

steam losses and to maintain dissolved solids in the boiler at an appropriate level. Water needed 

for sustained operations will likewise be so acquired or taken from wells on-site if possible. The 

total volume of water required from outside sources for sustained operation will be 

approximately 80 bbl/day during the drilling phase, and 27 bbl/day during the sustained 

operation phase. 

A.5.3.2.5 Staffing. It is estimated that a total of 10 to 40 employees will be required 

during test operations; most employees will work during daylight hours. During construction of 

the test facilities and drilling of the test wells, more workers will be needed, and their numbers 

will vary from 10 to 100, depending on the phase of construction. 

A.5.3.2.6 Utilities. A new power line will interconnect an existing power line southwest 

of the tract and project facilities. The power line will extend approximately 1,760 ft from the 

southwestern corner of the tract to the existing power line and have a 25-ft-wide ROW. 

Construction of the power line could disturb as much as 1.0 acre outside the 160-acre tract 

boundary. 

A.5.3.2.7 Noise. Noise generated during the testing phase of the project will be from drill 

rigs installing monitoring wells and the heating/production wells. Equipment used will be 

designed to meet applicable Colorado Oil and Gas Conservation Commission allowable noise 

levels, which are expected to be 50 to 55 dbA for the tract in a rural/agricultural setting. Noise 

readings will be taken at the site during operations to verify noise levels. 

A.5.3.2.8 Air Emissions. Air pollution emissions were estimated on the basis of the best 

available engineering data assumptions and scientific judgment. However, where specific data or 

procedures were not available, reasonable but conservative assumptions were incorporated. For 

example, the air emission estimates assumed that project activities would operate at full 

production levels continuously (i.e., with no downtime). 
Final OSTS PEIS A-66 

Table A-10 gives the estimated NOx, carbon monoxide (CO), sulfur dioxide (SO2), 

PM10, and PM2.529 emissions associated with AMSO’s project for both construction and RD&D 

operation scenarios. The emission estimates include both an anticipated maximum daily basis 

and an annual basis. The construction sources include fugitive dust from road traffic and surface 

preparation and trenching construction activities and combustion emissions from drill rig 

operations. Operation sources include combustion emissions from AMSO’s boiler and fugitive 

dust from road traffic. Construction and road traffic were modeled by assuming activities would 

occur during the 7 a.m. to 7 p.m. 12-hour period 5 days per week. The drill rig and boiler were 

modeled by assuming that these activities would occur continuously. 

A.5.3.2.9 Transportation. Workers and contractors will commute to the job site during 

the test phase. Most traffic will be from Rifle, Meeker, and Rangely, on Piceance Creek Road 

and State Highways 13 and 64. Employer-provided housing is not contemplated for the test 

phase, but workers whose presence would be required for extended nonroutine testing might be 

temporarily housed in trailers. 

AMSO estimates that 10 light and 6 heavy vehicles will travel to the tract each day for a 

4- to 6-month duration. During the well drilling and facility construction period, 16 light and 

10 heavy vehicles per day will travel back and forth for a duration of 12 to 18 months. During 

the 3 to 4 years that the facility will be operating, approximately 15 light and 9 heavy vehicles 

per day would travel back and forth. During shale oil production, 3 tanker trucks will transload 

railcars at Lacy Siding west of Rifle each day. During reclamation, 2 light vehicles and 1 heavy 

vehicle will travel to and from the site each day, for a duration of 3 to 4 years. Heavy vehicles 

will include drill rigs, water trucks, and tanker trucks. Light vehicles will include passenger 

vehicles, trucks, and vans. Equipment will be obtained locally, depending on equipment/drill rig 

availability, and local services will be used whenever possible. Tankers will be of the standard 

weight, size, and axle arrangements normally used in the State of Colorado without special 

permits. 

A.5.3.3 Shell Frontier Oil and Gas 

Shell is conducting RD&D projects on three separate 160-acre sites in the northern part 

of the Piceance Basin in Rio Blanco County, Colorado (Figure A-9); information presented 

here regarding these projects is taken from the EA of the proposed activities (BLM 2006c), 

from the Addendum to the Plan of Operation for the Oil Shale Test Project Shell Frontier Oil and 

Gas, Inc. Lease COC 69167 for the Yellow Creek Project (Shell Frontier Oil and Gas 2008a), 

from the Addendum to the Plan of Operation for the E-ICP Test Project Shell Frontier Oil and 

Gas, Inc. Lease COC 69194 for the Advanced Heater Project (Shell Frontier Oil and Gas 2008b), 

and from an INTEK and DOE review of progress on the RD&D projects (Crawford et al. 2012). 

The elevation of the sites ranges between 6,580 and 7,060 ft. The sites will be used to test 

different methods of shale oil extraction, all of which are based on Shell’s proprietary ICP that 

 

29 PM10 = particulate matter with a mean aerodynamic diameter of 10 micrometers (m) or less; PM2.5 = 

particulate matter with a mean aerodynamic diameter of 2.5 m or less. 
Final OSTS PEIS A-67 

TABLE A-10 AMSO RD&D Project Air Emissions Summary 

 Emissions 

Source Constituent lb/day tons/yr 

 

Construction 

 Surface preparation PM10 10.71 0.49 

 PM2.5 0.97 0.044 

 

 Trenching PM10 6.12 0.28 

 PM2.5 0.555 0.025 

 

 Road traffic (heavy vehicle) PM10 11.582 2.114 

 PM2.5 1.776 0.324 

 

 Drill rig engine PM10 7.12 1.300 

 PM2.5 1.10 0.200 

 NOx 124.40 22.700 

 CO 152.90 27.900 

 

Operations 

 Boiler NOx 220 40.15 

 CO 20 3.65 

 SO2 465 84.85 

 

 Road traffic (heavy vehicle) PM10 13.898 2.537 

 PM2.5 2.131 0.389 

Source: BLM (2006b). 

converts kerogen contained in oil shale into ultraclean petroleum liquids and gas that require less 

processing to become finished transportation fuels (e.g., gasoline and jet and diesel fuels). The 

majority of the 160 acres for each of the sites will be affected through ground disturbance and 

the construction of buildings and associated infrastructure. 

The three sites have the following variations: 

• Site 1: ICPimplemented by recovering hydrocarbons from kerogen using 

self-contained heaters that heat the shale rock. 

• Site 2: Two-Step ICPimplemented by initially extracting nahcolite by 

injecting hot water into the shale and then recovering hydrocarbons through 

ICP once the nahcolite is removed. 

• Site 3: Electric-ICP (E-ICP)implemented by recovering hydrocarbons from 

kerogen using bare-wire heaters to heat the rock; some of the heating is 

created by the flow of electricity through the shale formation. 
Final OSTS PEIS A-68 

Site 1 Technology: ICP. For Shell Oil Shale Test Site 1, a freezewall will be installed 

to prevent groundwater from flowing into areas where ICP is being used. A series of 75 to 

125 holes approximately 6 to 10 ft apart will be drilled where the freeze wall would be created. 

The freeze holes will be drilled to a depth of approximately 1,150 ft. Aqua ammonia or another 

suitable chilled fluid (45F) will be circulated inside a closed-loop piping system and into the 

holes. The cold fluid will freeze the nearby rock and groundwater, and in 6 to 12 months, it will 

create a wall of frozen ground. The freeze wall will be maintained during both the production 

and reclamation phases of the ICP project. 

 After the freeze wall is established, 2 to 4 producer holes will be drilled inside the freeze 

wall and used to remove the groundwater trapped inside the wall. These holes will later be 

converted to producer holes that will remove the hydrocarbon products. The producer holes will 

be completed to a depth of approximately 1,050 ft. Pumps will be installed in each hole to bring 

the product to the surface. Approximately 5 to 20 heater holes will be drilled in the interior of the 

containment zones, spaced 8 to 30 ft apart, and electric heaters will be installed to uniformly heat 

the otherwise undisturbed hydrocarbon-bearing shale to between 550 and 750F. The heated 

zone will range between approximately 100 and 175 ft in thickness. The heaters will heat the 

resource target zone for approximately 1 to 2 years. Product recovery will occur concurrently 

with heating once the heated rock begins to release hydrocarbons and may continue for some 

period beyond heating. The total time period for heating and product recovery is estimated to 

be approximately 2 to 3 years. Oil shale production is expected to be approximately 10 to 

30 barrels of oil per day at full production. Total production may range from approximately 

1,500 to 4,000 barrels. 

 Additional holes will be used to monitor subsurface conditions (e.g., temperatures, 

pressures, and water levels). The monitoring holes will be placed inside and outside the freeze 

wall. 

 After ICP treatment, pumping water into the heated zone will allow recovery of the 

remaining hydrocarbons. This process, followed by a pump-and-treat process with water and 

possibly bioremediation, will reduce the amount of hydrocarbons in the heated shale to 

acceptable levels. Then the freeze wall will be allowed to thaw. 

Site 2 Technology: Two-Step ICP. Although significant areas of the Piceance Basin 

are amenable to ICP technology, the presence of excessive amounts of nahcolite limits the 

applicability of ICP in portions of the Piceance Basin. Nahcolite, also known as baking soda or 

sodium bicarbonate, occurs naturally within shale. The process to be used at this test site will 

be nearly the same as the process to be used in Site 1, with the exception of the extraction of 

nahcolite prior to removal of hydrocarbon material. The drilling for the freeze walls, heater 

holes, and extraction will be the same. Removal of the nahcolite prior to implementation of ICP 

will be required for efficient recovery of both the nahcolite and the petroleum products in the 

kerogen. Shell has demonstrated that nahcolite can be solution-mined by circulating hot water 

through the shale. The nahcolite, which is dissolved into the hot water and recovered from the 

hot water after it is pumped back to the surface, is a product of this process. Removal of the 

nahcolite increases the permeability and porosity of the remaining rock matrix and significantly 
Final OSTS PEIS A-69 

improves the thermal efficiency in recovering petroleum from the oil shale when the ICP process 

is used. 

 This two-step ICP technology will have a number of energy-saving benefits. The hot 

water used for nahcolite decomposition could be heated by using waste heat from previous areas 

where ICP had been implemented. Solution mining will preheat the oil shale in the mined zone 

to at least 250F using otherwise wasted heat. The water used for cooling the ICP-treated oil 

shale will pass through a surface heat exchanger to heat the water used for nahcolite solution 

mining, providing additional energy savings. 

 Removing the nahcolite and then dewatering will reduce the mass within the formation 

that must be heated to ICP temperatures, ultimately reducing the ICP energy requirements. 

Solution mining the nahcolite will increase the speed at which a heat front would move within 

the formation, thus reducing the time and energy requirements to produce oil and complete the 

project. 

 A freeze wall will be created before initiating nahcolite solution mining and will be 

maintained through implementation of ICP to contain groundwater. Following the solution 

mining of the nahcolite, electric heaters will be installed to heat the shale to ICP temperatures, 

and the solution mining holes will be converted to hydrocarbon production wells. The boundary 

between the solution-mined nahcolite-ICP region and the remaining nahcolite-bearing strata will 

provide an impermeable wall, in addition to the freeze wall, to prevent hydrocarbons from 

migrating out of and water coming into the heated area. 

 After ICP treatment occurred, the pumping of water into the heated zone will allow 

recovery of the remaining hydrocarbons. This process, followed by a pump-and-treat process 

with water and possibly bioremediation, will reduce the amount of hydrocarbons in the heated 

shale to acceptable levels. Then the freeze wall will be allowed to thaw. 

Site 3 Technology: Advanced Heater Test Site (E-ICP). The process used at Site 3 will 

be nearly the same as that used for Site 1 in terms of the amount and type of drilling and the 

extraction process. The freeze holes will be drilled to a depth of approximately 1,450 ft. The 

producer holes will be completed to a depth of approximately 1,150 ft. However, the technology 

for heating will be different. The economics of the ICP process could be improved dramatically 

if bare electrode heaters were installed that combined both thermal conduction and some heating 

generated by electricity flow through the shale formation. The bare electrode process is called 

E-ICP and is a patented in situ heating technology. The project will include about 6 to 21 vertical 

heaters spaced 8 to 30 ft apart. The bare electrode heaters are about 1,950 ft long and are 

designed to concentrate most of their heat output in the bottom 1,000 ft. With lower heater well 

capital costs and greater energy efficiency, E-ICP might increase the oil shale target resource by 

making much more of the Piceance Basin commercially attractive. Other than the difference in 

heater technology, the remainder of this process is comparable to the Oil Shale Test (Site 1). 
Final OSTS PEIS A-70 

A.5.3.3.1 Groundwater and Surface Water Management. Groundwater monitoring 

will be conducted at each site to assure compliance with groundwater regulations during and 

after the project. 

 Water requirements will vary throughout the life of each project. Water will be trucked to 

the sites for initial construction and drilling activities. Potable water will be trucked to the sites 

throughout the life of the facilities. 

 Once a freeze wall is formed, the water inside the wall will be removed by pumping prior 

to heating. The groundwater pumped from inside the freeze wall will be injected into wells 

located outside the freeze wall. The injection wells will be permitted per the requirements of the 

EPA Underground Injection Control Program. 

 During heating, water removed from within the freeze wall, along with the hydrocarbon 

products, will be treated in the processing facilities and recycled or discharged. Water used to 

recover nahcolite will be recycled into the process. Water that cannot be recycled or otherwise 

used will be treated to appropriate discharge standards in a process water treatment plant and 

released to surface drainage in a manner consistent with the requirements of a Colorado 

Department of Public Health and Environment discharge permit. 

 Groundwater will be used only after state approvals are received. Water wells will be 

drilled to provide additional water required by the operations, especially during reclamation 

following completion of hydrocarbon recovery. Reclamation will include flushing and cooling 

of the shale inside the freeze wall. 

 During dewatering operations, water from the dewatered zone will be reinjected into the 

same zone or potentially a different zone at another location on the property. 

 The pyrolysis process occurring within the approximately 130-ft by 100-ft test area will 

likely increase the porosity of the oil shale intervals because of the removal of kerogen, resulting 

in an increase in horizontal hydraulic conductivity. Shell’s testing to date, using its heating 

process on oil shale materials, suggests that the porosity of the rock will increase by about 30% 

as a result of the pyrolysis of kerogen and removal of oil. There will likely be a minimal increase 

in the vertical hydraulic conductivity associated with the heating effect on the rock mass. The 

removal of kerogen is not anticipated to affect the aperture widths of preexisting joints or 

fractures. 

 Heating of the oil shale during the pyrolysis phase could increase the vertical 

permeability of the confining units by enlarging preexisting joints or fractures. The potential 

consequence of the increased fracture apertures is that groundwater could flow more easily 

between the Upper and Lower Parachute Creek Units. 

Produced Shale Oil and Gas. For Sites 1 and 3, oil and gas production is expected to be 

approximately 10–30 bbl/day of oil. The quantity of gas produced does not justify the processing 

necessary to make it commercially available during the short time the Advanced Heater Project 
Final OSTS PEIS A-71 

will be operational; therefore, gas will be thermally destructed by flaring or incineration. Testing 

of gas quality and composition will occur to determine suitability for future commercial use. Oil 

and gas coming to the surface via the previously installed producer holes will be collected for 

further processing by traditional processing techniques. Full oil and gas production for the 

Nahcolite Test Site 2 will be approximately 1,500 bbl/day of oil in the form of untreated 

synthetic condensate. 

 The recovered product will include a mixture of liquid hydrocarbons, gas, and water that 

will be processed further to remove impurities and ready the products for transport off-site or 

reuse in the recovery process. This recovery process is a typical process used in the oil and gas 

industry. 

 The initial processing will separate the recovered product into three streams: liquid 

hydrocarbons, sour gas, and sour water. The term “sour” refers to the presence of sulfur 

compounds and CO2. Once the three streams are separated, each stream will be further processed 

to remove impurities. The waste streams generated during much of the processing will be 

recycled for further treatment. 

Nahcolite Recovery (Site 2). The nahcolite mining solution will be pumped to a 

processing building where the mineral will be removed. The process will remove the mineral 

from the water in a series of steps; the product will then be dried, stored, and loaded for market. 

Hot solution will be cooled; because the mineral is less soluble, it would crystallize. Centrifuges 

will drive off water to concentrate the crystallized material. The water will be reheated and 

recycled as barren solution. CO2 will be used to make a final product (sodium bicarbonate). 

 To minimize disturbance, the groundwater reclamation facilities will be built at the same 

location as the nahcolite processing facility. Additional engineering evaluations will optimize the 

site arrangements for these facilities. 

Refrigeration System. Appropriate procedures for storage, handling, and emergency 

response for ammonia chemicals used in the refrigeration system will be included in the Process 

Safety Management Manual to be developed in accordance with Occupational Safety and Health 

Administration regulations prior to operation. Emergency response procedures, including 

procedures for cleanup of spills and notification requirements, will be included in the Emergency 

Response Plan developed prior to operation. 

 A.5.3.3.2 Storage and Disposal of Materials and Waste. During the course of 

construction and operation, a variety of by-products and waste materials will be generated at 

each of the three sites. They will include construction waste, drill hole cuttings, garbage, and 

miscellaneous solid and sanitary wastes. 

 Surface construction operations will result in a variety of small waste products that might 

include paper, wood, scrap metal, refuse, or garbage. These materials will be collected in 
Final OSTS PEIS A-72 

appropriate containers and recycled or disposed of off-site in accordance with applicable 

regulations. 

 Approximately 200,000 ft3 of earth and rock materials will be generated at each test site 

during drilling operations for the project. Drill cuttings removed from the drilled holes will be 

dewatered so that the water can be recycled back to the drill rigs. The dewatered cuttings will be 

placed into a cutting pit. These nontoxic, non-acid-forming drill cuttings will be separated from 

free water and buried below grade. Burial depth and soil coverage will be sufficient such that the 

materials will not impede revegetation. 

 During operation, garbage from the site will be collected in appropriate containers and 

disposed of off-site. Waste oils, reagents, and laboratory chemicals that are not collected in 

sumps and treated at the water treatment plants will be recycled or disposed of off-site in 

accordance with applicable regulations. 

 The process of producing hydrocarbons from the oil shale will require processing and 

treating multiple materials. The production complex will include a refrigeration facility, 

nahcolite recovery process (at Site 2), groundwater reclamation facility, and hydrocarbon 

processing facility. Spill prevention, control, and countermeasure plans and best management 

practices will need to be implemented for each stage of production and for all processing 

facilities. In addition, all waste by-products from the site will need to be properly transported and 

disposed of according to all rules and regulations regarding the specific waste by-product. These 

waste by-products will include but not be limited to biosolids effluent and reverse-osmosis reject 

effluent. 

 A combination of sanitary waste handling methods will be employed. Some sanitary 

waste, such as that collected in temporary toilet facilities, may be shipped to an approved facility 

for off-site treatment and disposal. Any gray water or black water disposed of on-site will be 

treated in an appropriate sewage processing unit or disposed of according to standards via an 

approved septic system with a clarifier and drain field. 

 A.5.3.3.3 Water Requirements. Water requirements will vary throughout the project 

life. Water uses will include construction, potable water, dust control, drilling, processing, 

filling, and cooling of the heated interval for reclamation, and rinsing of the zone inside the 

freeze wall. 

 Water will be trucked to the site for initial construction and drilling activities. Potable 

water for personnel consumption will be trucked to the site throughout the life of the facilities. 

 On-site water will be used for most operational uses and will be supplied from water 

wells drilled for that purpose. The well will supply water needed for processing and reclamation. 

Peak pumping demand (250 to 300 gpm, approximately 400 to 480 ac-ft/yr) will occur during the 

cooling and resaturation phase of the reclamation cycle. If the water well is available during 

construction and drilling, this water will supplement or replace construction and drilling water 

trucked to the site. 
Final OSTS PEIS A-73 

Water needs for each phase of the operation are outlined below and summarized in 

Table A-11. The projected water needs are estimates and are subject to change as additional 

information becomes available and facility designs are finalized. The estimate of the amount of 

water needed for process water in the 2006 EA was 10 gpm. The addenda to the Plan of 

Operation, dated July 17, 2008, state that overall water requirements are expected to be less. This 

water will be supplied from groundwater extracted from either the Uinta or Upper Parachute 

Creek Units. Water rights required for the project will be acquired prior to start-up of the 

operation. The combined annual volume of water required for all three sites was unknown at the 

time the 2006 EA was prepared and would vary on the basis of when each project started and 

how each project progressed. On the basis of the assumption that all three sites would operate at 

the same time for at least 1 year, the combined process water needs will be a minimum of 

30 gpm. This flow rate equates to an annual volume of almost 48 ac-ft/yr. 

 Construction water will be trucked to the sites as necessary to meet needs for compaction, 

dust control, and miscellaneous uses. Potable water needed during construction would be brought 

to the sites. Water required for drilling will be trucked to the sites until water from the on-site 

water supply well is available to supplement or replace trucked water. 

 Water will be needed for various processing and operating needs. Water removed with 

the hydrocarbon products will be treated in the processing facilities and recycled or discharged at 

a permitted discharge point. The locations of discharge points had not been determined in the 

2006 EA. It is anticipated that excess water will be available during the initial processing period 

as a result of dewatering operations from within the freeze wall containment area and that there 

will be no need for the water supply well to provide water for processing during this initial 

period. As processing progresses, there will be a need for additional water. 

 Water will also be needed to conduct reclamation filling and cooling of the heated 

interval within the freeze wall containment barrier as well as for rinsing the heated interval. This 

water will be a combination of recycle water and makeup water from the water supply well, as 

needed. During reclamation, a water supply will be needed for initial stages of flushing and 

cooling. Two wells would be completed in the upper Parachute Creek Unit to serve as 

reclamation water supply wells. However, only one well would be used at a time. 

A.5.3.3.4 Staffing. Employment of the maximum number of people at the sites will 

occur during construction and drilling. An estimated maximum of approximately 720 individuals 

would be employed at Sites 1 and 3 during the construction and drilling period. At Site 2, an 

estimated maximum of approximately 700 individuals would be employed during the 

construction and drilling period. However, because the three test sites will not be developed at 

the same time, the number of workers employed during construction and drilling would not be 

cumulative. Once construction is completed, the maximum expected employment will be 

approximately 155 individuals at Sites 1 and 3, and 150 individuals at Site 2. 

A.5.3.3.5 Utilities. Estimates of electricity and gas requirements were not provided in 

the EA. 
Final OSTS PEIS A-74 

TABLE A-11 Anticipated Water Usage for the Proposed Shell RD&D Projectsa

 

Estimated Water Usage 

Water 

Requirements Water Source Site 1 Site 2b Site 3b

 

Potable water Trucked in Unknown Unknown Unknown 

 

Drilling Trucked in or

groundwater 

5 gpm 

(8 ac-ft/yr) 

5 gpm 

(8 ac-ft/yr) 

5 gpm 

(8 ac-ft/yr) 

 

Construction water Trucked in 6 gpm 

(10 ac-ft/yr) 

6 gpm 

(10 ac-ft/yr) 

6 gpm 

(10 ac-ft/yr) 

 

Process waterc Groundwater 10 gpm 

(16 ac-ft/yr) 

10 gpm 

(16 ac-ft/yr) 

10 gpm 

(16 ac-ft/yr) 

 

Nahcolite recoveryd Groundwater NA 7.8 million gal

(24 ac-ft/yr)e

NA 

 

Reclamationf

 Groundwater 300 gpm max 

(480 ac-ft/yr) 

300 gpm max 

(480 ac-ft/yr) 

300 gpm max 

(480 ac-ft/yr) 

a Abbreviations: max = maximum anticipated or estimated; NA = not applicable. 

b Estimated quantities of water usage for Sites 2 and 3 are based on the plan of 

development for Site 1. 

c Initially, groundwater would be obtained from extraction wells inside the freeze wall 

(initial dewatering); subsequent process water would come from water wells completed 

in the Upper Parachute Creek Unit. Process water is treated and recycled again for 

process operations. 

d Groundwater for nahcolite solution mining would largely originate from dewatering of 

the freeze wall interior area, with additional water from extraction wells in the Upper 

Parachute Creek Unit located outside of the freeze wall. Water used would be treated 

and reused. 

e Volume estimated is for nahcolite solution mining of a 130-ft by 100-ft pyrolyzed zone 

footprint. Water would be treated and reused. 

f

 Reclamation includes quenching, cooling, and reclamation of the pyrolyzed zone. 

Groundwater would originate from extraction wells in the Upper Parachute Creek Unit 

located outside the freeze wall, and it would be treated and reused. 

Source: BLM (2006c). 
Final OSTS PEIS A-75 

A.5.3.3.6 Noise. Noise generated during the testing phase of the project will be from drill 

rigs installing monitoring wells and from the heating/production wells. Equipment used will be 

designed to meet applicable Colorado Oil and Gas Conservation Commission allowable noise 

levels, which are expected to be 50 to 55 dbA for the tract in a rural/agricultural setting. Noise 

readings will be taken at the site during operations to verify noise levels. 

A.5.3.3.7 Air Emissions. The air pollution emission estimates for each of the three Shell 

sites were based on the best available engineering data assumptions and scientific judgment. 

However, when specific data or procedures were not available, reasonable but conservative 

assumptions were incorporated. For example, the air emission estimates assumed that project 

activities would operate at full production levels continuously (i.e., with no downtime). 

A.5.3.3.8 Transportation. Access to each of the three sites will be provided by 

constructing an access road to connect the site to existing county roads. Initial construction 

activities will include development of the site access road to a running width of approximately 

24 ft to allow heavy equipment to travel in two directions. The access road will be paved with 

asphalt for the 24-ft width and include appropriate ditches and culverts to maintain drainage 

control. Access to the sites from public roads will be restricted by an entry gate. An estimated 

300 to 650 vehicles per day will access the sites during construction. 

A.5.3.3.9 Project Updates. Progress on the three Shell RD&D projects was reviewed in 

spring 2012 (Crawford et al. 2012). At that time at Shell Site 1, Shell had not yet initiated oil 

shale test activities. Between 2002 and 2004, Shell tested ICP heating, pyrolysis, production, and 

active remediation on the Shell Mahogany Isolation Test project on private land in the Piceance 

Basin. This test also demonstrated the ability to establish and maintain an effective freeze wall 

over the entire oil shale interval. Shell continues to monitor groundwater to verify effective 

flushing and remediation of the test zone. 

 Shell’s Site 2 project has had a significant change from the original plan. As of 2008, the 

plan has been modified to target the saline zone below the R-4 zone to allow testing in the 

nahcolite zone without a freeze wall. There has been no change in the objective to first recover 

nahcolite to develop permeability for oil shale recovery. Shell has completed baseline 

environmental studies; research, design, and permitting; and installed 13 heater wells, 2 producer 

wells, and 6 observer wells with a central leach well. 

 Regarding Shell’s Site 3 project, according to the 2008 addendum to the Plan of 

Operation (Shell Frontier Oil and Gas 2008b), the project, referred to as the Advanced Heater 

Project, will be completed with a smaller footprint, lower production, and less surface 

infrastructure than originally proposed, but would provide similar information and demonstration 

of the technology. In addition, the scaled-down test will employ the electrode in situ conversion 

process and freeze wall technology on a shorter heated interval higher in the formation than 

originally proposed, with less production of gas and oil, but of sufficient quantity for R&D 

purposes. 
Final OSTS PEIS A-76 

A.5.3.4 Enefit American Oil (Formerly OSEC)30

Enefit American Oil is a wholly owned subsidiary of Enefit (known as Eesti Energia for 

activities in Estonia). The Utah project was previously owned and operated by Oil Shale 

Exploration Company (OSEC). In March 2011, Enefit acquired 100% of OSEC’s shares and 

assumed full ownership and control of the project and all of OSEC’s assets. Enefit renamed 

OSEC as Enefit American Oil and has continued development of the project with several key 

modifications to the business plan and the RD&D plan put forward by OSEC and outlined in the 

following paragraphs. These modifications are currently under discussion and pending approval 

of BLM’s Vernal Field Office. As such, they are outlined only briefly below. The Utah Oil Shale 

Project, located in the Uinta Basin of eastern Utah, is designed to develop a greenfield oil shale 

mining and shale oil production complex producing approximately 30 million tons of oil shale 

rock per year and 50,000 barrels per day of premium quality refinery ready shale oil from the 

Green River Formation. Shale oil will be produced from multiple new-generation Enefit 

Technology surface retorts with on-site upgrading of the raw oil. The proposed facility will be 

located in the Uinta Basin, approximately 12 mi southeast of Bonanza in Uintah County, Utah. 

The RD&D Development Phase is broken up into two sub-phases, which build on the test work 

and progress of the previous sub-phase. The second sub-phase will include completion of the 

Enefit Pilot testing and PreFEED (Preliminary Front End Engineering Design) and completion of 

the application for conversion of the lease. New or unexpected information in an earlier phase 

may affect the timing or activities in a following phase. The RD&D Development Phase 

activities will be carried out on both the BLM RD&D lease property and Enefit American Oil’s 

adjacent private skyline property, as well as off-site at Enefit’s R&D center in Frankfurt, 

Germany. As Enefit has a proven technology operating industrially in Estonia and is not 

developing a new technology, the RD&D phases’ goal will be to prove the technology of, and 

optimize the design for, this specific resource in Utah (Enefit 2012). 

In 2011, Enefit acquired the former OSEC RD&D lease at the White River Mine site 

(160 acres) in Uintah County, Utah (Figure A-9). OSEC had proposed a three-phase RD&D 

project to test shale oil recovery by using the ATP retort technology and by providing incoming 

natural gas via a pipeline through the “western” ROW alignment. Information presented below 

regarding this project is taken from the EA of OSEC’s proposed activities (BLM 2007). The 

details of the project as presented below will undoubtedly change under Enefit’s ownership. 

They are presented here to depict the nature of the research, development, and demonstration 

work that would have been conducted by the previous lessee and will be likely carried over to 

some extent by Enefit. As OSEC originally proposed, Enefit will employ underground mining 

and aboveground retorting. However, the company will employ its own version of the proposed 

technologies reviewed here based on its Enefit 280 plant under construction in Estonia 

(Enefit 2011). The ATP system proposed by OSEC is a thermal process for pyrolyzing oil shale. 

The primary unit is the ATP Processor, which is a modified horizontal rotary kiln. The ATP 

Processor has four internal zones in which the four stages of ore processing occur: (1) preheating 

of the feedstock, (2) pyrolysis of the oil shale under anaerobic conditions, (3) combustion of 

coked solids to provide the process heat requirements, and (4) cooling of the combustion 

products by heat transfer to the incoming feed. 

 

30 Enefit American Oil was formerly called OSEC in the 2008 PEIS. 
Final OSTS PEIS A-77 

Phase 1 of the project is expected to last approximately 11 months according to the 

2007 EA. During this time, OSEC, now Enefit, will remove approximately 1,000 tons of oil 

shale from the White River Mine’s on-site surface stockpile for processing at the existing ATP 

pilot plant unit in Calgary, Alberta, Canada. 

 According to the EA, the 1,000 tons of shale will be transported by truck from the 

160-acre lease out of the project area to a gravel pit in Uintah County, where the material will be 

crushed to design specifications (3/8 in.). The crushed shale (total 1,000 tons) will be trucked to 

Calgary for testing by UMATAC in its 4-ton/h ATP Processor pilot plant. During Phase 1, no 

crushing of oil shale will be performed within the White River Mine lease area. 

 According to the EA, about 650 bbl of raw shale oil will be produced from the 1,000 tons 

of oil shale processed. Approximately 800 tons of non-Resource Conservation and Recovery Act 

(RCRA) hazardous spent shale will be produced from the processing of the 1,000 tons of feed 

shale. Samples of this material will be retained for testing and analysis in Canada and the 

United States. The remaining spent shale will be disposed of in a licensed landfill in Alberta, or 

it would be stored on-site in Alberta pending identification of a beneficial reuse. 

 No fuel storage, office facilities, overnight accommodations, toilets, or drinking water 

supply will be established at the White River Mine lease area during Phase 1. Although the 

loading and trucking operation is not expected to be dusty, some minor amounts of water may be 

required to control dust during the loading of the shale feed into the trucks at the White River 

Mine. All water required for this phase will be trucked in by a local supplier and dispensed from 

a water truck. No water rights will be needed for this phase of work. The fugitive dust emissions 

associated with loading the oil shale from the existing surface stockpile, road dust, and exhaust 

emissions from the front-end loader and trucks (short-term activities) will be the only air 

emissions associated with the Phase 1 operations within the 160-acre leasehold. 

Phase 2 of the RD&D project will last about 14 months, and involve the mobilization of 

the UMATAC 4-ton/h ATP Processor pilot plant and associated equipment from Calgary to the 

White River Mine lease area. Shale for processing will initially come from the existing surface 

stockpiles. Enefit will reopen the White River Mine and begin mining fresh oil shale for use as 

feed to the plant during the latter stage of Phase 2. 

 Phase 2 construction will involve a relatively small amount of new construction work onsite. The trailer-mounted ATP pilot plant will be mobilized from Calgary and set up on-site on an 

impervious base pad. A fuel tank area will be constructed with a liner and an embankment 

surrounding it. An additional aboveground storage tank area will be established for shale oil 

product storage and load out; these tanks will sit on a liner within an embankment. There will 

also be a facility for on-site crushing, stockpiling, and ore handling. 

 The major Phase 2 construction activity will involve reopening the mine and constructing 

a spent-shale disposal area. Approximately 10,000 tons of oil shale will be processed through the 

ATP Processor pilot plant during Phase 2. 
Final OSTS PEIS A-78 

Phase 3 of the RD&D project will involve the design, permitting, and fabrication of a 

250-ton/h ATP Processor demonstration plant and construction of that plant within the 160-acre 

lease area. It will require 2 years to permit, engineer, and construct the plant. Also, the mine will 

be developed sufficiently to support the mining of 1.5 million tons/yr of oil shale, which will be 

used as feed for the operation of the demonstration plant. Following commissioning, the plant 

will operate for 2 years so enough operational, technical, environmental, and financial 

information can be compiled to make an informed decision on whether to proceed to a 

commercial project. 

 Preparation for Phase 3 operations will involve significant on-site construction activity, 

particularly related to the new 250-ton/h ATP demonstration plant and all the ancillary 

equipment. Many of the demonstration plant components will be fabricated elsewhere and 

transported to the site for final assembly and erection. This will lessen the amount of laydown 

space required during construction and the number of construction workers needed at the site. 

The most significant permanent surface feature constructed during Phase 3 will be the 38-acre 

storage area for containing the 2.2 million tons of spent shale that may be generated during this 

phase of work. 

 Approximately 2.7 million tons of oil shale will be processed through the ATP Processor 

demonstration plant during Phase 3. The source of the shale feed will be the reopened mine. All 

mined shale will be stockpiled and crushed/blended at the surface within the 160-acre lease area. 

It is expected that all shale mined will be processed (i.e., there will be no fines rejects produced 

during the shale crushing activities). 

 In addition to the construction of the ATP Processor plant and ancillary equipment on the 

160-acre lease, it will be necessary to construct/install natural gas, electric power, and water lines 

along the proposed ROWs. 

 A.5.3.4.1 Storage and Disposal of Materials and Waste. During Phase 2, 

approximately 8,000 tons of spent shale will be generated and placed in a small valley 

impoundment, less than 2 acres in size. The impoundment will be bermed, and surface water 

runoff will be directed around the impoundment to prevent stormwater runoff from other areas 

of the lease from contacting the pile of spent shale. Overall, flow will be directed to the gully 

near the dam. 

 During Phase 3, 2.2 million tons of spent shale will be produced and disposed of at a 

38-acre storage area. Minor amounts of construction-related wastes will also be generated during 

the rehabilitation of existing structures and the construction of new facilities and structures 

associated with the Phase 3 250-ton/h demonstration work. Such wastes could include scrap 

metal or wood, concrete, and miscellaneous trash from the packaging of the construction 

materials. These materials will be temporarily staged in roll-offs and trucked to an off-site solid 

waste facility. 

 Shale oil typically contains 0.5 to 0.75% sulfur (OTA 1980b). Sulfur compounds 

generated during retorting and secondary processing (hydrotreating) are primarily in the form of 
Final OSTS PEIS A-79 

H2S, with lesser amounts of mercaptans. Through the treatment train process (i.e., air emission 

control devices and/or wastewater treatment), sulfur-bearing solid wastes will be generated. 

 The hydrotreatment process will generate a variety of waste products, including sulfurcontaining residuum and spent catalysts. Spent catalyst, which is considered a listed RCRA 

hazardous waste (K071), will consist of aluminum silicate and various metals (typically cobalt, 

molybdenum, nickel, and/or tungsten). These waste materials will be disposed of at an 

appropriate off-site disposal facility. Prior to disposal, the wastes will be contained in waste 

storage areas built with appropriate spill containment features. 

Occasionally, waste oils will be generated from equipment maintenance activities during 

Phases 2 and 3. In addition, the hydrotreatment process and wastewater treatment of the process 

waters will produce large volumes of oily sludges. All such materials will be temporarily stored 

on the 160-acre lease site and trucked off-site to a licensed facility for treatment and disposal. 

Mine Water. During Phase 2, the mine will be dewatered as part of the reopening 

process. Mine water of good quality will be discharged to the existing retention dam area. The 

exact volume of such water is not known, but it would amount to more than 2 million gal if the 

water was pooled to the top of the Birds Nest Aquifer. Mine water below the bulkhead may 

contain levels of petroleum-based compounds resulting from contact with the oil shale and the 

bitumen seep in the lower portion of the mine. This water will likely be trucked off-site for 

treatment and disposal at an approved facility. 

 During mining operations, water from dewatering of the mine may contain petroleumbased compounds. During Phase 2 operations, this water will be temporarily stored in tanks. 

Depending on test results, it will then either be discharged to an on-lease drainage channel to 

flow toward the retention dam area (if the test showed that it met agreed-upon discharge criteria) 

or trucked off-site. The appropriate frequency of testing the water will be stipulated on the basis 

of the results from the initial test of mine water conducted prior to the reopening of the mine. 

 During Phase 3, mine water that did not meet water quality standards will be treated 

through the process wastewater treatment system, along with wastewater from the air treatment 

and hydrotreatment processes. 

Connate and Retort Water. Approximately 150 tons (35,700 gal) of connate water 

(water trapped in shale pore spaces) will be generated during Phase 2, and 40,000 tons 

(9.5 million gal) will be generated during Phase 3. The connate water may be suitable for use in 

remoistening and cooling the spent shale without treatment. If the connate water does not meet 

appropriate criteria, it will be trucked off-site for treatment and disposal during Phase 2 RD&D 

activities and will be treated in a wastewater treatment system on the 160-acre lease site during 

Phase 3.

 Approximately 200 tons (48,000 gal) of retort water (chemically bound moisture in the 

shale) will be generated during Phase 2, and approximately 55,000 tons (13.2 million gal) will be 
Final OSTS PEIS A-80 

generated during Phase 3. Retort water often contains phenols, H2S, or trace levels of petroleum 

constituents that may require treatment before the water can be used for cooling and moistening 

spent shale or discharged to an existing retention dam. During Phase 2, all retort water will be 

temporarily stored on the lease site, tested, and, if it meets appropriate water quality criteria, 

used to cool the spent shale or trucked off-site for treatment and disposal. During Phase 3, a 

wastewater treatment facility on the 160-acre lease site will be used to treat the retort water to 

remove H2S, NH3, phenols, and other constituents of concern. It is anticipated that following 

treatment, nearly all of the water will be used to cool and moisten the spent shale or otherwise 

reused in the process. Small amounts of water not needed for cooling and moistening the spent 

shale may be discharged to a drainage feature leading to the retention dam area. 

 Process washdown is water that is regularly used to clean the retort and other equipment 

during the on-site operations. Such water may contain high levels of sediment, and it may also 

contain oily residues from the equipment. 

 All the sour water generated during Phase 3 will be stored and treated on-site prior to 

being used for controlling dust or moistening the spent shale. Depending on chemical analysis 

results, the sour water treatment may include stripping of NH3 and H2S, followed by biological 

aeration. 

Sanitary Sewage Effluent. During routine daily operations in Phase 2 and Phase 3, 

workers will generate sanitary wastes. These, along with other wash water, will be processed in 

an existing closed sanitary wastewater treatment system on the 160-acre lease site. Any sanitary 

sewage generated before the repair and testing of the on-site system will be collected and trucked 

to an off-site wastewater treatment plant. 

A.5.3.4.2 Produced Shale Oil and Gas. Approximately 6,000 bbl of raw shale oil will 

be produced during Phase 2. All oil produced will be temporarily stored in aboveground tanks 

located within the 160-acre lease area before being trucked to an off-site facility for sale. 

 Approximately 1.8 million bbl of raw shale oil is expected to be produced during 

Phase 3. It is anticipated that this oil will be hydrotreated on-site to produce a synthetic crude oil 

product. The synthetic crude oil will be temporarily stored in aboveground tanks on-site. The 

product will be trucked off-site to a refinery or delivered to a nearby pipeline that will have the 

capacity and specifications to accept this upgraded shale oil. 

A.5.3.4.3 Water Requirements. The amount of makeup water required in Phase 2 for 

processing the oil shale is estimated to be approximately 2 bbl (84 gal) per ton of shale feed, half 

of which will be needed to cool and moisten the spent shale. This means that the total makeup 

water requirement for Phase 2 will be 20,000 bbl of water. Small amounts of additional water 

may be required on-site for drinking, cooking, laundry, and toilet facilities for the Phase 2 

workforce. All Phase 2 water needs (potable and process) will be trucked to the site by a local 
Final OSTS PEIS A-81 

supplier that has the appropriate water rights. The water will be stored in aboveground tanks 

within the 160-acre lease area. No water rights will be needed by Enefit for this phase of work. 

 The total amount of Phase 3 water needed to process the oil shale (i.e., makeup water) is 

estimated to be on the order of 4.1 million bbl. This is equivalent to a peak water demand of 

380,000 gal/day while the processing plant is operating. The makeup water will be supplied from 

water wells established in the Birds Nest Aquifer (two to three wells located in the northwestern 

portion of the 160-acre lease site), from wells in the White River alluvial deposits (wells installed 

as part of the earlier mine development activities that are north of the 160-acre lease), or from a 

direct intake in the White River. Water pumped from these sources will be stored in aboveground 

tanks on-site. 

 A potable water tank will be placed near the trailers to supply domestic needs; the potable 

water will be trucked to the site. A process water tank with a capacity of about 750 bbl will be 

installed next to the plant. 

 A.5.3.4.4 Staffing. It is estimated that the operational workforce at the site during 

Phase 3 operations will be composed of approximately 120 individuals. Offices and shower and 

toilet blocks will be provided on-site. 

 A.5.3.4.5 Utilities. Electricity required for the mine, pilot plant, and on-site 

accommodations will be provided by diesel generators established within the 160-acre lease area 

(1-MW total capacity). Propane will be used to provide heat to the process during start-up 

periods as well as heat for office and field trailers. Also, diesel fuel will be used to run surface 

and underground mine vehicles and equipment on-site. All diesel and propane fuel will be 

trucked in and stored on-site in aboveground tanks. The diesel tanks will be placed in lined and 

bermed containment areas. 

 Up to 14 MW of electric power may be required at the site during Phase 3, and it is 

assumed that electric power to the site will be provided from the grid via a new 138-kV 

transmission line. Emergency diesel generator capacity will also be provided on-site to meet 

both plant backup and mine operational and safety requirements. 

 Natural gas or propane will be required for the operation of the ATP Processor 

demonstration plant. Further studies are required to assess whether it will be feasible to truck 

in propane gas or whether a pipeline connection to a natural gas supply will be required. 

 A.5.3.4.6 Air Emissions. The sources of air emissions will vary during the three phases 

of RD&D activities on the site. These sources are listed by phase in Tables A-12 through A-16. 

The ATP unit and the hydrotreatment unit will be fully permitted under the Clean Air Act and 

have all the emission control equipment required by the Act. 
Final OSTS PEIS A-82 

 Greenhouse gas emissions will be generated on-site during both Phase 2 and Phase 3 

operations. They will originate mostly from the retorting of the shale feed (see Tables A-12 and 

A-13, respectively). Additional greenhouse gas emissions will be produced from the burning of 

coal at the Bonanza Power Plant to generate electric power. 

A.5.3.4.7 Project Update. OSEC completed a technical, economic, and environmental 

feasibility study in 2009. As part of this effort, OSEC constructed an air quality monitoring 

station and developed an environmental baseline for the RD&D site. Enefit acquired the project 

in March 2011 and is planning to use the Enefit 280 surface retort technology being developed in 

Estonia. The company has sent Utah oil shale samples to Germany for analysis. A conceptual 

study was completed in 2011 and an environmental baseline study, planning for an EIS, and 

preparation of a Mine Development Plan are underway (Crawford et al. 2012). Enefit’s current 

projected timeline is to complete construction of a 25,000-bbl/day production facility in 2017, 

begin production at 25,000 bbl/day in 2020, complete construction of a second stage 

25,000-bbl/day facility in 2021, and begin production at a rate of 50,000 bbl/day in 2024. These 

projections assume that Enefit’s current 160-acre lease will be expanded to include its 4,960-acre 

BLM preferential lease area to a total of 5,120 acres, once Enefit demonstrates the commercial 

viability of shale oil production. 

TABLE A-12 Phase I Estimated Emissions 

Source: This table is reproduced as contained in Table A-12 of BLM (2007).
Final OSTS PEIS A-83 

TABLE A-13 Phase 2 Estimated Emissions 

Source: This table is reproduced as contained in Table A-13 of BLM (2007). 
Final OSTS PEIS A-84 

TABLE A-14 Phase 3 Estimated Emissions 

Source: This table is reproduced as contained in Table A-14 of BLM (2007). 
Final OSTS PEIS A-85 

TABLE A-15 Phase 2 Greenhouse Gas Emissions 

Source: This table is reproduced as contained in Table A-15 of BLM (2007). 

A.5.3.5 ExxonMobil 

 Exxon Mobil submitted a proposal for an RD&D project in 2010 in response to BLM’s 

second-round solicitation. The project would employ in situ technologies to extract kerogen and 

possibly, sodium mineral resources from below ground and would be located on 160 acres just 

east of several current RD&D projects in the Piceance Basin in Colorado, as shown in 

Figure A-9. The following discussion is based on information in the Plan of Operation for the 

proposed project (ExxonMobil 2011). 

ExxonMobil proposes to use its ElectrofracTM process, which is designed to heat oil shale 

in situ by building a hydraulic fracture in the oil shale and filling the fracture with an electrically 

conductive material. As electricity is conducted through the material, it serves as a resistive 

heating element. Heat flows from the fracture into the oil shale formation, gradually converting 

the solid organic matter of the oil shale into oil and gas. The oil and gas are produced by 

conventional methods. No circulating fluid is expected to be required to recover hydrocarbons. 

Upon conclusion of hydrocarbon production, ExxonMobil proposes to test a second patented 

technology to recover sodium-bearing minerals. As the formation cools, some production wells 
Final OSTS PEIS A-86 

TABLE A-16 Phase 3 Greenhouse Gas Emissions 

Source: This table is reproduced as contained in Table A-16 of BLM (2007). 

would be converted to water injection wells for this purpose. Water would be injected into the 

fracture network and, heated upon entry into the hot oil shale, would dissolve sodium-bearing 

minerals, which would be recovered in the produced water. Recovered natrite could then be 

converted to sodium bicarbonate, as needed, with the addition of carbon dioxide. 

Design and Permitting (Years 1–2) will involve road construction, site preparation and 

installation of facilities. An estimated maximum of 1 to 4 miles of existing road upgrades and 

new roads will be needed within the proposed lease area and to connect with nearby County 

Road 83. Total surface disturbance will not exceed 50 acres at any given time, exclusive of 

roads, utilities, and produced water and gas pipeline right of ways. Site buildings will include a 

temporary building or trailer for office space, and a warehouse or storage shed for equipment. A 
Final OSTS PEIS A-87 

fence surrounding areas of activity will protect livestock and wild game. Electricity will either be 

provided through a tie-in with the local electrical grid, or will be supplied from portable 

generators equipped with appropriate noise and emission controls. Water for all needs will be 

trucked to the site. 

Phase I (Year 3) will focus on drilling and subsurface work to construct two successful 

ElectrofracTM fractures at depth. Successfully building an electrically conductive fracture in the 

zone of interest is critical to further research phases. 

Phase II (Year 4) will focus on installation of production and monitoring wells; installing 

a utility tie-in and production headers and piping; and erection of facilities required to analyze, 

process, store, and dispose of fluids produced from pyrolysis of oil shale kerogen. About 200 kW 

of electrical power from the nearby power grid will be delivered to each of the two ElectrofracTM 

fractures to resistively heat the formation. Production wells will be placed appropriately to 

collect hydrocarbons from the fractures. Approximately 40 barrels of oil per day, 350 thousand 

standard cubic feet per day of gas, and 20 barrels of water per day are expected to be produced 

during Phase II. Production is expected to begin soon after the onset of heating and continue for 

6 months of active heating. Additional production is expected for a period of time after heating 

stops. 

Phase III (Years 5–10) will consist of a pilot level installation of the ElectrofracTM 

technology at depth. The pilot will consist of two ElectrofracTM fractures constructed at or near 

the anticipated size and spacing required for commercial development. The goal of this phase is 

to collect the information needed to determine the overall commercial viability of the 

ElectrofracTM process: hydrocarbon recovery, sodium mineral recovery, environmental 

acceptability, and economic viability. The anticipated number of wells and holes is somewhat 

greater than those used in Phase II to serve largerfractures. The site of the Phase III tests would 

be near the site used in Phases I and II. 

Approximately 4 MW of electrical power from the nearby power grid will be delivered to 

each of the two ElectrofracTM fractures to resistively heat the formation. Phase III operation is 

expected to produce peak rates of approximately 400 to 700 barrels of oil per day, 1 to 6 million 

standard cubic feet per day of gas, and 200 to 300 barrels of water per day. The pilot will be 

operated for approximately 5 years.

During construction of wells and facilities, peak employment may be 120 workers. 

Construction will involve a maximum of 30 vehicles per day going to and from the site 

(10 commercial trucks and 20 passenger vehicles). During ongoing operations, total staff may 

be as large as 20 workers, estimated to make a total of five to ten vehicle round-trips per day. 

Operations workers will likely be housed in hotels (if nonresidents) or in typical residential 

housing in Rifle, Meeker, Rangely, Silt, Parachute, or Grand Junction, Colorado. 

Water will be needed for construction and drilling activities, shale oil processing, dust 

control, testing the recovery of sodium minerals, and if necessary, used to mitigate groundwater 

contamination, if any. Water required for drilling, fracturing, and dust control is estimated to 

be 0.1–0.2 barrel of water per barrel of oil. Phase III efforts will better define water needs for 
Final OSTS PEIS A-88 

commercial in situ oil shale development and may identify opportunities to reduce water use. 

ExxonMobil’s mitigation strategy to protect proximate groundwater (and by extension, the 

surface water streams in communication with groundwater) will be to design the operations to 

contain the ElectrofracTM zone in a low-permeability envelope of unheated oil shale. 

The effectiveness of this mitigation strategy will be evaluated throughout research 

operations with a comprehensive Groundwater Monitoring Program. Up to 48 groundwater 

monitoring wells will be completed in overlying and possibly underlying hydrologic units, both 

upstream and downstream of the ElectrofracTM site. The Groundwater Monitoring Program will 

begin 15 months prior to the start of pyrolysis operations to obtain baseline data on groundwater 

quality. 

Similarly, a comprehensive Surface Water Monitoring Plan will be developed prior to the 

start of operations (and in parallel to the development of the Groundwater Monitoring Program) 

to detect potential contaminants migrating from the pyrolysis zone. The Surface Water 

Monitoring Plan will be implemented approximately 15 months prior to beginning the pyrolysis 

operations and will include, at a minimum, four sampling locations: two in Ryan Gulch and two 

in Yellow Creek, one upstream and one downstream of operations in each creek. 

A.5.3.6 Natural Soda 

Natural Soda Holdings, Inc. (NSHI) also submitted a proposal for an RD&D project in 

2010 in response to BLM’s second round solicitation. The project would employ in situ 

technologies to extract kerogen from below ground and would be located on 160 acres 

immediately east of ExxonMobil’s proposed RD&D projects in the Piceance Basin in Colorado, 

as shown in Figure A-9. The proposed RD&D lease abuts the southern boundary of Natural 

Soda’s existing federal sodium lease area. The following discussion is based on information in 

the Plan of Operation for of the proposed project (Natural Soda 2011). 

NSHI’s proposed process of extracting kerogen uses high-temperature supercritical or 

near supercritical water in conjunction with carbon monoxide, sodium bicarbonate, and sodium 

aluminate to break down and liquefy kerogen. NSHI has operated a sodium bicarbonate 

(nahcolite) solution mining operation in the Piceance Basin for over 18 years. The company will 

apply its expertise in solution mining in the proposed in situ oil shale recovery project. 

Experience has shown that sodium bicarbonate and sodium aluminate catalyze the liquid 

forming reactions of Victorian brown coal in the presence of carbon monoxide and water. The 

proposed project will test whether these same reactions work in oil shale. Naturally occurring 

Dawsonite (NaAlCO3(OH2)) in the saline zone of the Piceance Creek Basin is chemically 

similar to sodium aluminate (NaAlO2) and breaks down at temperatures in the range of kerogen 

decomposition, providing the opportunity to develop an in situ kerogen liquefaction process. 

The ultimate scale of the project will depend on the initial results of a small-scale effort 

involving a single Oil Shale Reactor (OSR) production well. The OSR will be drilled in 40-ft 

intervals at the base of a saline zone that has the potential to produce 100 bbl of oil shale. 
Final OSTS PEIS A-89 

Additional intervals will be installed at higher levels in the saline zone. Based on the results of 

this initial production well, additional production and monitoring wells will be placed within the 

160-acre lease area. 

The NSHI process would utilize the natural presence and distribution of sodium minerals 

for both the generation of porosity and permeability and potentially, to catalyze the conversion of 

kerogen to a liquid product. No fracturing methods will be employed, but minor fracturing might 

occur as a result of thermal expansion of the oil shale. Nahcolite produced in the pilot well will 

be tested at NSHI’s existing sodium bicarbonate processing facility. If the solution product is not 

rich enough for recovery, it will be added to the barren liquor stream of that process, thus 

preventing the production of a new waste stream from the proposed project. 

Groundwater impacts will be controlled by working in the lower part of the saline zone in 

the upper Green River Formation, which is devoid of groundwater. Nahcolite would be solutionmined prior to the conversion of kerogen, thus utilizing this resource fully. NSHI’s existing 

solution mining facilities, as well as supporting roads, electricity, water, and natural gas facilities 

would be used, thus reducing soil and other disturbance from construction of the project. 

An estimated 10–20 workers would be employed during the drilling and construction 

phase of the project, and 5–10 workers during operations. Drilling would start no later than 2014. 

Production would start about three months after completion of the production well and would 

continue until the success of the conversion technology and commercial viability of the process 

can be established. 

A.5.3.7 Red Leaf Resources 

Red Leaf Resources, incorporated in 2006, has developed the EcoShaleTM In-Capsule 

Technology to produce liquid transportation fuels from oil shale, oil sands, coal, lignite and 

bio-mass. The resultant product is a high-quality feedstock with no fines. The process also 

produces synthetic natural gas, which can be used as an energy source for the process. The 

following summary is based on information on Red Leaf’s Web site (Red Leaf Resources, Inc. 

undated). 

Red Leaf Resources holds 18 mineral leases for approximately 17,000 acres of stateowned and -managed school trust lands in the Uintah Basin, including some of the best 

surface-mineable and richest oil shale in the United States. Average overburden thickness is 

approximately 60 ft, with a resource seam at least equivalent. Estimates indicate approximately 

1.5 billion barrels of oil equivalent in-place on the Red Leaf leaseholds.  

The EcoShaleTM In-Capsule Technology involves heating surface-mined shale in a 

closed, clay-lined, surface impoundment, or capsule. The process relies on conventional mining 

and construction methods and produces a bottomless oil product that requires no coking. The 

process produces a shale oil with a much higher concentration of middle distillate than West 

Texas intermediate crude. Two synthetic shale oil products are produced: (1) prompt oil of 

approximately 29 API gravity and (2) condensate oil of approximately 39 API gravity. The oil 
Final OSTS PEIS A-90 

and condensate produced with this process have no fines and have very low acid numbers. The 

technology requires no process water. 

Pilot Test. A test of the EcoShaleTM In-Capsule technology was carried out in the Uintah 

Basin in Utah in 2009. The field test pilot validated the technology modeling and engineering 

design aspects. The process produced a high quality product with a prompt oil that was 

approximately 29 API gravity, about 65% paraffin + naptha, and about 12.6% hydrogen. A 

condensate liquid was also produced with an approximate 39 API gravity, about 55% paraffin + 

naptha, and about 12.9% hydrogen. Sulfur content was approximately 2,200 ppm and nitrogen 

content was about 1 to 1.2 wt%. The oil produced contained almost no entrained solid fines from 

the shale ore. Capsules (or, impoundments), which contain the hydrocarbon treatment zone, 

would be scalable from smaller impoundments that produce a few hundred barrels per day, to 

very large impoundments that produce thousands of barrels per day. 

Economics. According to the company, the EcoShaleTM In-Capsule Technology has an 

estimated Energy Return on Investment (EROI) of 10. This is, for every unit of energy that is 

used to heat the process, an estimated 10 units of energy are produced, thus making the EROI 

comparable to that of conventional oil. This EROI has been validated by bench-scale and field 

test performance. A process production cost of $25/bbl is estimated, depending on the project 

scale implemented and the specific resource geology. 

The EcoShaleTM In-Capsule Technology is largely energy self-sufficient, as it produces 

enough synthetic natural gas to meet all of its power, heat, and hydrogen requirements. Red Leaf 

Resources envisions using produced synthetic natural gas for all of its power requirements. 

Red Leaf has indicated that the company is ready to begin building a mine and a 

processing facility in the Unita Basin in 2012, with plans to produce 9,500 barrels of oil per day 

by 2014 (Hanson 2011). 

TomCo Energy holds approximately 3,000 acres of oil shale leases on private land in 

Uintah County, Utah, in four separate tracks and entered into a licensing agreement with Red 

Leaf Resources in March 2010 to use Red Leaf’s technology to produce oil shale products on 

TomCo’s leases. The company estimates production of 80 million barrels over 20 years (TomCo 

Energy 2011). 

A.6 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

AMSO (American Shale Oil), 2009, Plan of Development for Oil Shale Research, Development 

and Demonstration (RD&D) Tract, Oil Shale Lease COC 69169, May 15. 
Final OSTS PEIS A-91 

Argonne (Argonne National Laboratory), 1990, Environmental Consequences of, and Control 

Processes for, Energy Technologies, Noyes Publications, Park Ridge, N.J., Jan. 1. 

Beard, T.N., et al., 1974, “Nahcolite and Dawsonite Resources in the Piceance Creek Basin, 

Colorado,” pp. 101−109, in Guidebook to the Energy Resources of the Piceance Creek Basin, 

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Final OSTS PEIS A-99 

ATTACHMENT A1: 

ANTICIPATED REFINERY MARKET RESPONSE 

TO FUTURE OIL SHALE PRODUCTION 
Final OSTS PEIS A-100 

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Final OSTS PEIS A-101 

ATTACHMENT A1: 

ANTICIPATED REFINERY MARKET RESPONSE 

TO FUTURE OIL SHALE PRODUCTION 

1 INTRODUCTION 

Ultimately, crude shale oil’s acceptance into the U.S. refinery market will be based on a 

number of factors. While some of these factors are well understood and can be used to make 

reliable forecasts, others are difficult to precisely define at this time. This brief overview of the 

manner in which the U.S. petroleum refining market may react to new crude oil sources from 

shale oil identifies some of the major factors that will influence decisions regarding construction 

or expansion of refineries. Among the factors that predominate in supporting refinery market 

adjustments are the following: 

• The investment into and expansion of refining capacity are solely determined 

by the investor’s long-term expectation of refining margins. Only those crude 

oil sources that can demonstrate long-term availability and consistent quality 

factors are likely to be considered as expansion or displacement candidates. 

• New crude oil sources displace sources in existing markets on the basis of 

how well their quality parameters align with existing or expanding refining 

capability; the market will take proportionally longer to accept new sources 

with quality factors substantially different from those of existing or 

alternatively available sources. 

• Indicators of potential new incremental markets include forecasted refining 

capacity expansion in existing facilities or in proposed new refineries. 

Currently, only a few small facilities are in the planning or permitting stages, 

and no large-scale integrated distillate fuel refineries have been publicly 

proposed. 

• Incremental expansion at existing facilities is the expected way in which 

crude oil shale will be introduced into the refinery market in the short term, 

especially considering the time it has historically taken to plan, permit, design, 

and build new refineries (> 10 years). 

• Identification of the most probable markets for the shale oil crude is 

dependent upon the phase of its growth. Early adopters could displace existing 

sources in geographically local markets with shale oil of comparable quality. 

Subsequent phases of oil shale industry development will require the 

development of logistical capacity and transport to larger markets to 

accommodate the higher production levels, with the Midwest and Gulf Coast 
Final OSTS PEIS A-102 

markets becoming available first, followed by the West and East Coast 

markets. 

• Intuitively, domestic sources of crude shale oil are more desirable than foreign 

sources of crude oil simply because of their inherently more secure status. 

However, to retain their advantage, such domestic sources must also compare 

favorably with imported feedstocks with respect to overall product yield and 

other quality parameters (e.g., high-sulfur, high-acid content). Crude shale oil 

has great potential for replacing equivalent amounts of imported crude oil 

with comparable quality factors. 

• Of the imported crude sources likely to be displaced by crude shale oil, the 

most likely are those currently being delivered to refiners in the Midwest and 

Gulf Coast, the two geographic areas composing the largest and most flexible 

markets for crude. Imported crude oil supplies most similar in quality to crude 

shale oil would be the first to be replaced since that replacement would 

require little to no change in refining capability. 

• Pipelines do not drive refinery market investments; pipeline operators react to 

committed emerging markets and provide transportation linkage between the 

source and the refiner.31

The U.S. refining market is not geographically equally distributed, and it has evolved into 

concentrations of refining capacity. The volume and types of crude that each of these refining 

concentrations consume have also evolved given their economic and logistical access to various 

sources of crude. In addition, the economics of processing crude oil that has particular 

characteristics (e.g., heavy crude oil) has driven the type of processing capability and 

subsequently investments. For example, the Gulf Coast, with easy waterborne access to 

traditionally cheaper foreign crude imports, has emerged with a large share of the U.S. refining 

capacity. The increased availability of heavy foreign crude at a price discount has spurred 

increased heavy crude processing capacity in this region. Subsequently, extensive logistical 

capacity to transport refined products to larger consumer markets, such as the Northeast, has 

evolved. In contrast, inland refining centers, such as the Rocky Mountains, have expanded only 

to serve their regional markets. The inland centers originally were configured to process 

primarily lighter domestic crude. Only relatively recently, with the growth of heavy Canadian 

crude oil imports, have they invested in increased refining capacity to process heavy crude. 

The growth of total refining capacity has tended to result from the expansion of existing 

facilities rather than from the construction of totally new facilities. The lower risk to capital 

investment afforded by incremental expansion and economies of scale has supported this 

approach. While incremental expansion is the norm, it does occur in significant overall quantities 

and does have associated incremental environmental impacts. 

 

31 However, operators of existing pipelines may be reluctant to accept crude shale oil with high nitrogen content for 

fear of contamination of subsequent batches of conventional crude oils. Consequently, either crude shale oil 

upgrading must occur at the mine site, or a dedicated crude shale oil pipeline infrastructure must be created. 
Final OSTS PEIS A-103 

Refinery capacity growth and the location of this growth is determined by a complex mix 

of economics, acceptance of all environmental impacts, and in some situations, availability of 

basic resources, such as water and electricity, and logistical access. The same synergies of local 

markets for workers and equipment, logistical access, and markets for feedstock and product 

trading that created the existing concentrations of refining capacities have directed continued 

growth to these same areas. 

This paper reviews some of these issues to identify the inherent drivers in the 

marketplace that could show the likely market placement of increased production of U.S. crude 

shale oil. The relatively recent entry of Canadian syncrude and bitumen into the U.S. refinery 

market provides a good example of how U.S. oil shale production might enter the refining 

market.32 Volumetrically, the amount of Canadian syncrude and bitumen currently entering the 

U.S. market is of the same general order of magnitude as an estimate of anticipated commercial 

production levels for U.S. oil shale facilities (i.e., about 2 million bbl/day).33 The Canadian 

crude experience can help define logistical infrastructure changes, the economic factors that 

control inflow into existing refining centers, the probability of refinery expansions, and the 

possible crude sources that may be displaced. It is important to note, however, that recent trends 

in refining demand for Canadian crude are economically favoring the nonupgraded raw bitumen, 

which is sold at a substantial discount, thus providing the refiners with more margin potential. 

This ultraheavy bitumen is analogous to other foreign heavy crudes, which are in abundant 

supply in the marketplace and are also sold at a steep discount. The increased utilization of these 

ultraheavy crudes has required extensive investments in the “bottom-of-the-barrel processing” 

coker capacities. The shale oil and upgraded synthetic portions of Canadian crude have very little 

“bottoms” or residual; therefore, not only can they be processed in refineries without significant 

capital investment, they can serve as a complementary blending component with the ultraheavy 

crudes to balance the overall feedstock pool to the refinery. They must be produced, however, at 

an economically attractive price to compete with these steeply discounted heavy crudes 

2 OVERVIEW OF THE CRITICAL PARAMETERS 

IN THE CRUDE OIL REFINERY PROCESS 

Crude oil is a mixture of hydrocarbons formed from organic matter. It varies in chemical 

and physical composition, including differences in sulfur content, typically small amounts of 

nitrogen, acidity, density, etc. At the most fundamental level, the refining process involves 

actions in any of the following categories: 

• SeparationDistillation, 

 

32 The organic fraction of Canadian tar sands is what is referred to here as bitumen. Syncrude is that which results 

from the mine site upgrading of bitumen. Both raw bitumen and syncrude are currently being delivered to 

U.S. markets. 

33 To facilitate discussion of the potential effects of oil shale development, the BLM assumed a commercial 

production level of approximately 2 million bbl/day. 
Final OSTS PEIS A-104 

• ConversionChanging the size and/or shape of molecules, and 

• Treatment/blendingMaking products to desired specifications. 

The first step in the refining process is crude distillation. Crude distillation breaks a full 

barrel of crude into intermediate feedstocks through the application of heat and pressure. A small 

portion of the yield of a distillation tower can be recovered and marketed as a finished product. 

Most distillate fractions, however, must be further processed in downstream conversion units 

into blend components, petrochemical feedstocks, and finished petroleum products. The 

distillation process is merely a separation process, while other downstream conversion processes 

actually involve chemical reactions that modify the molecular structures of the hydrocarbon 

distillate fractions to produce products with desirable physical and chemical qualities. Figure 1 

shows a generic refinery flow. The initial crude oil composition dictates the relative proportions 

of initial distillate fractions. 

FIGURE 1 Generic Refinery Configuration (Source: EIA 2006a) 

(LPG stands for liquefied petroleum gas.)a

a Not all conventional crude oils are appropriate starting material for production of asphalt; however, 

they can instead efficiently produce heavy-weight fuel oils, such as bunker fuels used in ocean-going 

vessels or #6 fuel oil used in industrial boilers. 
Final OSTS PEIS A-105 

Crude oil sources are typically classified by density. 

By industry convention, density is expressed as American 

Petroleum Institute (API) gravity: light (API >34), medium 

(API 26–24), or heavy (API < 24).34 Density, in turn, is 

reflective of fundamental differences in underlying chemical 

compositions. The lighter the crude source, the greater the 

relative percentage of small- to moderate-sized organic 

molecules with high degrees of saturation, making it more 

amenable to conversion into high-value products such as 

gasoline and other low-boiling fuels and products. Heavier crude 

will have greater relative concentrations of heavier components 

with higher degrees of unsaturation. Such compositions lend 

themselves more readily to conversion into heavier distillate 

products such as various grades of fuel oils, lubricating oils, 

asphalts, and similar products, as shown in Figure 2. 

While it is chemically possible to convert any quality 

crude to a wide range of final products, to convert heavier crude 

feedstock into high-value products requires substantial amounts 

of energy and results in reduced yields. Consequently, crude oil 

density (and, more specifically, chemical composition) dictates the refining pathway and the 

relative proportion of distillate products in most instances. This is the case for any crude source, 

including crude shale oil. The maximization of a refinery’s total production value is derived by 

optimizing each component of the refinery, such as impurity removal, and each type of 

processing capacity. Consequently, for existing refineries considering replacement of an existing 

feedstock, the desirability of a crude shale oil source as a replacement will be as dependent on 

the shale oil’s quality and how well it aligns with the preferred refining pathway and intended 

final products for that refinery as it is on outright market price. On the other hand, when the 

pending decision is to create a new refinery or to expand an existing refinery to produce different 

products, long-term availability, supply logistics, and cost become more influential but still do 

not displace the long-term refining margin returns as the primary basis for the decision. 

As the above discussion suggests, many factors ultimately determine the extent of crude 

shale oil’s penetration into the existing petroleum refinery market; however, the crude shale oil’s 

overall quality (chemical composition as well as critical physical properties) would be the 

primary factor on which refineries base their decisions to pursue shale oil feedstocks. 

Unfortunately, the quality of crude shale oil produced at commercial scale is currently one of the 

areas of greatest uncertainty. Empirical evidence suggests that, together with the intrinsic 

variability in the composition of the parent oil shale, the quality of recovered shale oil ultimately 

offered to the refinery market will be highly dependent on the extraction and retorting 

technologies selected and the nature and extent of mine site upgrading. That being said, there is 

 

34 API gravity is an arbitrary scale for expressing the specific gravity or density of liquid petroleum products. 

Devised by the API and the National Bureau of Standards, API gravity is expressed as degrees API. API 

gravities are the inverse of specific gravity. Thus, heavier viscous petroleum liquids have the lower API values. 

FIGURE 2 Comparison of 

Conversion Products Based 

on Crude Composition 

(Adapted from Day 2005) 
Final OSTS PEIS A-106 

very little experience related to commercial-scale shale oil development.35 The newest in situ 

retorting technologies undergoing R&D hold the promise of recovered shale oil of exceptional 

quality. (For example, Shell Oil anticipates that its in situ heating/retorting technology may yield 

crude shale oil of roughly 30% fractions each of raw naphtha, jet fuel, and diesel fuel and 10% 

residual. Shell further believes that relatively minor adjustments to field conditions could allow a 

change in composition of recovered product in response to extant refinery market conditions.) At 

this point in time, however, neither legacy technologies nor cutting edge technologies have 

amassed sufficient evidence on which to safely predict the quality factors that would result from 

their implementation at commercial scales. Long-term reliability of quality factors is absolutely 

critical to refinery acceptance, more so than the absolute values of those quality factors. 

3 MARKET RESPONSES TO FEEDSTOCK VALUE PARAMETERS 

Because heavier crude sources produce fewer high-value products, or produce highervalue products only with additional processing costs, markets compensate by trading heavier 

crude at a price discount relative to lighter crude. Heavier crude stocks are further discounted to 

offset the higher processing costs of using cokers to convert this low-value residual into highervalue gasoline and distillate components rather than less valuable heating fuels and asphalts, 

lubricating oils, and road oils. Transportation fuels (e.g., gasoline and distillates) are the highest 

demanded products. Without upgrading capacity, there would be an excess of fuel oils and 

asphalts, and refiners would process lighter crudes rather than the economically desirable heavier 

crude. Figure 3 shows the refining margins associated with processing light and heavy crudes. 

The green line highlighted at the top represents the difference between processing the benchmark 

light (e.g., West Texas Intermediate) and heavy (Mexican Maya) crudes. As can be seen on the 

left axis, this reached a peak of an approximately $40 per barrel advantage of heavy crude over 

light crude this year. The Canadian crudes referenced in this paper are in the heavy category. 

While the expected composition of U.S. crude shale oil is not known precisely, it will probably 

be more comparable to the light crude in value than to the heavier crude stocks now available on 

the market. Mine site upgrading could further improve this equivalency. 

The second element critical to the desirability of crude oil supplies is sulfur content. New 

specifications on gasoline and diesel are increasingly requiring lower and lower sulfur content. 

Sellers of high-sulfur crudes have to discount them enough to account for the required sulfur 

extraction process in the refinery. From a sulfur content perspective, some U.S. shale oil 

products could be more attractive than conventional domestic crudes and Canadian imports. 

Green River oil shale sulfur content ranges from 0.46 to 1.1% (by weight), approximately 30% 

organic sulfur compounds, with sulfur content increasing as the richness of oil shale deposits 

increase. 

 

35 However, crude shale oil upgrading efforts associated with the Unocal operation at Parachute, Colorado, 

successfully demonstrated that crude shale oil could be converted to a syncrude whose properties, including 

substantially reduced concentrations of nitrogen and sulfur-bearing contaminants, made it acceptable for receipt 

at refineries. 
Final OSTS PEIS A-107 

FIGURE 3 Heavy vs. Light Crude Refining Margins (Source: Arnold 2006) 

Because of the high investment capital required to modify a refinery to process heavy 

crudes, refiners electing to do this have typically signed 7- to 10-year crude supply agreements. 

These long-term crude supply agreements shrink the near-term market available for heavy crude 

displacement by new crude shale oil supplies. 

Given the uncertainty of quality factors that can be expected for commercially developed 

shale oil, it is difficult for refinery operators to determine the relative attractiveness of future 

crude shale oil sources against currently available sources. Frequently, operational adjustments 

and sometimes equipment investments have to be made to adapt to a significant change in a 

crude oil source. This could be related to process upgrading, impurity removal, or 

accommodation of other metallurgy, heating, cooling, or pumping capacities. Even without 

major structural changes, the normal unit variations created with introductions of new sources 

typically result in a refinery repeatedly testing small volumes of a new feedstock over a period of 

time to better understand the impacts on operations. Until long-term quality factors are 

established for crude shale oil, it is reasonable to expect a lag between initial commercialization 

of oil shale facilities and the development of refineries to accept it. Such an initial lag may be 

shortened to some extent by interim decisions on the part of refineries to accept crude shale oils 

of lesser quality with the intent of blending them with existing stocks to produce averaged 

quality factors in the blend that can still be managed economically in existing refining units with 

little to no modifications. 

Shale oil facility operators also have opportunities to influence their potential place in 

the refinery market and to reduce the hesitancy of refineries to accept their product by the degree 

of upgrading they perform on their products. Since demand for low-sulfur distillate fuels is 
Final OSTS PEIS A-108 

currently high and expected to increase (especially given the additional influence of recent 

lowering of sulfur limits in diesel fuel by the U.S. Environmental Protection Agency [EPA]), 

upgrading to align shale oil more directly with the high-quality conventional crude sources 

that now support that refinery market segment is the most likely objective. Thus, if shale oil 

developers pursue this option, upgrading actions at the mine site would be designed to remove 

sulfur and nitrogen and increase hydrogen-to-carbon ratios with reactions such as hydrocracking 

to improve the quality of initially recovered crude shale oil and make it more competitive with 

higher-quality conventional crude oil feedstocks. 

However, given that shale oil production sites will be located in generally arid or 

semiarid regions with limited sources of power, fuel, and water for processing, extensive 

treatment and upgrading of crude shale oil could be limited in the early years of industry 

development by the availability and costs of required resources and may, therefore, occur only to 

the extent necessary for safe and economical pipeline transport to an off-site refinery. Should this 

be the case, early market penetration of shale oil would more likely be the result of the pursuit of 

blending options rather than displacement of high-value conventional crude feedstocks. 

4 REFINERY UTILIZATION FACTORS 

The refining process is a continuous liquid process. During normal operation, a refinery 

operates 24 hours per day, 7 days per week; however, maintenance on various units is 

periodically required. Individual (or groups of) units are typically shut down every 1 to 5 years, 

depending upon the unit type, and for 1 to 3 weeks for a unit “turnaround.” A turnaround 

involves a major maintenance overhaul of the unit, including replacing catalysts, performing 

upgrades, and replacing worn-out components. In addition, feedstock variation or unit upsets can 

cause feed preheating, pumping, overhead cooling capacity, sulfur recovery, etc., to become 

constraints, further lowering the overall utilization of the plant. Therefore, the overall utilization 

of the refinery is reduced by the amount of time the units are down. Thus, most data sources 

account for the realities of refinery operation by representing refinery capacity in two ways: 

barrels per stream day (BSD) and barrels per calendar day (BCD): 

BSD represents the absolute maximum rate at which a unit can operate during any single 

day. This rate is a function of unit design and the capacity of supporting systems but cannot be 

sustained for extended periods of time. 

BCD represents the maximum rate of production a unit can sustain over the course of a 

year given maintenance downtime and operating limits due to varying feed qualities. As such, 

the BCD value is the only reliable representation of a refinery’s long-term production capacity. 

The differences between BSD and BCD are unique for each refinery and reflect the types 

and ages of individual refining units and their respective repair and maintenance demands. The 

quality of the incoming feedstock also affects the difference between BSD and BCD capacities, 

since the amounts and types of impurities that must be removed during processing can greatly 

affect maintenance and overhaul schedules of individual units. Such factors explain the reported 
Final OSTS PEIS A-109 

utilization rates for refineries being typically less than 100%. U.S. refineries run as much as is 

operationally feasible over the long term. However, because of these maintenance turnarounds, 

operational upsets, and unforeseen breakdowns, their overall utilization average nationwide is 

about 90 to 93%. Utilization rates for refineries in the closest vicinity to Green River oil shale 

deposits currently range from 91 to 95%. This, however, is still the maximum operating rate that 

can be reliably anticipated. 

The difference between BCD and BSD, or between either rate and 100%, does not reflect 

spare capacity that can be utilized when desired to accommodate a new feedstock source, 

however. Unless otherwise specified, refinery capacities referenced in the remainder of this 

analysis mean BCD. 

5 CURRENT STATE OF PETROLEUM REFINING IN THE UNITED STATES 

The 149 operable refineries in the United States range in size from very small and 

specialized individual processing units with a capacity of 1,500 BCD, to large integrated 

refineries with capacities exceeding 550,000 BCD. 

For the purpose of data collection, refineries are arranged in geographic regions known as 

Petroleum Administration for Defense Districts (PADDs). This system of categorization dates 

back to World War II and was devised to administer the distribution of petroleum products. 

PADDs also reflect the natural boundaries and flows of petroleum feedstocks and refined 

products. Figure 4 shows the geographic boundaries of the PADDs.36

Figure 5 shows the histograms of refinery sizes by PADD. PADD 4—Rockies has a 

disproportionate number of small refineries in comparison with the other PADDs, and these 

small refineries only serve regionally local markets and are configured to produce a limited 

array of products. The PADD 4 refineries originally were almost exclusively supplied with 

domestically produced crude from fields within the PADD. Now, additional pipeline investments 

have been made, bringing Canadian crude into the region. In most cases, additional upgrading 

capacity was added at the refineries to process the heavier Canadian crude. A relatively high 

sulfur concentration characterizes the remaining domestic crude production in the region. Key 

producing states in PADD 4, such as Wyoming and Montana, currently have an excess capacity 

of domestic crude production. In addition to pipeline logistical constraints, the consistent 

expanding price differential between light crude over heavy crude has kept this domestic 

production of light crude noncompetitive outside of this region. This was the first market with 

logistical connections with Canada and was the first market penetrated by Canada, although in 

relatively small volumes compared with Canada’s current production. 

 

36 The U.S. Department of Energy (DOE) Energy Administration Agency (EIA) collects and provides reporting on 

energy data. Considerable information can easily be obtained at the EIA Web site: http://www.eia.doe.gov/. 

Much of this data reporting is aggregated on a regional basis, and the data are organized by PADDs. 
Final OSTS PEIS A-110 

FIGURE 4 Petroleum Administration for Defense Districts Map (Source: EIA 2006b) 

 Figure 5 shows the refinery production capacity and its variation arranged by PADD or 

regional basis. This is an important view for broader and longer range analysis. Figure 6 shows 

individual refining capacities by state for the production region of interest. This view defines the 

current maximum potential volume penetration for crude shale oil in PADD 4. Such market 

penetration could occur without the significant transportation infrastructure expansion that would 

be required before shale oil market penetration into any other PADD could take place. Thus, 

penetration into these “local” refinery markets is the most likely scenario in the early years of 

commercial oil shale production. 

 As shown in Figure 7, U.S. refining capacity increased a total of 3.6 million bbl/day 

between 1985 and 2004, and refinery utilization rates have been stable at near maximum 

achievable levels. The last refinery built in the United States was in Garyville, Louisiana, in 

1976. Current conservative estimates for construction of a new refinery are about $2.4 billion for 

a 150,000-bbl/day capacity ($16,000/bbl/day of processing capacity). The most expensive sale of 

an existing refinery asset was Valero’s recent purchase of Premcor, which sold for approximately 

$10,000/bbl/day of processing capacity. With existing assets selling for well under construction 

costs, there is little incentive to develop a new grass roots facility. Nevertheless, between 1985 

and 2004, U.S. refineries increased their total capacity to refine crude oil by 7.8%, from 

15.7 million BSD in 1986 to 16.9 million BSD day in 2004, but only maintained a consumption 

rate of 15.7 million BCD, reflecting a utilization rate of operating capacity equivalent to 93%. 

This increase in operating capacity is equivalent to adding several mid-size refineries, but it 

occurred, instead, as a result of expansions of production capacities at existing refining facilities 

to take advantage of economies of scale (Slaughter 2005). Much of the current capital investment 

is going to environmentally related processing capability. Over the last 10 years, U.S. refiners 
Final OSTS PEIS A-111 

FIGURE 5 Distribution of Refining Capacities (Source: EIA 2006c) 

have spent approximately $47 billion (Slaughter 2005) to reduce sulfur levels in transportation 

fuels and to comply with 14 new environmental regulations that come into place this decade 

(Wall Street Journal 2004). Of the 60 refinery expansion projects identified by the Oil and Gas 

Journal, 38 are environmentally related, 14 are for conversion units, and only 8 are related to 

expanding or retrofitting crude distillation capacity. Approximately 300,000 bbl of crude 

distillation capacity are committed to refinery expansion through 2010. However, despite the 

overall increase in production capacity that would result, utilization rates for refineries overall 
Final OSTS PEIS A-112 

FIGURE 6 Western States Refining Capacity (Source: EIA 2006c) 

U.S. Refining Capacity History

14.0

15.0

16.0

17.0

18.0

19851987198919911993

1995

1997

1999

2001

2003

Million Barrels Per Day

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

% Utilization

U. S. Operable

Crude Oil

Distillation

Capacity

U.S. Percent

Utilization of

Refinery Operable

Capacity

FIGURE 7 U.S. Refining Capacity (Source: EIA 2006d) 
Final OSTS PEIS A-113 

are not expected to change substantially.37 However, refinery expansion is a continuous process 

of capital project evaluation, so it does not represent a true forecast for refinery capacity. 

Because of the industry’s tendency to expand existing assets, initial new market growth for shale 

crude oil is most likely to be at existing areas of refining concentration. 

U.S. demand for refined products has grown steadily, and growth is expected to continue 

into the foreseeable future. Similarly, increased refining capacity has followed a parallel growth 

path to meet the rising demand. Current margins and announced refinery projects suggest that 

refinery growth will continue into the foreseeable future. The distinction of whether or not such 

growth occurs at a new location or whether it comes through expansion of existing facilities is 

not critical in evaluating the foreseeable potential of crude shale oil. If the market drives the 

crude shale oil to be delivered to the Gulf Coast, expansion of existing large refinery facilities 

to take advantage of associated economies of scale would be the probable response. If a new 

facility was constructed to take specific advantage of crude shale oil economics and logistical 

availability, it would not necessarily be located within the immediate vicinity of the crude shale 

oil sources. Ultimately, increase in refining capacity, whether through expansions or new 

facilities, will occur to the extent necessary to serve the ultimate markets for the end products. 

Whether the crude shale oil is transported to existing refining centers for processing or whether a 

new facility is constructed to refine the crude closer to the point of production is a function of 

economics and market balance and is not an inherent constraint on the viability of crude shale oil 

production. In either scenario, there is a positive realization of the crude shale oil market and an 

associated environmental impact wherever refinery expansion occurs. 

Refinery expansion occurs to profitably meet growing demand. Feedstock selection is a 

secondary process of optimizing refinery economics. Given the complexity of the dynamics of 

meeting increasing refinery demand and/or displacing existing crude supplies, attribution of 

refinery expansion to the introduction of crude shale oil is difficult. A further complication arises 

with the realization that over a period of as long as 20 years, production rates of some current 

feedstock sources may fall dramatically, therefore “freeing up” refining capacity without the 

need for refinery expansions. 

6 CURRENT CRUDE SOURCES 

Any new crude source has to find a market in either expanded refinery production or by 

competitively displacing other crude supplies in the market (including through the adoption of 

feedstock blending strategies by refineries). This section describes the existing sources of crude 

feedstock that are supplying U.S. refineries. 

In 2011, the United States processed 17.1 million bbl of crude per day. Of this, 

5.7 million bbl/day comes from domestic production, 2.7 million bbl/day is imported from 

 

37 Since these expansions would involve new processing units utilizing state-of-the-art technologies, some minor 

improvements of utilization rates may result, but such increases are likely to be insignificant when averaged over 

the entire U.S. refining capacity. 
Final OSTS PEIS A-114 

Canada, and 8.7 million bbl/day comes from other international sources. Crude is produced 

domestically in 28 states and in state and federal offshore waters on the West Coast and the Gulf 

of Mexico (EIA 2012a). Table 1 shows domestic production by state (EIA 2012b). 

TABLE 1 Crude Oil Production in the United States in 

2011 

Location 

2011 Crude Oil Production 

(103 bbl/day) 

 5,676 

 

PADD 1 22 

 Florida 6 

 New York 1 

 Pennsylvania 10 

 West Virginia 5 

 

PADD 2 817 

 Illinois 25 

 Indiana 5 

 Kansas 114 

 Kentucky 6 

 Michigan 18 

 Nebraska 7 

 North Dakota 419 

 Ohio 13 

 Oklahoma 204 

 South Dakota 4 

 Tennessee 1 

 

PADD 3 3,277 

 Alabama 23 

 Arkansas 16 

 Louisiana 189 

 Mississippi 64 

 New Mexico 196 

 Texas 1,474 

Federal Offshore 1,316 

 

PADD 4 395 

 Colorado 107 

 Montana 66 

 Utah 72 

 Wyoming 150 

 

PADD 5 1,165 

 Alaska 572 

 South Alaska 10 

 North Slope 562 

 California 538 

 Nevada 1 

Federal Offshore 54 
Final OSTS PEIS A-115 

The most likely market for new domestic crude sources is the displacement of 

comparable foreign crude. States in the extreme North and some in the Midwest are processing 

Canadian imports, which are less likely to be displaced because of the capital investment in 

upgrading already made or committed to by refineries to process these heavy crude supplies. The 

Canadian producers are developing crude pipelines to the Gulf Coast and are looking to the Gulf 

Coast PADD as their next incremental market. Any substantial shale oil production would likely 

follow this same market pattern. Summary information describing each of the PADDs is 

provided below: 

• PADD 1—East Coast has primarily waterborne crude receipts. It is net short 

of refining capacity and is a large importer of refined products from within the 

United States and internationally. It is the least likely market for crude shale 

oil. It receives refined products through the Colonial and Plantation pipelines 

and refined imports from the Caribbean and Europe. 

• PADD 2—Midwest is geographically constrained from the primarily 

waterborne receipts in the Gulf Coast and offshore domestic Gulf Coast 

production. Its access via crude pipelines from the Gulf adds additional 

expense. Therefore, it was a natural secondary market for Canadian 

penetration. It is a very diverse PADD with a wide range of refinery sizes and 

configurations and serves a wide range of product specifications, including 

heavy integration of ethanol (for use in gasoline blending). PADD 2 has been 

the largest regional recipient of Canadian crudes entering the market. This is 

because of its large total refining capacity and its relatively closer proximity to 

the Canadian sources than other refining center markets. Its proximity to 

Canada and associated crude pipelines and the relatively higher cost to ship 

foreign crudes from the Gulf Coast to Midwest refineries makes PADD 2 a 

naturally attractive and economic recipient of Canadian crudes. Without some 

unexpected extensive logistical expansion of crude shale oil to other markets, 

such as the West Coast, these same factors will make PADD 2 the most likely 

recipient of any substantial volumes of shale oil. 

• PADD 3—Gulf Coast is the heart of the U.S. refining concentration. It not 

only contains the most diverse refinery sizes and configurations, it is also the 

most integrated, with exchanges of secondary feedstocks with refineries and 

petrochemical plants. The first step in refining is distillation, which breaks 

crude into components such as naphtha, distillates, etc. These are considered 

secondary feedstocks in that they feed conversion process units downstream 

of the initial crude distillation. Secondary feedstocks are routinely sold to 

other refineries or to petrochemical plants. If a secondary market for this is 

readily available, such as in the Gulf Coast, then a refiner has to be less 

concerned with balancing the composition of the crude with the individual 

unit capacities. The refiner can sell or purchase additional intermediates to 

make up for crude mismatch. The extensive number of petrochemical plants 

within the immediate vicinity of PADD 3 refineries further expands market 

flexibility for secondary feedstocks. This makes a much more competitive 
Final OSTS PEIS A-116 

crude environment and lowers the premium on crude qualities, since there is 

more freedom to correct poor-quality feeds. The Gulf Coast also was the 

original recipient of foreign heavy crude and, therefore, has extensive 

upgrading and sulfur extraction processing capacity for these supplies. Having 

access to a wide variety of world crude supplies, these refiners present a more 

competitive landscape for producers of crude oil and also establish a lower 

barrier to market entry for any feedstock that has differentiating economics. 

Pipeline reversals and new pipeline construction are underway to transport 

Canadian crudes to PADD 3. The large market is certainly an alternative for 

larger volumes of shale oil but, again, is the most competitive on price. 

• PADD 4—Rockies is the region in which crude shale oil would be produced. 

Its refineries are relatively smaller than those in other PADDs. Its crude 

market is primarily domestic light sour production and imported Canadian 

crude. Canadian crude imports have increased substantially. It was one of the 

first markets to be exploited by Canada until further logistical capacity could 

be built to the Midwest and then later connections could be made with other 

pipelines to the Gulf Coast. The markets for the refined products are also very 

localized, with the exception of the product pipeline from Salt Lake City, 

Utah, to eastern Washington and Oregon. Environmental considerations, such 

as water availability, could be a larger issue to refinery expansion in PADD 4 

than in other PADDs. PADD 4 refiners are implementing improved 

wastewater recovery and water conservation projects in existing refineries in 

this region. PADD 4 would be the most likely early adopter, and refineries 

would be available with little pipeline capacity increase, but, collectively, 

refineries in this PADD are very limited in the total volume of new feedstock 

that they can accept. Full realization of the shale oil potential will require 

significant displacement of current crude sources to PADD 4 refineries or 

crude shale oil sales in other PADDs. 

• PADD 5—West Coast is a complex but isolated market. The product 

requirements of the California Air Resources Board (CARB) are very 

challenging for refiners. Access to European and Gulf Coast products is 

constrained logistically by the transit time and ship availability to transit the 

Panama Canal (including the size limitation imposed on ships by the Canal). 

Even within the PADD, interchanges of supply and distribution are complex. 

Many of the San Francisco area refiners cannot produce CARB-approved 

gasoline and, therefore, export the entirety of their gasoline production to 

Washington and Oregon. Washington refiners can make CARB-approved 

gasolines and, therefore, produce for this higher-profit market segment and 

supply gasoline to southern California, which is net short of all products. 

Washington refiners produce some high-sulfur distillates, which exceed 

U.S. specifications, and these distillates are exported to both Latin America 

and South America. PADD 5 processes approximately two-thirds of domestic 

crude, including Alaska North Slope crude. Both California and Alaskan 

domestic crude sources are expected to decline within the 20-year time frame 
Final OSTS PEIS A-117 

for this shale oil forecast horizon. The Southern California refiners, 

representing more than 1 million bbl/day of processing capacity, are 

particularly short of crude, and any domestic declines will only increase their 

disadvantage. While there are currently no crude pipelines to carry shale oil 

crude from the Rocky Mountain area to the West Coast, PADD 5 represents a 

sufficiently attractive market for consideration in that pipeline infrastructure 

investments are likely over the long term. 

7 CANADIAN CRUDE PRODUCTION 

Canada is one of the largest crude exporters into the United States and is becoming of 

greater strategic importance given the increasing uncertainties associated with other foreign 

crude sources. It is enlightening to review the history of Canadian syncrude oil’s entry into the 

U.S. refining market since this has been a relatively recent injection of a significant volume of 

crude feedstock into the U.S. market and may be representative of the pathway that 

U.S.-produced crude shale oil may follow. The source for the information presented in this 

section is Alberta’s Energy Reserves 2011 and Supply/Demand Outlook 2012–2021, published 

in 2012 by the Energy Resources Conservation Board (ERCB 2012). 

The majority of Canadian syncrude is produced in Alberta Province, which is 

geographically closest to and competes with Western U.S. crude production. Most syncrude is 

now produced either by mining tar sands or by various in situ techniques using wells to extract 

crude bitumen. The product is generally classified as “heavy crude.” Raw bitumen production 

has been increasing in recent years and accounts for more than 78% of Alberta’s 2011 total crude 

feedstock production. A large portion of Alberta’s bitumen production is upgraded to syncrude. 

Upgraders chemically add hydrogen to bitumen, subtract carbon from it, or both. In upgrading 

processes, the sulfur contained in bitumen may be removed. Bitumen crude must be diluted with 

some lighter viscosity product (called a diluent) in order to be transported in pipelines. Use of 

heated and insulated pipelines can decrease the amount of diluent required; however, such 

techniques are not feasible for transport over long distances. 

Canada has accomplished a dramatic increase in overall crude production, and it is 

forecasted to continue increasing at a large rate. Figure 8 shows the historical growth and 

forecast of Canadian crude oil by source. At the rate of anticipated production growth displayed 

in Figure 8, Canadian syncrude could represent a substantial percentage of total crude volume 

consumed by U.S. refineries within the near future. For example, by 2015, a forecasted 

Canadian syncrude production volume of approximately 3.8 million bbl/day could represent as 

much as 23% of the U.S. refinery industry’s crude consumption.38

 

38 The EIA forecasts that, by 2015, the total volume of crude actually consumed by all U.S. refineries will be 

16.3 million bbl/day. For clarification against refinery capacities discussed earlier, assuming continuing refinery 

utilization rates of 93%, this volume infers 17.5 million BSD refinery distillation capacity, which can be 

reasonably expected to come from incremental expansions of existing facilities. For EIA crude volume 

consumption forecasts, see EIA (2006e). 
Final OSTS PEIS A-118 

FIGURE 8 Canadian Crude Supply Forecast (Source: CAPP 2012) 

Western Canadian exports to the United States were 2.0 million bbl/day in 2011. By 

2020, 3.7 million bbl/day are expected to be exported to the United States, which would be an 

increase of 1.7 million bbl/day over current levels. Figure 9 shows the disposition of the 

Canadian exports to the United States by state. 

In the United States, PADD 4—Rockies, although small in overall refining capacity, and 

PADD 2—Midwest have been the traditional markets for Canadian crude. However, several 

announced pipeline projects constructing new pipelines and reversing the direction of flows in 

existing pipelines are currently planned or under construction. The most significant is the 

planned construction of the Keystone pipeline and the reversals of the Spearhead and 

ExxonMobil line targeting significant new pathways to the PADD 3—Gulf Coast market. 

Significant increases in U.S. crude shale oil production in PADD 4 also would likely target 

similar markets of existing refinery capacity. As noted earlier, there are similar drivers between 

U.S. crude shale oil and Canadian crude because of geographical location and associated 

transportation capacities and costs. However, they do differ in chemical composition. Expected 

higher production costs as well as heavy subsidization of Canadian synthetic crude oil by the 

Alberta government suggest that the U.S. crude shale oil will not be offered at the lower cost that 

enables higher refining margins for the Canadian heavy crude. However, because commercially 

produced crude shale oil can be expected to be lighter than Canadian synthetic crude oil, its 

acceptance into refineries will not require incremental investment in heavy crude processing 

capacity. 
Final OSTS PEIS A-119 

FIGURE 9 Canadian Crude Oil Disposition (Source: EIA 2007) 

Figure 10 shows the refining locations and the associated volumes of gasoline production 

in thousands of metric tons per year. This shows the concentration of refining assets in the Gulf 

Coast and West Coast markets and the lack of them in the Rocky Mountain source region. 

To accomplish logistical movements of existing and planned import volumes, a series of 

pipeline construction projects, reversals of existing pipelines, and pipeline capacity expansions 

are underway. Figure 11 shows the current and projected Canadian and U.S. pipeline projects. 

8 THE EVOLVING MARKET FOR SHALE OIL CRUDE 

 It is useful to consider the development of shale oil markets in phases. On the basis of 

historical precedent, in the early years of initial commercial production (1 to 5 years after the 

start of commercial development), there is likely to be a relatively small volume of shale oil 

available on the local commercial market, and this volume may be of varying quality as various 

methods of shale oil recovery and processing are introduced, fine-tuned, and combined. In 

addition, over this period, the shale oil producers may shift the degree to which they upgrade the 

raw recovered crude shale oil to match evolving market conditions and to improve their market 
Final OSTS PEIS A-120 

FIGURE 10 Refinery Locations and Gasoline Production 

(Source: EIA 2006c) 

FIGURE 11 Canadian and U.S. Crude Oil Pipelines (Source: CAPP 2012) 
Final OSTS PEIS A-121 

penetration potential. If these initial volumes of commercial shale oil are differentiated 

economically, they are most likely to find a market within PADD 4 to the extent allowed by 

existing transportation infrastructure. As was noted earlier, there will likely be some hesitancy 

on the part of refiners to use these crudes until their qualities are consistent and predictable. 

 In a second phase (probably in years 5 to 10), the volume of shale oil available will 

have exhausted refiner’s opportunities to displace existing feedstocks, saturate local refining 

capacities, and exceed existing pipeline transport capacity within the immediate region. This 

is likely to focus additional growth to either PADD 2—Midwest or PADD 3—Gulf Coast, 

depending upon which region has the greatest new (and unclaimed) pipeline transport capacity. 

In this time frame, it is possible that PADD 2 already could be saturated with existing Canadian 

capacity, and PADD 3 would be the more likely incremental market for greater volumes of crude 

shale oil. By this point in time, the quality of commercially available shale oil should have 

stabilized so that the true determining factor would be a market-driven valuation of the crude 

composition and qualities versus its transportation and processing economics. Either PADD 2 

or PADD 3 could absorb up to 2 million bbl/day additional shale oil with little refinery 

configuration restructuring required if the market determines it is economically advantageous 

to do so. 

 In the long term (probably 10+ years), other markets such as PADD 5—West Coast could 

also become viable. The potential decreases in California and Alaskan North Slope crude 

production and/or increased insecurity in foreign crude availability could provide the motivation 

to construct high-capacity pipelines to supply that market. 

 Uncertainty as to the exact quality of commercially produced shale oil prevents a precise 

determination of the feedstock market segment in which it would be most competitive. Current 

in situ technologies under evaluation show the promise of partial upgrading of crude oil prior to 

recovery from the oil shale formation as well as the conversion of sulfur and nitrogen-bearing 

compounds to hydrogen sulfide and ammonia compounds, respectively, either of which can be 

easily removed from the product stream. Although this hypothesis remains unproven at 

commercial scales, if it is realized, the resulting crude shale oil could be both lightweight and 

low in sulfur content (relative to many current conventional feedstocks), which could give it a 

distinct advantage over both the high-sulfur conventional domestic crude production and the 

Canadian synthetic crude oil. This may influence both the rate and extent of market penetration 

for shale oil. 

Refinery expansion and operations will also be influenced by environmental factors, 

which contribute to the overall market picture. Issues such as air quality (attainment status for 

each of the primary ambient air quality criteria pollutants as well as source-specific emission 

limitations) and water availability could constrain or preempt significant expansions of existing 

refineries or the construction of new refineries in certain geographic areas. It is intuitive that 

refinery growth occurring in the immediate vicinity of a crude oil source would minimize 

transportation costs; however, other factors, such as ambient air quality and water availability, 

could be key constraining factors in refinery expansion that could overwhelm any concerns for 

transportation costs. In addition to the high water requirement of typical refineries of 1 to 3 bbl 

of water per barrel of processed crude, the degree of impurities present in crude shale oil could 
Final OSTS PEIS A-122 

create increased wastewater and waste disposal issues. In the final economic models that are 

typically employed, transportation costs are nominal and have very little influence over the 

ultimate decision regarding the location of the refinery relative to the crude oil source. Of a more 

critical influence is the existing pipeline capacity that links the market areas under consideration. 

However, as has been suggested in the introduction, pipeline operators will expand their 

capacities and build pipelines linking new locations once markets are reliably established. 

Environmental controls aimed not at refineries but at some distillate fuel products may 

also influence the overall market. New low-sulfur fuel requirements will put high-sulfur 

feedstocks at a disadvantage or will require expensive expanded sulfur control capabilities at 

refineries currently receiving such feedstocks. The intrinsically lower sulfur content of crude 

shale oil compared to some conventional crude feedstocks, as well as the ability of crude 

producers to further reduce sulfur content through in situ retorting techniques and/or mine site 

upgrading, could greatly increase shale oil’s attractiveness to refineries producing such distillate 

fuels. 

9 OTHER POSSIBLE MARKET DRIVERS 

Declines in supply from existing major exporters (e.g., Venezuela and Mexico), domestic 

sources (North Slope of Alaska), and geopolitical events could create an increasing demand for 

domestic crude production in the future. Venezuela and Mexico have been primary sources of 

crude oil, with each providing approximately 1.5 to 1.7 million bbl/day into the United States, 

but concern for these sources is growing. Venezuela has been unable to return to the level of 

production in 2001, and the government has become increasingly antagonistic to U.S. interests. 

Also, there is growing industry concern over the decline of Mexican production because of the 

lack of investment, which could dramatically impact production levels in the next few years. 

With two major Western Hemisphere producers facing uncertain futures and continuing concerns 

over the Middle East and Africa, the medium-term potential for increased demand for domestic 

crude production could improve the market viability for production and processing of crude 

shale oil. 

Alaska North Slope production has been in decline and is currently supplying 

approximately half of its historic peak. Although there are considerable logistical challenges to 

moving crude to the West Coast, future declines in supply from Alaska could create increased 

demands on the West Coast that could improve what is currently considered a nonviable market 

for moving feedstock from the Rocky Mountain region to the West Coast. 

While nearby crude sources are likely declining, world demand for crude oil is expected 

to increase by 47% by 2030. China and India are expected to account for more than 40% of this 

increase (EIA 2006e). These forecasts of increasing demand and diminishing resources are 

creating an international competition, which is being acted on now. China began the process of 

constructing a Strategic Petroleum Reserve in 2004 and is increasing its relations with oil 

producers, such as Angola, Central Asia, Indonesia, the Middle East (including Iran), Russia, 
Final OSTS PEIS A-123 

Sudan, and Venezuela (Office of the Secretary of Defense 2005). Further international energy 

risk could provide additional incentive for utilization of domestic resources. 

Legislation could also play a role in driving the advancement of shale oil. The Energy 

Policy Act of 2005 extends the Title VII, National Oil Heat Research Alliance Act of 2000, 

providing for research for use of distillates as home heating oil. Heating oil equipment is found 

to “operate at efficiencies among the highest of any space heating energy source.” Further 

support of this could drive additional demand for the types of distillates that can be produced 

from upgraded shale oil. The same act also directs the Secretary of Energy to select sites 

necessary to procure the fully authorized Strategic Petroleum Reserve (SPR) storage volumes. 

Although additional segregation would be required from the current SPR storage, shale oil could 

be upgraded to meet additional SPR storage acquisition or even displace existing barrels of 

conventional oil. The need to extend the physical storage capacity affords an opportunity to 

evaluate alternative locations, from the existing Gulf Coast-centric storage to support production 

in the Rocky Mountain region, or storage and consumption in Southern California or the upper 

Midwest. In addition, Section 369 of the Act directs the Secretary of Defense to procure fuel 

derived from coal, shale oil, and tar sands. This could also stimulate a demand, especially in the 

western United States. While the precise nature of future actions implementing these statutory 

directives is unknown at this time, impacts on the oil shale industry are easily anticipated. 

10 CONCLUSIONS 

The unknowns regarding the quality and availability of crude shale oil, the extent to 

which it may be upgraded at the site of production, and the time frames for expansions of 

pipeline capacity for movements outside the immediate production area introduce considerable 

uncertainty with respect to the timing and specifics of refinery market development. As a result, 

it is difficult to predict with certainty how the refinery market will respond to oil shale 

development on public lands over the next 20 years (2007 to 2027). It is likely that during the 

first 10 years of the study period (2007 to 2017), there will be no commercial oil shale 

production; activities during this period will be focused on R&D and demonstration only. 

Commercial-scale production may start around 2017 at some project sites and reach a level of 

about 1 million bbl/day from those sites within a few years. Additional production from other 

project sites could start in a similar time frame, and a production rate of approximately 

2 million bbl/day could be reached around the end of the study period. 

The information presented in this paper defines the factors that will likely impact the 

incorporation of shale oil into the market. In addition, information from the relatively recent 

introduction of Canadian synthetic crude can be used to define a possible path for crude shale oil 

market infusion. To make any projections about the refinery market response to oil shale 

production, it is necessary to make certain assumptions. It is assumed that the U.S. refinery 

market will respond in a fashion consistent with past behavior. It is further assumed that both the 

Canadian crude and other foreign crude will continue at their current levels of availability. This 

analysis of potential markets for shale oil does not depend upon any reduction in available global 

supply typically referred to as the peak oil argument. The expected build-out of shale oil 
Final OSTS PEIS A-124 

production will enter at the beginning of the peak oil argument. Any international decline in 

crude oil production will only create greater demand for alternative crude production sources. An 

exception to the assumption that all existing crude supplies remain relatively stable is the 

Alaskan North Slope crude supply, for which, as noted, current projections forecast a 

significantly reduced production in the 10-year time frame. In the Alaska projection, the Alaska 

National Wildlife Refuge is not assumed to be in production. 

Because of the many uncertainties that still exist, it is probable that market development 

will proceed in different directions during different growth phases of the crude shale oil market. 

Initially, the market is likely to respond to new crude shale oil production through displacements 

of similar or complementary quality crude supplies from the refinery stream rather than 

expansions of refinery capacity. Such displacements, however, will be tempered by conditions in 

the market, including the relative price of crude oil of similar quality and existing crude oil 

supply contracts (as in the case of existing contracts for heavy Canadian crude oil). 

On the basis of historic patterns of expansion in refining capacity, refinery expansions to 

incorporate new crude shale oil supplies will occur incrementally, largely within areas of existing 

concentrated refining capacity, and only after refiners have identified a long-term profit margin 

for expanded facilities. The availability of new supplies alone is not sufficient to drive new 

refining capacity (as seen in the current oversupply of light crude in Wyoming). Only long-term 

profit potential will provide that incentive. 

The scenario described below reflects the suppositions and constraints discussed in this 

paper. There is no historic precedent for production increases of this magnitude in such a short 

period of time; therefore, this scenario may not be accurate. It does not represent the only 

pathway by which shale oil refining markets will develop but can nevertheless be justified on a 

number of critical levels. 

Development will likely occur in three phases: 

1. Early adoption and geographically local market penetration within PADD 4, 

2. Market expansion outside of PADD 4 with increased logistical capability (for 

both oil shale production facilities and transportation infrastructure), and 

3. High-volume production and multimarket penetration of a mature shale oil 

industry. 

Successful market penetration is a balance of crude shale oil availability, logistical 

availability (i.e., pipeline transportation), and market demand. Each phase of market maturity for 

shale oil will confront constraints in one or more of these areas. The relative significance of these 

constraints will shift during the various phases of maturity. 

 Phase 1, early adoption and local market penetration, will likely occur during the first 

5 years of commercial development. If approximately 1,000,000 bbl/day of oil shale is produced 

in Colorado during this time, the abundance of shale oil supply will be placed into a refinery 
Final OSTS PEIS A-125 

market that already is experiencing excess domestic production. Transportation capacity will be 

the limiting factor during this phase. Until reliable product definition and consistent quality of 

the crude shale oil are established, refineries will have a slow adoption rate and are more likely 

to only replace existing sources of crude of comparable quality. While it is unlikely that new 

refineries will be constructed during this period in response to this new production, the crude 

transport connections and overall refinery capacities within the PADD 4—Rocky Mountain 

region will need to be improved in order for these refineries to be early adopters. This could 

translate into the construction of new pipelines in the PADD 4 region. Demand in PADD 4 is not 

expected to increase dramatically during this time, but refineries could potentially reconfigure 

their processes or create new blends of crude stocks to better align their feeds with desired 

products. The potential qualities of crude shale oil could be similar to domestic light crudes and 

if market conditions allow, could compete with an already oversupplied local domestic crude 

market in the immediate vicinity. Alternatively, Phase 1 could be very short-lived, or skipped 

entirely, and Phase 2 conditions could prevail. 

Phase 2, market expansion beyond PADD 4, is likely to involve expansion of the 

transportation network, allowing distribution of crude shale oil outside of PADD 4. At the point 

in time that PADD 4 reaches a saturation point, thus presenting a growth-limiting factor, Phase 2 

expansions beyond PADD 4 will need to occur. This could occur starting around 2022 (or 

sooner) and extend until 2027 or beyond. To accomplish this, expansion of pipeline capacities to 

multiple markets outside of PADD 4 will be required. As addressed above, the most likely 

markets are the Midwest and Gulf Coast, although some potential growth could occur in the local 

markets. Because of the limited forecasted refinery expansion over this time period, new market 

penetration will require displacement of alternative sources of crude oil. The overall cost of 

production, the final qualities of the crude shale oil, and the availability of out-of-region 

transport will determine the economics and, subsequently, its economic viability. During this 

period, it is also unlikely that new refineries, will be constructed in any of the PADDs; more 

likely, the transportation network will expand and there could be some expansions at existing 

refineries. 

Phase 3 represents multimarket penetration and the maturation of the shale oil industry 

where the market is at equilibrium and crude shale oil availability is the limiting factor rather 

than transportation or refinery capacity. This phase assumes large volumes of crude shale oil 

would be produced (approximately 2 million bbl/day). By this time, it is realistic to expect that 

PADD 5—West Coast refineries that have been utilizing California and Alaskan North Slope 

crude will be searching for alternative sources of supply, which may bring these refineries into 

the shale oil market equation. The market viability of these levels of production is probably 

dependent upon integration with multiple regional markets and assumes ongoing economic 

viability versus alternative sources. Even in this long-range projection, neither demand or 

refining capacity in the PADD 4 local markets is expected to increase to a level that could utilize 

the expected shale oil production; thus, development of markets in other regions will be 

necessary to sustain the industry or allow it to reach its full projected production capacity. 

The long-term view for the potential for the oil shale industry beyond 2027, with an 

expected production capacity of 2.1 million bbl/day, could be realistic. On the basis of recent 

experience with the development and penetration of U.S. markets by Canadian syncrude, 
Final OSTS PEIS A-126 

however, the early and mid-phase development scenarios are aggressive, especially given some 

of the unknowns regarding the final reliable quality of crude shale oil produced at commercial 

scale and the extended time lines required for market acceptance and development of both 

transportation and refining infrastructures. Assuming that the chemical characteristics of the 

crude shale oil product are desirable (and assuming no revolutionary development of refining 

technology that would make feedstocks of marginal quality more desirable), market 

manipulation, including possible subsidization or facilitation of development of logistical 

infrastructure (e.g., designated pipeline corridors), could speed up market acceptance and make 

the overall scenario more likely. 

11 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

Arnold, J., 2006, “Trends in North American Refining,” presented at the American Institute of 

Chemical Engineers, Chicago Symposium 2006, Oct. 10, Jacobs Consultancy. Available at 

http://www.aiche-chicago.org/symposium/arnold.pdf. Accessed Feb. 2, 2007. 

CAPP (Canadian Association of Petroleum Producers), 2012, Crude Oil Forecast, Markets & 

Pipeline, June. Available at http://www.capp.ca/getdoc.aspx?DocId=209546&DT=NTV. 

Accessed July 19, 2012. 

Day, T., 2005, “Refining 101,” presented at Petro-Canada Mini-Investor Day: Downstream 

Strategy and Refining 101, Aug. 23. Available at http://www.petro-canada.ca/en/investors/ 

816.aspx. 

EIA (Energy Information Administration), 2006a, “Energy Kid’s Page, Petroleum (Oil) 

Refining.” Available at http://www.eia.doe.gov/kids/energyfacts/sources/non-renewable/ 

refinery.html. Accessed Oct. 4, 2006. 

EIA, 2006b, “Official Energy Statistics from the U.S. Government,” Appendix A, Map of 

Petroleum Administration for Defense Districts. Available at http://www.eia.doe.gov/pub/ 

oil_gas/petroleum/analysis_publications/oil_market_basics/paddmap.htm. Accessed 

Feb. 2, 2007. 

EIA, 2006c, Refinery Capacity Report 2006, released June 15, 2006. Available at 

http://www.eia.doe.gov/pub/oil_gas/petroleum/data_publications/refinery_capacity_data/ 

current/refcap06.pdf. Accessed Feb. 2, 2007. 

EIA, 2006d, “Petroleum Navigator, Refinery Utilization and Capacity: May 2006 through 

October 2006.” Available at http://tonto.eia.doe.gov/dnav/pet/pet_pnp_unc_dcu_nus_m.htm. 

Accessed Feb. 2, 2007. 
Final OSTS PEIS A-127 

EIA, 2006e, “World Oil Markets,” Chapter 3 of International Energy Outlook 2006, 

DOE/EIA-0484 (2006), June. Available at http://www.eia.doe.gov/oiaf/ieo/pdf/oil.pdf. 

Accessed Feb. 2, 2007. 

EIA, 2007, “Official Energy Statistics from the U.S. Government, Company Level Imports.” 

Available at http://www.eia.doe.gov/oil_gas/petroleum/data_publications/company_level_ 

imports/cli.html. 

EIA, 2012a, “U.S. Imports by County of Origin 2006 through 2011.” Available at 

http://205.254.135.7/dnav/pet/pet_move_impcus_a2_nus_ep00_im0_mbblpd_a.htm. 

Accessed June 27, 2012. 

EIA, 2012b, “Petroleum Navigator, Annual Crude Oil Production 2006 through 2011.” Available 

at http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm. Accessed June 27, 2012. 

ERCB (Energy Resources Conservation Board), 2012, Alberta’s Energy Reserves 2011 and 

Supply/Demand Outlook 2012–2021, ST98-2012, Calgary, Alberta, Canada. Available at 

http://www.ercb.ca/sts/ST98/ST98-2012.pdf. Accessed July 19, 2012. 

Office of the Secretary of Defense, 2005, Annual Report to Congress, The Military Power of 

the People’s Republic of China. Available at http://www.defenselink.mil/news/Jul2005/ 

d20050719china.pdf. Accessed Feb. 2, 2007. 

Slaughter, R., 2005, President, National Petroleum Refiners Association, Testimony before the 

Senate Committee on Commerce, Science, and Transportation, Sept. 21. 

Wall Street Journal, 2004, “Pump Power,” Opinion Page, May 24. Available at 

http://www.opinionjournal.com/columnists/pdupont/?id=110005087. Accessed Feb. 2, 2007. 
Final OSTS PEIS A-128 

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Final OSTS PEIS B-1 

APPENDIX B: 

TAR SANDS DEVELOPMENT BACKGROUND AND TECHNOLOGY OVERVIEW 

 
Final OSTS PEIS B-2 

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Final OSTS PEIS B-3 

APPENDIX B: 

TAR SANDS DEVELOPMENT BACKGROUND AND TECHNOLOGY OVERVIEW 

 This appendix describes the geology of the tar sands resource area, the resource, and the 

history of tar sands development in the western United States, and it provides an overview of the 

technologies that have been applied to tar sands development. It introduces technologies that 

may be employed in future developments on U.S. Department of the Interior, Bureau of Land 

Management (BLM)-administered lands. The technologies that are addressed include those used 

for recovery (i.e., mining), processing (i.e., separation and pyrolysis of the hydrocarbon fraction), 

and upgrading of tar sands resources. Finally, Attachment B1 provides an analysis of how the 

refining industry may adjust to the availability of syncrude feedstocks derived from U.S. tar 

sands. 

Tar sands deposits occur throughout the world except in Australia and Antarctica 

(Han and Chang 1994). The largest deposits occur in Alberta, Canada (the Athabasca, Wabasha, 

Cold Lake, and Peace River areas), and in Venezuela. Smaller deposits occur in the 

United States, with the larger individual deposits in Utah, California, New Mexico, and 

Kentucky. 

Accurate estimates of the reserves of hydrocarbon liquids in tar sands deposits have not 

been made, but worldwide demonstrated deposits (excluding inferred deposits) may total about 

320  109 m3 (2,000  109 bbl), with the largest share in Alberta, Canada, at about 270  109 m3

(1,700  109 bbl). There are about 546 occurrences of tar sands in 22 states in the United States 

in deposits that may have more than 4.5  109 m3 (28  109 bbl) of hydrocarbons. About 60% of 

this potential resource is located in Utah (Spencer et al. 1969; Meyer 1995). 

The term tar sands, also known as oil sands (in Canada), or bituminous sands, commonly 

describes sandstones or friable sand (quartz) impregnated with a viscous, extra-heavy crude oil 

known as bitumen (a hydrocarbon soluble in carbon disulfide). Significant amounts of fine 

material, usually largely or completely clay, are also present. The degree of porosity varies from 

deposit to deposit and is an important characteristic in terms of recovery processes. The bitumen 

makes up the desirable fraction of the tar sands from which liquid fuels can be derived. However, 

the bitumen is usually not recoverable by conventional petroleum production techniques 

(Oblad et al. 1987; Meyer 1995; Speight 1997). 

The properties and composition of the tar sands and the bitumen significantly influence 

the selection of recovery and treatment processes and vary among deposits. In the so-called “wet 

sands” or “water-wet sands” of the Athabasca deposit, a layer of water surrounds the sand grain, 

and the bitumen partially fills the voids between the wet grains. Utah tar sands lack the water 

layer; the bitumen is directly in contact with the sand grains without any intervening water 

(Speight 1997); such tar sands are sometimes referred to as “oil-wet sands.” Typically, more than 

99% of mineral matter is composed of quartz and clays. The general composition of typical 

deposits at the P.R. Spring Special Tar Sand Area (STSA) showed a porosity of 8.4 vol% with 

the solid/liquid fraction being 90.5% sand, 1.5% fines, 7.5% bitumen, and 0.5% water by weight 
Final OSTS PEIS B-4 

(Grosse and McGowan 1984). Utah deposits range from largely consolidated sands with low 

porosity and permeability to, in some cases, unconsolidated sands (Speight 1997). High 

concentrations of heteroatoms tend to increase viscosity, increase the bonding of bitumen with 

minerals, reduce yields, and make processing more difficult (Oblad et al. 1987). 

To utilize a tar sands resource in a mining operation, the bitumen must be recovered from 

its natural setting, extracted from the inorganic matrix (largely sand and silt) in which it occurs, 

and upgraded to produce a synthetic crude oil suitable as a feedstock for a conventional refinery. 

In general, it takes about 2.0 tonnes (2.2 tons) of surface-mined Athabasca tar sands to produce 

159 L or 1 barrel (42 gal) of synthetic oil (Oil Sands Discovery Center 2006a). Nonmining 

operations recover the bitumen already free of the matrix (sand and clays) in which it originally 

occurred. Preparation may require removal of bitumen or vaporized bitumen from steam, other 

gases, water, or solvents. Depending on the end product required, upgrading may not be 

required. 

At this time, there are no commercial tar sands operations for the production of oil for 

energy use on public lands in Utah. Commercial development could occur on lands with existing 

combined hydrocarbon leases (CHLs). The BLM does predict some commercial development 

on public lands under the new tar sands leasing program that would be established with this 

Allocation of Oil Shale and Tar Sands Resources on Lands Administered by the Bureau of Land 

Management in Colorado, Utah, and Wyoming Draft Programmatic Environmental Impact 

Statement (PEIS) and Possible Land Use Plan Amendments and the accompanying Record of 

Decision (ROD). It is also likely that additional development would proceed on private and/or 

state lands. The impacts being evaluated in the PEIS could occur under either a CHL or under a 

tar sands lease; however, the decisions that may result from this PEIS and its accompanying 

ROD are not applicable to CHLs. 

The following discussion includes general information on the geology, development 

history, and technologies for tar sands development that are being considered in this PEIS. 

Chapter 9 of the PEIS provides a glossary of technical terms used in the PEIS and its appendices, 

including geologic terms. 

B.1 DESCRIPTION OF GEOLOGY 

Tar sands are sedimentary rocks containing bitumen, a heavy hydrocarbon compound. 

Tar sands deposits may be divided into two major types. The first type is a breached petroleum 

reservoir where erosion has removed the capping layers from a reservoir of relatively heavy 

petroleum, allowing the more volatile petroleum hydrocarbons to escape. The second type of tar 

sands deposit forms when liquid petroleum seeps into a near-surface reservoir from which the 

more volatile petroleum hydrocarbons escape. In either type of deposit, the lighter, more volatile 

hydrocarbons have escaped to the environment, leaving the heavier, less volatile hydrocarbons in 

place. The material left in place is altered by contact with air, bacteria, and groundwater. 

Because of the very viscous nature of the bitumen in tar sands, tar sands cannot be processed by 

normal petroleum production techniques. 
Final OSTS PEIS B-5 

Tar sands deposits are not uniform. Differences in the permeability and porosity of the 

reservoir rock and varying degrees of alteration by contact with air, bacteria, and groundwater 

mean that there is a large degree of uncertainty in the estimates of the bitumen content of a given 

tar sands deposit. Estimates may be off by an order of magnitude (a factor of 10) 

(USGS 1980a–k). 

 More than 50 tar sands deposits occur in Utah. Limited data are available on many of 

these deposits, and the sizes of the deposits are based on estimates. Most of the known bitumen 

occurs in just a few deposits. The deposits that are being evaluated in this PEIS are those 

deposits classified in the 11 sets of geologic reports (minutes) prepared by the U.S. Geological 

Survey (USGS) in 1980 (USGS 1980a–k) and formalized by Congress in the Combined 

Hydrocarbon Leasing Act of 1981 (Public Law [P.L]. 97-78).1 While there are 11 sets of 

minutes, in some cases, the geologic report refers to more than one deposit. For example, the 

minutes titled Asphalt RidgeWhiterocks and Vicinity discuss the Asphalt Ridge deposit, the 

Whiterocks deposit, the Asphalt Ridge Northwest deposit, the Littlewater Hills deposit, and the 

Spring Hollow deposit. All of these deposits are included in the designated STSA and in this 

analysis for the PEIS. For the sake of convenience, the deposits are often combined and referred 

to on maps, and otherwise, as the Asphalt Ridge STSA. 

Tar sands deposits outside the areas designated by the Secretary of the Interior in the 

11 sets of minutes are not available for leasing under the tar sands program, but would be 

available for development under a conventional oil and gas lease. Figure B-1 shows the locations 

of the STSAs in Utah, as defined by the 11 sets of minutes from the USGS. Figure B-2 shows the 

generalized stratigraphy of the areas in Utah where the STSAs are present. 

Table B-1 provides estimates of the heavy oil resources for the 11 STSAs as published by 

Ritzma (1979). Additional resource estimates have been published in an Interstate Oil Compact 

Commission report titled, Major Tar Sand and Heavy Oil Deposits of the United States

(Lewin and Associates 1983). The data indicate that a large percentage of the tar sands bitumen 

in Utah is located within just a few of the STSAs. The following sections summarize the 

information that is available for each of the STSAs. The level of detail varies between the STSAs 

because significant amounts of information have been compiled only for those STSAs with the 

largest resource base. 

B.1.1 Argyle CanyonWillow Creek STSA 

The Argyle CanyonWillow Creek STSA, hereafter referred to as the Argyle Canyon 

STSA, is located in the southwestern portion of the Uinta Basin and includes deposits in two 

areas. These deposits are sometimes referred to independently as the Argyle Canyon deposits, 

which are located in the Bad Land Cliffs area, and the Willow Creek deposits, which are located 

along the western end of the Roan Cliffs. For the purposes of this PEIS, the Argyle Canyon 

 

1 The boundaries of the designated STSAs were determined by the Secretary of the Interior’s orders of 

November 20, 1980 (Volume 45, pages 76800–76801 of the Federal Register [45 FR 76800–76801]) and 

January 21, 1981 (46 FR 6077–6078). 
Final OSTS PEIS B-6 

FIGURE B-1 Special Tar Sand Areas in Utah 
Final OSTS PEIS B-7 

STSA includes both areas. All information presented in this 

section is from Blackett (1996) unless otherwise noted. 

The Argyle Canyon portion of the STSA is highly 

dissected by a north-south trellis-type drainage. The rocks 

present in this deposit are the Parachute Creek Member and 

the Deltaic facies of the Eocene Green River Formation, 

which is overlain by the Eocene Uinta Formation. The 

Parachute Creek Member is regularly bedded and contains 

siltstone, mudstone, and oil shale. The Deltaic facies is 

irregularly bedded, lenticular micaceous sandstone and 

interbedded mudstone. 

 The Willow Creek portion of the area is 

characterized by high plateaus dissected by deep, 

steep-walled canyons. Rocks present in the Willow Creek 

deposit are the upper part of the Garden Gulch Member and 

the lower part of the Parachute Creek Member of the Green 

River Formation (Eocene). The Garden Gulch Member 

consists of interbedded thin sandstone, siltstone, shale, and 

limestone. The Parachute Creek Member is composed of 

massive beds, thinning upward, of fine-grained sandstone, 

interbedded with siltstone and shale. 

Within the Argyle Canyon deposit, most of the 

bitumen is contained in the sandstones of the Deltaic facies. 

Within the Willow Creek deposit, channel sandstones 

contain most of the bitumen. Recovery of the bitumen in 

areas near outcrops, with gentle dips, would be amenable to 

surface mining. The remainder of the area would have to be 

developed by in situ methods (BLM 1984). 

B.1.2 Asphalt RidgeWhiterocks and Vicinity STSA 

The Asphalt RidgeWhiterocks and Vicinity STSA, 

hereafter referred to as the Asphalt Ridge STSA, is located 

along Asphalt Ridge, on the north-northeast flank of the 

Uinta Basin. Asphalt Ridge is a northwest-southeast 

trending cuesta, with dips to the southwest. All information 

presented in this section is from Blackett (1996) unless 

otherwise noted. FIGURE B-2 Generalized 

Stratigraphy of the Areas in Utah 

Where the STSAs Are Present 
Final OSTS PEIS B-8 

TABLE B-1 Estimated Resources in Place in Utah Tar Sands 

Deposits 

Measured 

(million bbl)a

Speculative 

(million bbl) 

 

Major Deposits 

 Uintah Basin 

 P.R. Spring 2,140 2,230 

 Hill Creek 320 560 

 Sunnyside 4,400 1,700 

 Whiterocks 60 60 

 Asphalt Ridge 830 310 

 Paradox Basin 

 Tar Sand Triangle 2,500 420 

 Nequoia Arch 730 160 

 Circle Cliffs Uplift 

 Circle Cliffs 590 1,140 

 San Rafael Uplift 

 San Rafael Swell 300 250 

Subtotal 11,870 6,830 

 

Minor Deposits 

 Uinta Basin 

 Argyle Canyon b 50–75 

 Raven Ridge  75–100 

 Rimrock  25–30 

 CottonwoodJacks Canyon  20–25 

 Littlewater Hills  10–12 

 Minnie Maud Creek  10–15 

 Pariette  12–15 

 Willow Creek  10–15 

 San Rafael Uplift 

 Black Dragon  100–125 

 Chute Canyon  50–60 

 Cottonwood Draw  75–80 

 Red Canyon  60–80 

 Wickiup  60–75 

Subtotal 557–707 

 

Total 11,870 7,387–7,537 

a bbl = barrel; 1 bbl syncrude = 42 gal. 

b A dash indicates no formal quantification available. 

Source: Ritzma (1979). 
Final OSTS PEIS B-9 

 The rock units present at Asphalt Ridge, in order of decreasing age, are the Mesaverde 

Group (Asphalt Ridge Sandstone, Mancos Shale, and Rim Rock Sandstone; all Cretaceous), 

possibly the Uinta Formation (Eocene), and the Duchesne River Formation (Eocene-Oligocene). 

The Uinta Formation may or may not be present as the contact between the Mesaverde Group 

and the Duchesne River Formation; it is gradational and difficult to recognize. The Duchesne 

River Formation unconformably overlies the Rim Rock Sandstone. Both the Duchesne River 

Formation and the Rim Rock Sandstone dip to the south-southwest at gradients ranging from 

8 to 30 the Rim Rock Sandstone generally has the steeper dips. 

The White Rocks tar sands deposit is found in the Navajo sandstone, which dips from 

70 to near vertical due to a major regional uplift and folding. Severe faulting has caused a large 

offset of the Navajo and other formations in the subsurface. However, within the limits of the 

deposit as seen at the surface, local faulting is small. The over- and underlying strata are 

impervious shales of the adjacent Chinle and Carmel Formations, which have sealed the bitumen 

in the Navajo. 

Several faults are known to have cut across the trend of the ridge. One has 150 ft of 

vertical displacement. At least one fault acted as a barrier to hydrocarbon migration, as the 

Asphalt Ridge Sandstone is bitumen saturated to the northwest of the fault and unsaturated to the 

southeast. 

The Rim Rock Sandstone, the Uinta Formation (where present), and the Duchesne River 

Formation all contain bitumen in the Asphalt Ridge area. The Rim Rock Sandstone is generally 

bitumen saturated for its entire outcrop length in the Asphalt Ridge area. The Uinta Formation 

generally contains bitumen only in sandy beds near the southern part of Asphalt Ridge. The 

bitumen saturation of the Duchesne River Formation varies both laterally and vertically. Rock 

composition of the Duchesne River Formation ranges from shale to conglomerate. The rocks 

with the greatest porosity, coarse sandstones, tend to have the highest bitumen saturations. 

It has been suggested that the bitumen in the White Rocks deposit is Tertiary and has 

migrated across joints and unconformities to the Jurassic Navajo. However, original paths of 

migration are not clear and Paleozoic source rocks have been suggested as an alternate 

hypothesis for the source of hydrocarbons. In the subsurface, the bitumen extends down to the 

water/oil contact in the steeply dipping Navajo sandstone. 

Recovery of the bitumen at this STSA would be amenable to surface mining along the 

outcrop on Asphalt Ridge. However, the surface minable portion of the deposit is primarily on 

state and private lands. In the remainder of the area, the deposits would have to be recovered by 

in situ methods (BLM 1984). 

B.1.3 Circle Cliffs East and West Flanks STSA 

The Circle Cliffs East and West Flanks STSA, hereafter referred to as the Circle Cliffs 

STSA, is located in south-central Utah, along the Circle Cliffs anticline. All information 

presented in this section is from BLM (1984) unless otherwise noted. 
Final OSTS PEIS B-10 

Rocks exposed at the surface in the vicinity of the Circle Cliffs anticline, in decreasing 

age order, are the Kaibab Limestone (Permian), Moenkopi Formation (Torrey Member and 

Moody Creek Member; Triassic), Chinle Formation (including the Shinarump Conglomerate; 

Triassic), Wingate Sandstone (Triassic/Jurassic), Kayenta Formation (Jurassic), Navajo 

Sandstone (Jurassic), Carmel Formation (Jurassic), Entrada Sandstone (Jurassic), and several 

younger units (Short 2006). The beds on the eastern side of the anticline dip from a few degrees 

to more than 25. The beds on the western side of the anticline dip from 2 to 3 to the west. 

The bitumen is contained in shoreface and fluvial-deltaic sandstones of the Torrey and 

Moody Creek Members of the Moenkopi Formation (Schamel and Baza 2003). Recovery of the 

bitumen would only be amenable to surface mining in very limited areas. In most of the area, the 

deposits would have to be recovered by in situ methods (BLM 1984; Kohler 2006). 

B.1.4 Hill Creek STSA 

The Hill Creek STSA is located along the Book Cliffs, on the south flank of the 

Uinta Basin. It lies to the west of the P.R. Spring STSA and east of the Sunnyside and Vicinity 

STSA. All information presented in this section is from Blackett (1996) unless otherwise noted. 

The Hill Creek STSA tar sands deposits are contained entirely within the Eocene Green 

River Formation. The composition of the Green River Formation includes oil shale, marlstone, 

shale, siltstone, sandstone, limestone, and tuff. The three mappable units of the Green River 

Formation in the vicinity of the Hill Creek deposit, in order of decreasing age, are the Douglas 

Creek Member, the Parachute Creek Member, and the Evacuation Creek Member. The 

Mahogany Bed, an important oil shale resource, lies between the Douglas Creek and Parachute 

Creek Members. 

There are five bitumen-impregnated zones in the Hill Creek STSA. Four of these zones 

are in the upper portions of the Douglas Creek Member, and one is in the lower part of the 

Parachute Creek Member. In ascending order, these zones have been designated A, B, C, D, 

and E. The zones can be correlated throughout the deposit. 

The extent of bitumen saturation varies laterally and vertically throughout each of the 

zones. Overburden thicknesses are too great throughout most of the deposit for surface mining to 

be feasible, and it is likely that recovery of the bitumen would require in situ methods 

(BLM 1984). 

B.1.5 Pariette STSA 

The Pariette STSA is located on the southern flank of the Uinta Basin in an area of low 

relief near the topographic center of the basin. All information presented in this section is from 

Blackett (1996) unless otherwise noted. 
Final OSTS PEIS B-11 

Rocks of the Uinta Formation (Eocene) are present within the Pariette STSA. The Uinta 

Formation rocks in the STSA are overlain by Quaternary surficial deposits. The Uinta Formation 

is nearly flat in the STSA, dipping 1 to 4 to the north. 

The bitumen-saturated zones are typically lenticular, fluvial sandstones. There is a large 

amount of horizontal and vertical variability in bitumen saturation levels within the Pariette 

STSA deposits. The small size and discontinuous nature of the individual areas of rock saturated 

with bitumen would tend to limit in situ production to a few of the larger bitumen-saturated 

areas. Development is limited by the small size, the lean quality (saturation is low), and the 

discontinuous lenticular-occurring nature of the deposits (USGS 1980e). 

B.1.6 P.R. Spring STSA 

The P.R. Spring STSA is located along the Book Cliffs in the southeastern part of the 

Uinta Basin, to the east of the Hill Creek STSA. The topography in the area is relatively flat, 

with narrow plateaus and mesas incised by intermittent and perennial streams. All information 

presented in this section is from Blackett (1996) unless otherwise noted. 

The geology of the Hill Creek STSA and the P.R. Spring STSA is essentially identical. 

The P.R. Spring STSA tar sands are contained entirely within the Eocene Green River 

Formation. The composition of the Green River Formation includes oil shale, marlstone, shale, 

siltstone, sandstone, limestone, and tuff. The three mappable units of the Green River Formation 

in the vicinity of the P.R. Spring deposit, in order of decreasing age, are the Douglas Creek 

Member, the Parachute Creek Member, and the Evacuation Creek Member. The Mahogany Bed, 

an important oil shale resource, lies between the Douglas Creek and the Parachute Creek 

Members. 

There are five bitumen-impregnated zones in the P.R. Spring STSA. Four of these zones 

are in the upper portions of the Douglas Creek Member, and one is in the lower part of the 

Parachute Creek Member. In ascending order, these zones have been designated A, B, C, D, 

and E. The zones can be correlated throughout the deposit. 

The extent of bitumen saturation varies laterally and vertically throughout each of the 

zones. Numerous tar seeps occur along the outcrop of the bitumen-impregnated areas within the 

STSA. They tend to be active during periods of wet weather and inactive during drier periods. 

Overburden thicknesses are too great throughout most of the deposit for surface mining 

to be feasible, except in the southern part of the STSA. It is likely that recovery of the bitumen 

would require in situ methods, except in the southern part of the STSA where these deposits are 

considered among the most valuable for surface mining (USGS 1980f). 
Final OSTS PEIS B-12 

B.1.7 Raven RidgeRim Rock and Vicinity STSA 

The Raven RidgeRim Rock and Vicinity STSA, hereafter referred to as the Raven 

Ridge STSA, is located on the north flank of the Uinta Basin and includes deposits in two areas. 

These deposits are sometimes referred to independently as the Raven Ridge deposits, which are 

located along a series of northwest-trending hogbacks known as Raven Ridge, and the Rim Rock 

deposits, which lie at the east end of a series of low, west-northwest-trending hogbacks called the 

Rim Rock. The Raven Ridge portion of the STSA is east of Asphalt Ridge. The Rim Rock 

portion lies between Raven Ridge and Asphalt Ridge. All information presented in this section is 

from Blackett (1996) unless otherwise noted. 

Rocks present within the Raven Ridge deposit include, in order of decreasing age, the 

Paleocene/Eocene Green River Formation (Douglas Creek Member, Parachute Creek Member, 

and Evacuation Creek Member) and the Eocene Uinta Formation. The Mahogany oil shale zone 

occurs above the Raven Ridge tar sands deposit. Rocks in the Raven Ridge area dip from 10 to 

85 southwest, with an average dip of 30. They are composed of shoreline and deltaic facies 

sandstone, limestone, and shale in the Green River Formation, and fluvial-deltaic shale, 

sandstone, and pebble conglomerate in the Uinta Formation. All four of the rock units present in 

the Raven Ridge area contain some bitumen. Saturation levels vary greatly between units, as well 

as in lateral and vertical extent. 

The Wasatch Formation (Paleocene) and the Douglas Creek and Parachute Creek 

Members of the Green River Formation are present in the Rim Rock part of the STSA. Rocks in 

the Rim Rock area dip as much as 76 to the southwest. Each successively younger unit overlaps 

and truncates the next older unit. Bitumen is located within the Wasatch Formation sandstones 

and in Green River sandstones that truncate older Wasatch Formation rocks. 

Recovery of the bitumen by surface mining would be possible in the Raven Ridge STSA 

only along the outcrops on Raven Ridge. In situ methods would be needed elsewhere 

(BLM 1984). 

B.1.8 San Rafael Swell STSA 

The San Rafael Swell STSA is located in the southwestern portion of Utah. The 

San Rafael Swell is a breached dome, with the core of older rocks exposed in the middle of the 

dome. The rocks dip away from the geographic center of the dome, in all directions. Schamel 

and Baza (2003) report that the White Rim Sandstone, within the San Rafael Swell deposit, 

contains bitumen. The White Rim Sandstone is present only on the eastern most edge of the 

San Rafael Swell. All information presented in this section is from BLM (1984) unless otherwise 

noted. 

Rocks exposed at the surface in the vicinity of the San Rafael Swell, in order of 

decreasing age, are the Cutler Group (White Rim Sandstone; Permian), Kaibab Limestone 

(Permian), Moenkopi Formation (Sinbad Limestone Member and Black Dragon Member; 

Triassic), Chinle Formation (Triassic), Wingate Sandstone (Triassic/Jurassic), Kayenta 
Final OSTS PEIS B-13 

Formation (Jurassic), Navajo Sandstone (Jurassic), and San Rafael Group (Carmel Formation, 

Entrada Sandstone, Curtis Formation, and Summerville Formation; Jurassic) (USGS 2006). 

All of the rock units in the San Rafael Swell area contain bitumen in some areas 

(Schamel and Baza 2003). Within the deposit, most of the bitumen occurs within the lower and 

middle portions of the Black Dragon Member of the Moenkopi Formation. The other units 

contain lesser amounts of bitumen, with some such as the Sinbad Limestone containing only 

isolated spots of bitumen. 

In situ methods would be the preferred methods of production for the San Rafael Swell 

STSA. The overburden is too great for recovery of the bitumen by surface mining (BLM 1984). 

B.1.9 Sunnyside and Vicinity STSA 

The Sunnyside and Vicinity STSA, hereafter referred to as the Sunnyside STSA, is 

located along the Roan Cliffs on the southwestern flank of the Uinta Basin. The topography of 

this area is characterized by high relief and rugged terrain. All information presented in this 

section is from Blackett (1996) unless otherwise noted. 

The rock units present at Sunnyside, in order of decreasing age, are Colton Formation 

(Paleocene/Eocene) and the Lower Green River Formation (Eocene). Colton Formation rocks are 

shale, siltstone, and sandstone, which were deposited in a fluvial-deltaic environment. The Green 

River rocks were deposited in a lacustrine environment and are composed of shale, marlstone, 

siltstone, sandstone, limestone, and tuff. Bitumen in the deposit is typically contained in 

sandstone. The bitumen content is typically inversely proportional to the distance from the 

deltaic complex. 

The rocks in the Sunnyside area dip to the northeast at 3 to 12. Small-scale faulting and 

fracturing occur in the area but do not appear to have affected bitumen emplacement. 

The depositional environments in this area have resulted in a complex stratigraphy. 

Bitumen saturation may vary greatly within just a few feet, with bitumen-saturated rock and 

barren rock occurring within a few feet of each other. Surface mapping has identified as many as 

32 bitumen saturated beds. 

Recovery of the bitumen by both surface mining and in situ methods would be needed to 

fully develop the Sunnyside deposit (BLM 1984). 

B.1.10 Tar Sand Triangle STSA 

The Tar Sand Triangle STSA is located in southeastern Utah along the western edge of 

the Monument Upwarp. The topography of the area is a dissected plateau. The margins of the 

plateau have stair-step topography, and mesas and buttes occur as outliers from the plateau 
Final OSTS PEIS B-14 

(BLM 1984). All information presented in this section is from Glassett and Glassett (1976) 

unless otherwise noted. 

The rocks present in the Tar Sand Triangle STSA, in order of decreasing age, include the 

Cutler Group (Cedar Mesa Sandstone and White Rim Sandstone; Permian), Moenkopi Formation 

(Triassic), and Chinle Formation (Shinarump Conglomerate; Triassic). The Monument Upwarp 

is a westward-dipping monocline, and the Permian and Triassic rocks of central Utah pinch out 

against the upwarp. The bitumen in the Tar Sand Triangle STSA appears to be the residue of a 

gigantic oil field located in the stratigraphic trap formed by this pinch out. The oil field was 

breached by erosion allowing the more volatile components to escape, leaving the less volatile 

components behind. 

Although bitumen is found in the Cedar Mesa Sandstone, White Rim Sandstone, 

Moenkopi Formation, and Shinarump Conglomerate, most of the bitumen is located in shoreface 

and eolian deposits of the Permian White Rim Sandstone near its southeastern extent, as it 

pinches out against the Monument Upwarp (Schamel and Baza 2003). 

The Tar Sand Triangle deposit may be technically suitable for surface mining; however, 

the remoteness of the area and other considerations could limit this potential (BLM 1984). 

B.1.11 White Canyon STSA 

The White Canyon STSA is located south of the Tar Sand Triangle STSA, in the 

White Canyon area of southeastern Utah. The topography in the area is that of one large mesa 

with bench and slope topography along its margins. The ground below the mesa is incised by 

White Canyon. All information presented in this section is from BLM (1984) unless otherwise 

noted. 

Rocks present in the White Canyon area, in order of decreasing age, include DeChelly 

and/or White Rim Sandstones (these two sandstones are coeval; Permian), Moenkopi Formation 

(Hoskinnini Member; Triassic), and Chinle Formation (Shinarup Member; Triassic) (Beer 2005). 

Other rock units may be present but are not relevant to the tar sands. The Hoskinnini Member, 

which hosts all of the bitumen in the White Canyon STSA, pinches out toward the northwestern 

part of the STSA. 

The lack of site-specific data precludes any consideration of mining methods for the 

White Canyon deposit. The data available on the quality of the deposit suggest that it is not of 

commercial grade. It may be too heavily jointed for in situ methods, and heavy overburden 

appears to be unfavorable for surface mining (USGS 1980k). 

B.2 PAST EXPLORATION AND DEVELOPMENT ACTIVITY 

The mining of petroleum-bearing materials from tar sands has been practiced for 

thousands of years. Petroleum and bitumen were mined in the Sinai Peninsula before 5,000 B.C. 
Final OSTS PEIS B-15 

The bitumen was used as an adhesive, brick binder, and waterproofing agent and, somewhat 

later, it was used to produce petroleum as a fuel. However, the distillation process was lost and 

not used again until the middle of the nineteenth century with the advent of drilling for oil. 

Underground oil mining was practiced in the Alsace region of France from about 1735 to 1866. 

The mined sand was treated on the surface with boiling water to release the oil. After 1866, oil 

was obtained by letting it drain into mine shafts where it was recovered as a liquid (National 

Academy of Sciences 1980; Meyer 1995; Speight 1995). 

Natural bitumen (or natural asphalt) has been used throughout the world, primarily in the 

last 200 years, during which time it was widely used as a paving material. This use has largely 

been replaced by the use of manufactured asphalt. In the 1890s, the Canadian government 

became interested in oil sands deposits. Research on recovery mining from the Athabasca oil 

sands began in the 1920s. Three extensive pilot-scale operations were conducted between 1957 

and 1967, and commercial operations began in 1967 when the Great Canadian Oil Sands 

Company (now Suncor) started open-pit mining using bucket-wheel excavators, conveyor belts, 

and hot water extraction (Oblad et al. 1987; Meyer 1995; Speight 1995, 1997; 

Woynillowicz et al. 2005). By 1976, cyclic steam recovery had been piloted by Imperial Oil 

Limited at Cold Lake. Syncrude Canada Ltd. opened the Athabasca deposits in 1978 using 

draglines, bucket-wheel reclaimers, and conveyor belts. By 1986, steam-assisted gravity drainage 

(SAGD) had been piloted, and in situ combustion was being researched in Canada. Suncor and 

Syncrude were in commercial operation as was Imperial Oil’s cyclic steam facility. By 1996, 

both Suncor and Syncrude had converted their extractions to truck and shovel operations. For 

surface mining, hydrotransport (the transport of mined sand as a slurry of warm water and sand 

in pipes) rather than conveyor belts was used to transport mined sand to the extraction plant for 

cold-water extraction, mechanical separation, and by-product recovery. Several new in situ 

projects were also in commercial operation (Oil Sands Discovery Center 2006a.) By 2004, about 

two-thirds of the recovered oil sands in Alberta were mined; about one-third was recovered by in 

situ operations (Alberta Economic Development 2006). 

In Utah, the amount of exploration and development for tar sands resources has varied 

from location to location. No known exploration or development activities have occurred at the 

Argyle Canyon, Circle Cliffs, Hill Creek, Pariette, San Rafael Swell, Tar Sand Triangle, or 

White Canyon STSAs. A brief description of previous activities at the other STSAs is provided 

below (from Blackett 1996). 

• Asphalt Ridge STSA. The Asphalt Ridge deposit has been the target of many 

exploration and development efforts. It was mined at least as early as the 

1920s when the town of Vernal, Utah, paved its streets with material from the 

deposit. Between 1910 and 1950, a number of shallow wells were drilled in 

the area in an attempt to locate liquid hydrocarbons below the bitumen cap. 

During the 1930s, a hot-water extraction plant was built to extract tar from the 

deposit. Knickerbocker Investment Company and W.M. Barnes Engineering 

Company conducted a comprehensive evaluation program on Asphalt Ridge 

in the early 1950s. Sohio Petroleum Company then leased Asphalt Ridge and 

conducted its own evaluation program. In 1970 or 1971, Major Oil Company 

obtained a working agreement with Sohio to strip-mine the tar sands and build 
Final OSTS PEIS B-16 

and operate an extraction plant. Hot water was used to strip the bitumen from 

the crushed run-of-mine material, and the bitumen was shipped to a refinery in 

Roosevelt, Utah. Arizona Fuels Corporation and Fairbrim Company acquired 

the operation in 1972. In the 1970s, Sun Oil Company, Texaco, Phillips 

Petroleum Company, and Shell Oil Company conducted exploratory drilling 

at Asphalt Ridge. The U.S. Department of Energy (DOE) conducted extensive 

field experiments on the deposit between 1971 and 1982. 

• P.R. Spring STSA. In 1900, John Pope drilled an oil test well in the 

P.R. Spring deposit. During the early twentieth century (the exact date is 

unknown), a 50-ft-long adit was driven into a tar sands outcrop in the 

P.R. Spring area. A steel pipe was run from the adit to a metal trough to 

collect the gravity-drained oil. In the 1970s and 1980s, the P.R. Spring deposit 

was the target of intense exploration and research activity by several 

companies and government agencies. The U-tar Division, Bighorn Oil 

Company, operated a 100-bbl/day pilot plant in the area. Although several 

other companies proposed development operations for the P.R. Spring deposit, 

no viable commercial production has occurred. 

• Raven Ridge STSA. Sporadic attempts to develop the Raven Ridge deposit 

were made before 1964. Western Tar Sands, Inc., conducted test mining 

activities on the deposit during the summer of 1980 and planned to build a 

100-bbl/day production facility. This plant was not built, and there have been 

no other exploration or development activities at the STSA since. 

• Sunnyside STSA. The Sunnyside deposit was mined, primarily for road 

construction, from 1892 to the late 1940s. The mined material was transported 

over a 3-mi-long aerial tram and then trucked to the railhead at Sunnyside, 

where it was shipped to five other western states. A large number of 

companies, including Shell Oil Company, Signal Oil and Gas Company, 

Texaco, Gulf Oil Corporation, Pan-American Petroleum Corporation, Phillips 

Petroleum, Sabine Resources, Cities Service, Amoco, Chevron Resource 

Company, Great National Corporation, and Mono Power Company, 

conducted activities in the Sunnyside deposit from 1963 through 1985. Shell 

Oil Company, Signal Oil and Gas Company, Pan-American Petroleum 

Corporation, Mono Power Company, and Great National Corporation all 

conducted pilot operations on the deposit. Sunnyside sandstone was mined as 

a road-paving material as early as 1892 through 1948. These deposits were 

also the site of Shell Oil’s steam flood pilot plant from 1964 to 1967 and a 

mining and bitumen extraction operation from 1982 to 1985. 

B.3 PRESENT EXPLORATION AND DEVELOPMENT ACTIVITY 

Currently, little tar sands development activity is underway on public lands in Utah. As of 

2006, according to the Utah Office of Energy Policy (Wright 2006), the only ongoing tar sands 
Final OSTS PEIS B-17 

operations in Utah were small pilot-scale and exploration operations and a few small mining 

operations by counties to recover road materials (including operations by Uintah County to 

excavate materials at Asphalt Ridge for road surfacing). The Utah Division of Oil, Gas and 

Mining expected to see several of the pilot operations expand to large mines ranging from 5 to 

possibly 80 acres in size. Specifically, the Division projected three large mines (two on private 

and one on state lands) and eight small mines (one on private and seven on state lands) in the 

future. As of summer 2012, progress on the development of tar sands for oil production remained 

at the research and development level, with no commercial oil production from tar sands in 

operation. The University of Utah prepared an assessment of the technical, economic, and legal 

aspects of North American heavy oil, oil sands, and oil shale resources in response to the Energy 

Policy Act of 2005 (University of Utah 2007). This report notes that no significant tar sands 

development has taken place on BLM leases granted in 1995 on about 14,000 acres in the 

Sunnyside and P.R. Spring deposits. 

For several years, Nevtah Capital Management Corp. and its joint venture partner, Black 

Sands Energy (formerly known as Cassandra Energy, Inc.), have been working to develop an oil 

extraction technology for commercial tar sands development. Initial tests were conducted at the 

Asphalt Ridge STSA. On August 1, 2006, the companies announced the completion of 

construction of their first commercial production unit, which was built off-site and has a 

production capacity of 400 to 500 bbl/day of syncrude. The companies hold a total of 13 leases 

covering 11,000 acres within the Asphalt Ridge, Sunnyside, and P.R. Spring STSAs 

(Nevtah Capital Management Corp. 2006). As of 2009, according to its Web site, the company 

was continuing tar sands development research at it Bartlesville, Oklahoma, facility and was in 

the process of raising capital for a prototype facility in Utah. 

U.S. Oil Sands (Utah) Inc., a U.S. subsidiary of a Canadian company, announced in 

May 2012 progress on its tar sands efforts in its P.R. Spring area holdings in Uintah County. The 

company reported completion of an independent bitumen resource assessment of the P.R. Spring 

area and progress in engineering design work for its commercial bitumen mining project. The 

company expressed its intentions to begin commercial bitumen production in 2013 using a 

proprietary bio-solvent process (U.S. Oil Sands 2012). 

 Temple Mountain Energy has been producing asphalt for road paving and other 

applications at its operations in Asphalt Ridge in the Uinta Basin since 2006. The company also 

produces bitumen for road construction as an asphalt binder. The raw bitumen can also be 

upgraded and sold as low-sulfur crude oil to refiners, who can further refine it to liquid products 

such as gasoline and diesel. The company also markets the spent sands produced after separation 

of bitumen for use in a variety of industries, including oil and gas fracturing and for glass making 

(Temple Mountain Energy 2011). 

An application for a commercial tar sands lease covering 2,100 acres on public lands in 

Asphalt Ridge STSA was submitted to the BLM in 2011 and is currently under review. 
Final OSTS PEIS B-18 

B.4 RECOVERY OF TAR SANDS 

Recovery methods can be categorized as 

either mining activities or in situ processes. 

Mining consists of using surface or subsurface 

mining techniques to excavate the tar sands with 

subsequent recovery of the bitumen by washing, 

flotation, or retorting. In situ techniques recover 

the bitumen without physically excavating the tar 

sands. Some techniques combine mining 

techniques and in situ techniques. In situ recovery 

is sometimes further categorized as true in situ or 

modified in situ. True in situ methods generally 

involve either heating the tar sands or injecting 

fluids into them to mobilize the bitumen for 

recovery (Speight 1990, 1995, 1997). There are at 

least two types of modified in situ methods. The 

first involves fracturing the tar sands with 

explosives to increase the permeability of the 

deposit (National Academy of Sciences 1980); 

the second process combines true in situ 

processes with mining techniques (Speight 1990). 

Depending on production costs and the 

price of the synthetic crude produced, surface 

mining operations are generally cost-effective 

only where the overburden is no more than about 45 m (150 ft) (Meyer 1995). In situ processes 

requiring high pressures are generally considered to require a thick overburden of about 150 m 

(500 ft) to contain the pressure. Between these depths, bitumen must be extracted by other 

means. 

B.4.1 Direct Recovery Mining Technologies

Surface mining methods can be used to mine the tar sands for subsequent recovery of 

bitumen. Subsurface mining has been proposed but has not been applied because of the fear of 

collapse of the sand deposits (Speight 1990). For this reason, only surface mining is discussed 

below. However, subsurface mining techniques are employed in some modified in situ recovery 

methods. 

Surface mining requires conventional earthmoving and mining equipment (BLM 1984). 

Development begins with the construction of access roads and support facilities. Major mining 

activities during extraction include the following: 

• Removing vegetation; 

Potential Tar Sands Recovery Processes

Mining 

 Surface 

 Subsurface 

In Situ 

 Thermal 

− Steam and hot water 

• Stimulation 

• Flood 

− Combustion 

• Forward 

• Reverse: wet, dry 

− Electrical 

− Nuclear 

 Nonthermal 

− Diluents 

• Miscible displacement: 

hydrocarbons, inert gases, 

carbon dioxide 

• Solvent 

• Chemical: polymer, caustic, 

surfactant polymer 

− Emulsification 

− Bacterial

Source: Based on Speight (1997). 
Final OSTS PEIS B-19 

• Stripping, stockpiling, and disposal of topsoil; 

• Removing and disposing of overburden; 

• Excavating of tar sands; and 

• Reclamation of the mined area. 

Operations begin with the removal of topsoil and overburden. Topsoil is stockpiled, 

protected from erosion, and used for reclamation. Erosion and runoff can be reduced by 

depositing overburden in layers beginning in the bottoms of valleys and building upwards. Later, 

the deposited overburden can be used for backfilling the pit. It is likely that ultimately the entire 

area would be disturbed because of actual mining and ancillary activities. Reclamation can 

proceed as mining progresses and initially mined areas are retired (BLM 1984). 

Disposing of waste sand after extraction of the bitumen is a major concern in any surface 

mining operation (BLM 1984). Although variable, the bitumen content of waste sand can be as 

high as 5%. Waste sand can be disposed of by (1) backfilling the mined area, (2) filling valleys, 

or (3) using tailings ponds. Tailings ponds need to be constructed to keep tailings from sliding, to 

preclude outside runoff from entering the ponds, and to control seepage from the ponds. 

In Utah, less than 15% of the tar sands may be shallow enough for strip mining; the 

deposits at the Asphalt Ridge, P.R. Spring, and Sunnyside STSAs appearing to be most suitable 

(BLM 1984; National Academy of Sciences 1980). The Athabasca deposits are currently being 

recovered by surface mining. 

The equipment used for surface recovery includes a combination of excavation 

equipment, to remove the sands from their original location, and conveying equipment, to move 

the excavated sand to another location. Depending upon the approach chosen, tar sands removal 

equipment can include draglines, bucketwheel excavators, power shovels, scrappers, bulldozers 

and front-end loaders. Conveying equipment can include belt conveyors, large trucks (typically 

150400 tons), trains, scrapers, and hydraulic systems (Speight 1995). 

Surface excavation is conducted by using two basic approaches. The first uses a small 

number of large, custom-made, expensive bucketwheel excavators and drag lines along with belt 

conveyors. The second uses a large number of smaller, conventional, less expensive equipment. 

Initially, the major developers of the Athabasca oil sands in Canada used bucketwheels or 

draglines, they now use a truck and shovel approach. Truck and shovel mining is more mobile, 

can be moved more easily to the richest deposits, and requires less maintenance than the custom 

bucketwheels and draglines. The larger number of units in operation also means that equipment 

breakdown has much less impact on overall production. 

Today, hydrotransport provides an alternative to the use of belt conveyors between the 

mining pit and the extraction plant (Oil Sands Discovery Center 2006b). The oil sands are 

crushed at the mine site, mixed with warm water, and moved by pipeline to the extraction plant. 

Hydrotransport improves efficiency by initiating the extraction of bitumen while the oil sands are 
Final OSTS PEIS B-20 

being transported to the extraction plant. However, its application in arid areas such as Utah may 

be problematic. 

Speight (1995) identifies the following possible problems that may be encountered when 

mining tar sands deposits: 

• The clay shale overburden and sand may swell when exposed to fresh water, 

• Pit wall slopes may slough off and may need to be controlled by preblasting or 

excluding heavy equipment from slope crests, 

• The abrasive sands cause a high rate of equipment wear, and 

• The large quantity of tailings from the extraction process requires disposal. 

 Table B-2 provides available data describing potential impact-producing factors that 

could be associated with a tar sands surface mine. These data were derived from information 

published by Daniels et al. (1981) on the basis of a proposed 20,000-bbl/day-capacity plant 

designed for recovery of oil from a diatomaceous earth tar sands deposit near McKittrick, 

California. The volatile emissions data presented in this table are likely to exceed those that 

would be expected from one of the Utah tar sands deposits because the bitumen is more volatile 

at McKittrick. In addition, the particulate emissions are likely to exceed emissions from a Utah 

deposit because the diatomaceous earth tar sands at McKittrick are less tightly bound than the 

sandstone deposits in Utah. The table presents the original numbers estimated for the McKittrick 

project and extrapolated numbers for larger operations. It should be noted that the numbers were 

extrapolated linearly because no information is available to justify doing otherwise; linear 

extrapolations are likely to result in conservative overestimates of potential impacts. 

 Table B-3 provides available data describing potential air emissions from a tar sands 

surface mine on the basis of data published by Aerocomp, Inc. (1984), for a proposed 

32,500-bbl/day-capacity project in the Sunnyside STSA. These data may more accurately reflect 

emissions from a surface mine excavating sandstone-based tar sands deposits as opposed to the 

emissions presented in Table B-2 for the diatomaceous earth tar sands deposit. 

B.4.2 In Situ Methods 

 Given the environmental problems associated with mining and the fact that the majority 

of tar sands lie under an overburden too thick to permit their economic removal, nonmining 

recovery of bitumen may be a practical alternative. This is especially true in U.S. deposits where 

the terrain and the character of the tar sands may not be favorable for mining. However, the 

physical properties of Utah tar sands and the bitumen may constrain application of nonmining 

methods; Utah sands tend to be low-porosity, low-permeability, consolidated to unconsolidated 

sands, and the bitumen does not flow under reservoir conditions. Low permeability and porosity 

require fluids to be injected at pressures sufficient to cause fracturing, which can result in 
Final OSTS PEIS B-21 

TABLE B-2 Potential Impact-Producing Factors Associated with 

a Tar Sands Surface Mine Operating at a Diatomaceous Earth Tar 

Sands Deposit 

Production Capacity 

(bbl/day syncrude)b,c

Impact-Producing Factora 20,000 25,000 50,000 100,000 

 

Total land disturbance (acres) 1,000 1,250 2,500 5,000 

Water use (bbl/day)d 25,160 31,450 62,900 125,800 

Noise (dBA at 500 ft) 61 e  

Processed sand (tons/day) 52,000 65,000 130,000 260,000 

Air emissions (tons/yr)f

 

 Mining equipment 

 TSP 70 87 174 348 

 SOx 70 87 174 348 

 NOx 905 1,131 2,262 4,524 

 CO 383 479 957 1,914 

 THC 104 131 261 522 

 Crushing apparatusg 

 TSP 7 9 17 35 

 Mine pit and storageh 

 TSP 1,009 1,262 2,523 5,046 

 THC 35 44 87 174 

a CO = carbon monoxide; NOx = nitrogen oxides; SOx = sulfur oxides; 

THC = total hydrocarbons (includes methane and photochemically 

nonreactive compounds); TSP = total suspended particulates (includes all 

particulate matter up to about 100 m in diameter). 

b bbl = barrel; 1 bbl syncrude = 42 gal, 1 bbl water = 55 gal. 

c Data taken from Daniels et al. (1981) for a proposed 20,000-bbl/daycapacity plant designed for recovery of oil from a diatomaceous earth tar 

sands deposit near McKittrick, California. Numbers for larger production 

capacities were extrapolated linearly, which is likely to result in 

conservative overestimates of potential impacts. 

d Approximately 3.5% of the process water would need to be fresh water 

(Daniels et al. 1981). 

e A dash indicates noise level determined by modeling, not by 

extrapolation. 

f

 The volatile emissions data presented in this table are likely to exceed 

those that would be expected from one of the Utah tar sands deposits 

because the bitumen is more volatile at McKittrick. In addition, the 

particulate emissions are likely to exceed emissions from a Utah deposit 

because the diatomaceous earth tar sands at McKittrick are less tightly 

bound than the sandstone deposits in Utah. 

g Assumes 99.5% emissions control via the baghouse. 

h Assumes 80% dust suppression by virtue of the natural oil in the tar sands 

combined with water application. 
Final OSTS PEIS B-22 

TABLE B-3 Potential Air Emissions from a Surface Mine Operating at a 

Sandstone-Based Tar Sands Deposita

Production Capacityc,d

Air Emissionsb

20,000 bbl/day 

syncrude 

(tons/yr) 

32,500 bbl/day 

syncrude 

(tons/yr) 

50,000 bbl/day 

syncrude 

(tons/yr) 

100,000 bbl/day 

syncrude 

(tons/yr) 

 

TSP 2,814 4,573 7,035 14,071 

SOx 335 544 837 1,674 

NOx 5,276 8,573 13,189 26,378 

CO 1,047 1,701 2,617 5,234 

VOC 338 549 322 1,689 

a Modeled on the basis of the following: height above ground surface = 3 m (9.8 ft) 

and area = 2,000 m2 (2,392 yd2). 

b CO = carbon monoxide; NOx = nitrogen oxides; SOx = sulfur oxides; TSP = total 

suspended particulates (includes all particulate matter up to about 100 m in 

diameter); VOC = volatile organic compound. 

c bbl = barrel; 1 bbl syncrude = 42 gal. 

d The air emissions data were derived from information published by Aerocomp, Inc. 

(1984) for a proposed 32,500-bbl/day-capacity project in the Sunnyside STSA. 

Numbers for larger production capacities were extrapolated linearly, which is likely 

to result in conservative overestimates of potential impacts. 

undesirable flow pathways (e.g., direct communication between the injection well and the 

production well) (Speight 1990). 

In situ or nonmining methods are basically enhanced or tertiary oil recovery techniques 

that require injecting a “heating” and “driver” substance into the tar sands formation through 

injection wells to reduce the viscosity of and displace the bitumen so that it can be recovered 

through conventional liquid production wells (Speight 1997). For a given technique, there could 

be considerable variation in the efficiency of extracting bitumen between different sites, for 

example, between water-wet Athabasca sands and oil-wet Utah sands (BLM 1984). 

All in situ recovery processes must perform the following: 

• Establish fluid flow between injection and production wells; 

• Reduce the viscosity of the bitumen by heating it or dissolving it in a solvent 

so that it will flow to the production well; and 

• Maintain the flow of bitumen after it has started. 
Final OSTS PEIS B-23 

Heat could be supplied either from steam from surface boilers or by combustion of part 

of the bitumen in situ. In addition, the deposit should be permeable or susceptible to fracturing to 

make it permeable and reasonably stable so that it does not compact structurally (i.e., collapse) 

and lose permeability as bitumen is removed (BLM 1984). 

 Briefly, development of an in situ facility would include the following processes: 

• Exploration to characterize the formation hydrogeologically; 

• Drilling of injection and production wells; 

• Installation of production equipment; 

• Recovery, processing, and upgrading of bitumen to produce synthetic crude 

oil; 

• Removal of equipment at the close of operations; and 

• Reclamation. 

Numerous, closely spaced holes would be required for injection and production wells, 

with production wells probably spaced within 150 m (500 ft) of each other. The exact number 

and the spacing of the wells would be governed by the characteristics of the formation. Surface 

equipment would vary by the method used but would include drilling rigs, compressors, pumps, 

piping, storage tanks, waste pits, and pits or tanks for drilling fluids and process water storage 

and recycling. For most processes, especially those involving steam injection, boilers and steam 

pipes would also be required. Facilities for treating condensate and water for recycling would 

also be needed. Ancillary facilities could include shops, warehouses, offices, outside storage 

areas, fuel storage, housing, and roads (BLM 1984). 

Over time, different parts of the site would be developed, and production equipment 

would be moved from one area to another as the recoverable bitumen was exhausted. Upgrading 

equipment would be centrally located and would probably not be moved over the life of the site. 

After the production equipment had been moved, the depleted site could be reclaimed. The 

amount of surface disturbance from development of in situ recovery facilities would depend on 

topography and the characteristics of the bitumen and the surrounding rock. Estimates of surface 

disturbance range from 10 to 60% of the site and are expected to be similar for most in situ 

methods. The use of directional drilling techniques tends to reduce the amount of surface 

disturbance (BLM 1984). In addition to the disturbances resulting directly from surface 

activities, subsidence may also occur and require remediation. 

B.4.2.1 Combustion Processes and Modifications 

In combustion processes, the bitumen itself is ignited. Once ignition has been achieved, 

partial or complete combustion must be maintained for a period of about 30 to 90 days. 
Final OSTS PEIS B-24 

Temperatures can range from about 600 to 1,200°F. Control of the amount of air injected 

regulates the rate at which bitumen is burned and hence the temperature. Several regions exist 

within the reservoir. Just ahead of the fire front, heat breaks the oil down (by cracking and 

distillation). The cracking provides a partial upgrading of the bitumen recovered from the 

production wells. Lighter fractions of the bitumen vaporize and move toward cooler portions of 

the formation and exchange their heat with it, displacing some of the bitumen and increasing 

recovery efficiency. As the vapors move into cooler parts of the deposit, they condense and can 

be pumped out of production wells. Condensation could cause a problem by plugging the 

deposit. Heavier fractions remain behind as coke that includes heavy hydrocarbons containing 

oxygen, sulfur, nitrogen, and trace metals. Coke may account for up to 20% of the oil and 

provides most of the combustion fuel. The burned region consists mostly of sand 

(Schumacher 1978; Speight 1990, 1997). 

The use of combustion or fire flooding to stimulate bitumen production may be attractive 

for deep reservoirs because little heat is lost. Conversely, heat loss limits the use of steam 

injection in deep reservoirs. The high pressures involved in injecting combustion air preclude the 

use of combustion in shallow deposits. Another advantage of combustion over steam-based 

processes is the reduction of carbon dioxide (CO2) emissions from aboveground steam 

generators. However, CO2 from in situ combustion will be present in the produced gases 

recovered from production wells. Combustion has been effective in the recovery of heavy oils 

from thick reservoirs where the dip and continuity of the formation may assist gravity flow of 

bitumen or where wells can be closely spaced (Schumacher 1978; Speight 1990, 1997; 

Isaacs 1998). 

With the exception of the fuel needed to initiate combustion, there is no need to buy fuel 

to produce heat in the well (Schumacher 1978). However, any bitumen in the combusted coke 

cannot be recovered as product. Some of the advantage also is lost by the need to compress the 

injection air and the increased loss of heat to the formation at the elevated temperatures 

associated with burning. This loss can be reduced by injecting water at the same time or 

alternatively with the combustion air. 

Far less experience and information are available for in situ combustion than for steam 

processes, and process control is more difficult. Some considerations include: 

• Sufficient bitumen must be consumed to raise the temperature enough to 

mobilize the remaining bitumen, 

• Sufficient oxygen must be supplied to support and control combustion, 

• Overburden and underburden must provide effective seals for injected air and 

mobilized bitumen and serve as effective barriers to heat loss (Speight 1990). 

The combustion in in situ processes can be categorized as forward, reverse, or a 

combination of forward and reverse. In forward combustion (Figure B-3), the fire front is ignited 

at the injection well and moves toward the production well. As the bitumen moves toward the 

production well, it moves from the zone of combustion into a colder, unheated portion of the 
Final OSTS PEIS B-25 

formation. Because the bitumen is generally 

less mobile when it is colder, the forward 

combustion process has an upper limit on the 

viscosity of liquids that can be recovered. Up 

to 80% of the combustion heat remains behind 

the advancing fire front and is lost. However, 

because the air passes through the hot 

formation behind the flame front prior to 

reaching the combustion zone, combustion 

efficiencies are enhanced and more unburned 

hydrocarbons are recovered. Heavier 

components are left on the sand grains and 

consumed as fuel. Deposits with relatively 

high permeability and relatively low bitumen 

saturation (4565 vol%) are most amenable to 

this process. Forward combustion has been 

used with some success in the Orinoco 

deposits in Venezuela and in Kentucky sands 

(Schumacher 1978; Speight 1990, 1997; 

Meyer 1995). 

In reverse combustion (Figure B-3), the 

fire front is ignited at the production well and 

moves toward the injection well. Combustion 

air introduced at the injection well helps drive 

the volatile organics toward the production 

well. Because combustion products and 

product move into the hot zone behind the fire 

front, there should be less of a viscosity 

limitation. Residual coke would remain on the 

sand grains. This process is most applicable to 

deposits with lower permeability because 

movement of mobilized fluids would be into a hot zone with a consequent reduction in plugging 

(Speight 1990, 1997; Meyer 1995). 

In a combination of reverse and forward combustion, the initial phase uses a 

low-temperature reverse combustion to increase the permeability of the formation and increase 

the mobility of the bitumen. The subsequent forward combustion phase supplies the heat and 

energy to distill and mobilize the bitumen and move it to the production wells (Marchant and 

Westhoff 1985). 

Modifications of the in situ combustion process include fracturing by either pneumatic or 

hydraulic means to increase permeability of reservoirs so that combustion air can flow more 

freely. In another modification, oxygen or oxygen-enriched air rather than atmospheric air is 

injected under certain conditions. Cost savings accrue because of the reduced compression costs 

and the reduction in the gas-to-oil ratio in the recovered product. 

FIGURE B-3 Simplified Diagrams of 

Forward and Reverse Combustion Processes 

(Speight 1990) (Copyright 1990 from Fuel 

Science and Technology Handbook edited by 

James G. Speight. Reproduced by the permission 

of Routledge/Taylor & Francis Group, LLC.) 
Final OSTS PEIS B-26 

In the wet combustion modification, water and air are injected alternatively into the 

formation. The water flows through the fire, vaporizes, and then condenses, thereby heating the 

unburned deposit and reducing the viscosity of the bitumen. Wet combustion can move heavier 

oils and operate at lower pressures than dry combustion and may burn less bitumen, resulting in 

a reduced need for injected air (Schumacher 1978; Speight 1990, 1997). 

A combination of forward combustion and waterflooding has also been tried at 

Athabasca. It involved a heating phase followed by a production or blowdown phase followed by 

a displacement phase using a fire-water flood, over a period of 18 months (8 months heating, 

4 months blowdown, and 6 months displacement) (Speight 1990). 

 Table B-4 provides available data describing potential impact-producing factors that 

could be associated with in situ combustion processes. The air emissions data were derived from 

information published by Aerocomp, Inc. (1984), for a proposed 20,000-bbl/day-capacity project 

in the Circle Cliffs STSA (based upon parameters for an oil shale processing facility) and include 

emissions from upgrading processes. The nonair emissions data were derived from information 

published by Daniels et al. (1981) on the basis of the proposed 20,000-bbl/day-capacity plant 

designed for recovery of oil from a diatomaceous earth tar sands deposit near McKittrick, 

California. The table presents the original numbers estimated for each project and extrapolated 

numbers for larger operations. It should be noted that the numbers were extrapolated linearly 

because no information is available to justify doing otherwise; linear extrapolations are likely to 

result in conservative overestimates of potential impacts.

B.4.2.2 Noncombustion Processes 

 The noncombustion processes discussed in this subsection involve the injection of liquid 

or gas into the reservoir to effect the mobilization and recovery of the bitumen. For steam 

injection processes, the cost of generating steam is the most significant expense. Also, the 

feedwater must be of relatively high quality (Speight 1990), which could prove to be an obstacle 

to using steam injection processes in the arid and semiarid regions of Utah. 

Steam drive (steam flood) processes (Figure B-4) involve the injection of steam from 

surface boilers into at least one injection well with the recovery of the mobilized bitumen and 

condensed steam from at least one production well. The wells could be placed either in parallel 

rows or in a ring around a central well. Heat released by condensing steam reduces the viscosity 

of the bitumen, which is forced to the production well by the flow of steam and hot water. In situ 

distillation (upgrading) and improved gas drive are side benefits of this steam drive. This process 

may be used following cyclic steam injection. The permeability of the reservoir must be 

sufficient to permit the injection of steam at rates high enough to raise the temperature to the 

point at which the bitumen will flow. Permeability will decrease as the process proceeds and 

water and steam saturate the reservoir; as permeability decreases, the amount of injected steam 

required to produce a unit of oil increases sharply. Establishing communication between the 

injection and production wells presents a problem for this technique, but it has been successfully 

utilized by Shell Canada in the Peace River deposit in Alberta. Bitumen-to-water ratios could be 

as high as 1 to 10 but are generally around 1 to 5. The use of steam has been demonstrated with 
Final OSTS PEIS B-27 

TABLE B-4 Potential Impact-Producing Factors Associated with 

In Situ Combustion Processes 

Production Capacity (bbl/day syncrude)b,c

Impact-Producing Factora 20,000 25,000 50,000 100,000 

 

Total land disturbance (acres) 4,000 5,000 10,000 20,000 

Produced wastewater (bbl/day)d 40,000 50,000 100,000 200,000 

Air emissions (tons/yr) 

 Stack emissionse 

 TSP 438 548 1,095 2,190 

 SOx 4,960 6,200 12,400 24,800 

 NOx 2,052 2,565 5,130 10,260 

 CO 60 75 150 300 

 VOC 110 138 275 550 

 Fugitive emissionsf

 

 TSP 409 511 1,022 2,045 

 SOx 4 5 10 20 

 NOx 7 9 18 35 

 CO 48 60 120 240 

 VOC 2 3 5 10 

a CO = carbon monoxide; NOx = nitrogen oxides; SOx = sulfur oxides; 

TSP = total suspended particulates (includes all particulate matter up to 

about 100 m in diameter); VOC = volatile organic compound. 

b The air emissions data were derived from information published by 

Aerocomp, Inc. (1984), for a proposed 20,000-bbl/day-capacity project in 

the Circle Cliffs STSA (based upon parameters for an oil shale processing 

facility). Nonair emissions data were derived from Daniels et al. (1981) 

for a proposed 20,000-bbl/day-capacity plant designed for recovery of oil 

from a diatomaceous earth tar sands deposit near McKittrick, California. 

Numbers for larger production capacities were extrapolated linearly, 

which is likely to result in conservative overestimates of potential 

impacts. 

c bbl = barrel; 1 bbl syncrude = 42 gal, 1 bbl water = 55 gal. 

d Based upon an estimated generation rate of 1 to 2 bbl of wastewater per 

bbl of syncrude produced. 

e Modeled on the basis of the following: stack height = 76 m (249.3 ft), 

stack diameter = 3 m (9.8 ft), velocity = 10 m/s (32.8 ft/s), and 

temperature = 311K (100.1F). 

f

 Modeled on the basis of the following: height above ground surface = 3 m 

(9.8 ft) and area = 2,000 m2 (2,392 yd2). 
Final OSTS PEIS B-28 

FIGURE B-4 Simplified Steam Drive Process (Speight 1990) 

(Copyright 1990 from Fuel Science and Technology Handbook

edited by James G. Speight. Reproduced with the permission 

of Routledge/Taylor & Francis Group, LLC.) 

some success in Utah sands. The large amount of energy required to generate, compress, and 

pump steam presents an important technical requirement for steam drive (Spencer et al. 1969; 

Schumacher 1978; National Academy of Sciences 1980; BLM 1984; Speight 1995; Isaacs 1998). 

 The alternative cyclical steam stimulation, also known as “huff and puff,” involves 

injecting high-temperature (about 350oC [660oF]) steam from surface boilers at higher than 

fracturing pressure into the deposit over a period ranging from days to months, followed by a 

“soak” period of variable length, followed by production for up to a year. Initial production relies 

on the pressure created by injection followed by pumping (Speight 1990, 1997; Oils Sands 

Discovery Center 2006b). Cyclic steam has more effect on increasing the rate of production than 

on increasing the ultimate recovery (Schumacher 1978). 

Another steam injection approach, SAGD, is most suitable for reservoirs with immobile 

bitumen. It involves drilling two horizontal wells at the bottom of a thick unconsolidated 

sandstone reservoir. Steam is injected continuously through the upper well at pressures much 

lower than the fracture pressure. Heat and steam rise and condensed water and mobilized oil flow 

down by gravity into the lower or production well. As the process proceeds, a “steam chamber” 

develops laterally and upwards. SAGD seems to be insensitive to horizontal barriers to flow such 

as shale intrusions that fracture from thermal shock. Recovery ratios of 50 to 75% may be 

achievable; however, the initial oil recovery rate is low. 

The uses of hot fluids, steam, water, and gas for injection are similar. Hot water is more 

efficient than hot gas but less efficient than steam mainly because of the relative heat-carrying 
Final OSTS PEIS B-29 

capacities of the fluids. Nonsteam techniques have been applied to bitumen recovery in 

conjunction with other techniques (Spencer et al. 1969; BLM 1984). 

Solvent extraction involves the injection of solvent into the formation to dissolve the 

bitumen and carry it to a production well for pumping to the surface. At the surface, the bitumen 

is separated from the solvent and the solvent is recovered. When applied in situ, large losses of 

solvent and bitumen have always presented major problems that must be controlled. In addition, 

the only useful solvents, at least for Athabasca bitumen, are relatively expensive naphthenic and 

aromatic substances. Solvent extraction has not generally been economical compared with steam 

injection. 

Two aqueous emulsifying systems have been developed for use in the Athabasca sands 

(Spencer et al. 1969). One employs an alkaline surfactant solution, the other a dilute sodium 

hydroxide solution. Field tests showed that bitumen was completely removed from the contacted 

portion of the reservoir but that the contacted portion was very limited because of the low 

permeability of the reservoir. 

Several variations of steam heating and emulsification have been tried (Speight 1990). 

These include the use of steam with various solvents to reduce the viscosity of the oil through a 

combination of heating and dissolution. A technique involving fracturing by using dilute aqueous 

alkaline solutions followed by emulsification with hot caustic and production of an emulsion by 

using steam injection at the production wellhead was used in the Athabasca sands. It was 

estimated that more oil had leaked away from the recovery zone than had been recovered. 

Many additional processes are in the concept or early development phase or for which 

patents have been sought or issued. Some of those that potentially could be applied within the 

20-year planning horizon of this PEIS include the following: 

• Top-Down Combustion, in which combustion would be initiated and 

maintained by the injection of air at the top of the reservoir with the heated, 

mobilized oil draining into horizontal wells by gravity (Isaacs 1998). 

• Cyclic Steam Combined with Steam-Assisted Gravity Drainage Gravity

(Isaacs 1998). 

• Warm Vapor Extraction, which involves the injection of vaporized solvents to 

create a vapor chamber through which mobilized hydrocarbons flow because 

of gravity drainage. 

• Toe-to-Heel Air Injection, which combines a vertical air injection well with a 

horizontal production well. A combustion front is created and combusts part 

of the hydrocarbon in the reservoir. The heat generated reduces the viscosity 

of the hydrocarbon that is pulled to the horizontal production well by gravity. 

The combustion front moves from the “toe,” the underground end of the 

horizontal production well, to the “heel,” where the production well 

transitions from horizontal to vertical. 
Final OSTS PEIS B-30 

• Pressure Pulse Flow Enhancement Technology, which is based on the recent 

discovery that large-amplitude, low-frequency energy waves can enhance 

flow rates in porous media (Dusseault 2001). 

• Nuclear Energy, which has been proposed as an energy source for producing a 

combination of steam and electricity for tar sands recovery while reducing 

CO2 emissions (Donnelly and Pendergast 1999; Dunbar and Sloan 2003). 

Table B-5 provides available data describing potential impact-producing factors that 

could be associated with in situ steam injection processes. The air emissions data were derived 

from information published by Aerocomp, Inc. (1984), for a proposed 50,000-bbl/day-capacity 

project in the P.R. Spring STSA and a proposed 20,000-bbl/day-capacity project in the San 

Rafael Swell STSA and include emissions from upgrading processes. The nonair emissions data 

were derived from information published by Daniels et al. (1981) on the basis of the proposed 

20,000-bbl/day-capacity plant designed for recovery of oil from a diatomaceous earth tar sands 

deposit near McKittrick, California. The table presents the original numbers estimated for each 

project and extrapolated numbers for larger operations. It should be noted that the numbers were 

extrapolated linearly because no information is available to justify doing otherwise; linear 

extrapolations are likely to result in conservative overestimates of potential impacts. 

B.4.3 Modified In Situ Methods 

The use of explosives to disaggregate the tar sands and increase permeability is similar to 

the process used for oil shale (see Appendix A) and is not discussed further here. 

As noted above, methods for recovering bitumen from formations located at depths 

between about 45 and 150 m (150 and 500 ft) are limited. In comparison with surface mining, 

subsurface mining reduces the need for raw tar sands handling and storage; the need for handling 

and disposal of spent sand (tailings); and the need for reclamation of a mined out pit, room, or 

shaft. One potential extraction method applicable at these depths involves combining in situ and 

subsurface mining techniques. This process, referred to as oil mining, has been used in the past 

in France, Germany, and Russia and entails underground mining of some of the tar sands deposit 

so that in situ methods can be used on the remaining deposit. Most commonly, a vertical shaft is 

sunk and horizontal drifts are excavated from the bottom of the shaft. Horizontal injection and 

production wells are drilled from the drifts. The drifts can be above or below the tar sands 

formation and are typically used to permit low-pressure steam to be injected into the formation to 

heat the sands so that the bitumen will flow (Meyer 1995; Isaacs 1998). 

B.5 PROCESSING RECOVERED BITUMEN 

The choice of recovery method affects which processing operations are used. In mining 

operations, the mined bitumen must be processed to recover or separate it from the inorganic 

matrix (largely sand, silt, and clay) in which it occurs. Nonmining extraction produces bitumen 

mixed with water, steam, other gases, or solvent from which it must be separated. If combustion 
Final OSTS PEIS B-31 

TABLE B-5 Potential Impact-Producing Factors 

Associated with In Situ Steam Injection Processes 

Production Capacity 

(bbl/day syncrude)b,c

Impact-Producing Factora 20,000 50,000 100,000 

 

Total land disturbance (acres) 4,000 10,000 20,000 

Water use (bbl/day)d 100,000 250,000 500,000 

Air emissions (tons/yr) 

 Stack emissionse 

 TSP 358 1,155 2,310 

 SOx 6,758 16,896 33,792 

 NOx 5,332 13,332 26,664 

 CO 712 1,782 3,564 

 VOC 356 889 1,778 

 Fugitive emissionsf

 

 TSP 615 895 1,790 

 SOx 0 1 2 

 NOx 1 2 4 

 CO 4 11 22 

 VOC 0.4 1 2 

a CO = carbon monoxide; NOx = nitrogen oxides; SOx = sulfur 

oxides; TSP = total suspended particulates (includes all 

particulate matter up to about 100 m in diameter); 

VOC = volatile organic compound. 

b The air emissions data were derived from information 

published by Aerocomp, Inc. (1984), for a proposed 

50,000-bbl/day-capacity project in the P.R. Spring STSA and 

a proposed 20,000-bbl/day-capacity project in the San Rafael 

Swell STSA. Nonair emissions data were derived from 

Daniels et al. (1981) for a proposed 20,000-bbl/day-capacity 

plant designed for recovery of oil from a diatomaceous earth 

tar sands deposit near McKittrick, California. Numbers for 

larger production capacities were extrapolated linearly, 

which is likely to result in conservative overestimates of 

potential impacts. 

c bbl = barrel; 1 bbl syncrude = 42 gal, 1 bbl water = 55 gal. 

d Based upon an estimated use rate of 5 bbl of water per bbl of 

syncrude produced. 

e Modeled on the basis of the following: for the 20,000-bbl/day 

facility, stack height = 76 m (249.3 ft); stack diameter = 5 m 

(16.4 ft); velocity = 12 m/s (39.4 ft/s); and temperature = 

493K (427.7F). Modeled on the basis of the following: for 

the 50,000-bbl/day facility, stack height = 76 m (249.3 ft); 

stack diameter = 7 m (23 ft); velocity = 12 m/s (39.4 ft/s); 

and temperature = 473 K (391.7F). 

f

 Modeled on the basis of the following: height above ground 

surface = 3 m (9.8 ft) and area = 2,000 m2 (2,392 yd2). 
Final OSTS PEIS B-32 

recovery is used, the viscosity of the recovered 

bitumen may need to be reduced prior to 

further processing. If steam, water, or gas 

injection is used, the injection fluid would 

need to be separated from the bitumen. In all 

cases, the viscosity of the bitumen might need 

to be changed prior to further processing and 

upgrading (BLM 1984). Depending on the 

recovery method, mining operations may also 

need to perform similar separations. 

B.5.1 Hot Water Process 

The hot water process has been applied 

with commercial success to mined water-wet 

Athabasca sands (see Figure B-5). As of 1997, 

it was the only process to have been applied 

with commercial success to mined tar sands in North America (Speight 1997). There are three 

main steps: conditioning, separation, and scavenging. 

 There are two methods of conditioning. In the first, mined tar sands are pumped with 

water and caustic into a conditioning drum at 180 to 220F to reduce particle size and digest the 

bitumen. The resulting slurry is screened to remove undigested material, and lumps are sent to a 

separation cell. In the newer hydrotransport method, the tar sands are crushed at the mine site 

and moved by pipeline in a water slurry to the extraction plant (Marchant and Westhoff 1985; 

Speight 1997; Oil Sands Discovery Center 2006b). 

The separation cell operates like a settling vessel. Sand settles downward to be removed, 

as tailings and bitumen float to the top where they are skimmed off. Most of the middlings, an 

emulsion for bitumen and water, are sent to scavenger cells for additional bitumen removal by 

froth flotation (Marchant and Westhoff 1985; Speight 1997). 

Experiments have been conducted to develop a hot water process for the oil-wet tar sands 

deposits in Utah (Speight 1997; Marchant and Westhoff 1985). The absence of a sheath of water 

around the tar sands particles and the strong bonding directly between the sand and the bitumen 

suggest that more energy would be required to separate sand and bitumen in the Utah tar sands 

than would be required in the Athabasca tar sands. After size reduction, digestion is 

accomplished using a high shear energy digester stirred at about 750 rpm at 200°F. Next, 

bitumen is separated by modified froth flotation. Middlings are screened and recycled 

(Oblad et al. 1987). This process has been developed to the pilot plant stage (Figure B-5), 

processing 125 tons/day of tar sands to produce 50 to 100 bbl/day of oil (Speight 1990). 

Disposal of tailings presents a problem for hot water recovery processes (Speight 1997). 

The volume of material expands during processing. A ton of in situ tar sands has a volume of 

about 16 ft3 and produces about 22 ft3 of tailings, a volume increase of almost 40%. The tailings 

FIGURE B-5 Simplified Diagram of Hot Water 

Recovery Process (Marchant and Westhoff 1985)
Final OSTS PEIS B-33 

stream contains about 49 to 50 wt% sand, about 1 wt% bitumen, and about 50 wt% water 

(Speight 1990). Regulations preclude dumping these tailings in streams or rivers or in areas from 

which runoff may enter rivers or contaminate groundwater. Reclamation of the tailings must also 

be accomplished upon site closure. 

In some operations, recovery of bitumen from the middlings in scavenger cells may be 

economical, the goal being an additional 2 to 4% bitumen recovery. This process generally 

involves injecting air in a froth flotation process. Froth containing bitumen rises to the surface of 

the cell and is skimmed off. 

The froths from the separation vessel and the scavenger cells are combined and sent for 

further processing. The froth stream is usually diluted with naphtha and centrifuged. At this 

stage, the bitumen contains 1 to 2 wt% minerals and 5 to 15 wt% water and is ready for 

upgrading. 

B.5.2 Cold Water Process 

Operations in the Athabasca tar sands have changed from hot water processing to cold 

water processing, which uses less energy. This change was made possible by using slurry 

pipelines rather than belt conveyors to transport ore from the mine to the extraction facility. 

Mined sand is crushed at the mine site, mixed with warm water to form a slurry, and moved by 

pipeline to the extraction plant. Partial separation of the bitumen from the sand occurs in the 

pipeline (Singh et al. 2005; Oil Sands Discovery Center 2006b). 

Experiments with cold water extraction of Utah tar sands showed a removal of more than 

60% of the sand with easily accomplished water removal. Calculations indicated that for 90% 

recovery of the bitumen, hot water processing would require at least 45 kWh/ton, while cold 

water processing would require only 13 kWh/ton (Oblad et al. 1987). 

Bench-scale cold water processes have also been developed. The sand reduction process 

uses cold water and no solvent to provide a feed for a fluid coking upgrading process. Tar sands 

are mixed with water in a screw conveyor and discharged to a screen of appropriate mesh in a 

water-filled settling vessel. Bitumen agglomerates on the screen and is removed while the sand 

passes through and is removed as waste. 

 In the spherical agglomeration process, water is added to the tar sands and the mixture is 

sent to a ball mill. The bitumen agglomerates to particles with at least 75 wt% bitumen 

(Speight 1990, 1997). 

B.5.3 Processes Involving Solvents 

Solvent extraction without water has been attempted. It generally uses a low boiling point 

hydrocarbon (such as heptane, cyclohexane, or ethanol) and involves four main steps. Fresh tar 

sands are mixed with recycled solvent containing some bitumen, water, and minerals. Next, a 
Final OSTS PEIS B-34 

three-stage countercurrent wash is used with settling and draining of about 30 minutes after each 

stage forming a bed of sand through which the bitumen containing solvent is drained. The last 

two steps recover the solvent from the sand. Solvent extraction has been demonstrated for 

Athabasca, Utah, and Kentucky sands, but the cost of solvent losses has kept the process from 

going commercial (Speight 1997). 

Experiments have been carried out on various tar sands deposits, including those at the 

Asphalt Ridge and Sunnyside STSAs, by using kerosene to control the viscosity of the bitumen 

to improve bitumen recovery and tailings sedimentation. The temperatures involved have been 

lowered from near the boiling point of water 100C (212F) to around 50 to 55C (120130F). 

More than 92% of the bitumen in the concentrate was recovered (Oblad et al. 1987). 

The cold water bitumen separation process using a combination of cold water and a 

solvent has been used in a small-scale pilot plant (Speight 1997). The tar sands are first mixed 

with water, reagents, and a diluent, which may be a petroleum fraction such as kerosene. The 

solution is maintained in an alkaline condition. Then sand is removed by settling in a clarifier 

from which the water and oil overflow is sent to thickeners to concentrate the oil. Clay in the 

feed emulsifies and carries off some of the bitumen as waste from the thickeners. 

Table B-6 provides available data describing potential impact-producing factors that 

could be associated with solvent extraction processes. The air emissions data were derived from 

information published by Aerocomp, Inc. (1984), for a proposed 32,500-bbl/day-capacity project 

in the Sunnyside STSA and include emissions from upgrading processes. The nonair emissions 

data were derived from information published by Daniels et al. (1981) on the basis of the 

proposed 20,000-bbl/day-capacity plant designed for recovery of oil from a diatomaceous earth 

tar sands deposit near McKittrick, California. The table presents the original numbers estimated 

for each project and extrapolated numbers for larger or smaller operations. It should be noted that 

the numbers were extrapolated linearly because no information is available to justify doing 

otherwise; linear extrapolations are likely to result in conservative overestimates of potential 

impacts. 

B.5.4 Thermal Recovery Processes 

Various schemes have been proposed as alternatives to the hot water process to remove 

bitumen from mined tar sands by applying heat. Direct coking or thermal recovery processes 

appeared promising but the success of hydrotransport in making cold water extraction 

commercially successful in Athabasca has helped reduce the attractiveness of thermal recovery, 

which can require consumption of a substantial amount of heat (Marchant and Westhoff 1985). 

In most processes, the tar sands are pyrolyzed (heated in an inert or nonoxidizing 

atmosphere) by heating at 900F to effect chemical changes, including 

• Volatilization of low molecular weight components, 

• Cracking of some heavier components, and 
Final OSTS PEIS B-35 

TABLE B-6 Potential Impact-Producing Factors Associated with a 

Solvent Extraction Facility 

Production Capacity (bbl/day syncrude)b,c

Impact-Producing Factora 20,000 32,500 50,000 100,000 

 

Total land disturbance (acres) 2,600 4,225 6,500 13,000 

Water use (bbl/day)c,d 106,930 173,760 267,330 534,650 

Noise (dBA at 500 ft) 7388 –e – – 

Air emissions (tons/yr)e,f 

 Extraction plante 

 TSP 422 686 1,055 2,110 

 SOx 632 1,027 1,580 3,161 

 NOx 4,990 8,109 12,475 24,950 

 CO 239 389 598 1,196 

 VOC 118 193 296 592 

 Upgrading plantg 

 TSP 139 225 346 693 

 SOx 94 153 235 470 

 NOx 4,522 7,348 11,305 22,610 

 CO 217 352 542 1,084 

 VOC 107 174 268 537 

 Spent tar sandsh 

 TSP 825 1,340 2,062 4,123 

 SOx 46 75 115 231 

 NOx 750 1,218 1,874 3,748 

 CO 129 209 322 643 

 VOC 39 63 97 194 

a CO = carbon monoxide; NOx = nitrogen oxides; SOx = sulfur oxides; 

TSP = total suspended particulates (includes all particulate matter up to 

about 100 m in diameter); VOC = volatile organic compound. 

b The air emissions data were derived from information published by 

Aerocomp, Inc. (1984), for a proposed 32,500-bbl/day-capacity project in 

the Sunnyside STSA. Nonair emissions data were derived from 

Daniels et al. (1981) for a proposed 20,000-bbl/day-capacity plant 

designed for recovery of oil from a diatomaceous earth tar sands deposit 

near McKittrick, California. Numbers for larger production capacities 

were extrapolated linearly, which is likely to result in conservative 

overestimates of potential impacts. 

c bbl = barrel; 1 bbl syncrude = 42 gal, 1 bbl water = 55 gal. 

d Approximately 22% of the process water would need to be fresh water 

(Daniels et al. 1981). 

e A dash indicates noise level not calculated. 

f

 Modeled on the basis of the following: height above ground 

surface = 3 m (9.8 ft) and area = 2,000 m2 (2,392 yd2). 

Footnotes continued on next page.
Final OSTS PEIS B-36 

TABLE B-6 (Cont.) 

g Modeled on the basis of the following: stack height = 33 m (108.3 ft), 

stack diameter = 5 m (16.4 ft), velocity = 12 m/s (39.4 ft/s), and 

temperature = 393 K (247.7F). Values derived from the original source 

on basis of relative emission rates provided (see Table 5-5, Aerocomp, 

Inc. 1984). 

h Modeled on the basis of the following: stack height = 55 m (180.4 ft), 

stack diameter = 6 m (19.7 ft), velocity = 12 m/s (39.4 ft/s), and 

temperature = 393K (247.7F). Values derived from the original source on 

the basis of relative emission rates provided (see Table 5-5, Aerocomp, 

Inc. 1984). 

• Conversion of part of the bitumen to coke. 

The volatile materials exit the reaction vessel, are cooled, and separated into gases and 

condensed liquids while the coke remains behind adhering to the sand, which is transferred to a 

combustion vessel for burning to provide heat for the process. In general, the oil obtained by a 

thermal process would require upgrading before it is acceptable as a refinery grade synthetic 

crude. The sulfur- and nitrogen-containing compounds must be eliminated, the nitrogen and/or 

sulfur converted to compounds that are subsequently removed (typically ammonia and hydrogen 

sulfide, respectively) and further processed into saleable commodities or disposed of as waste, 

the average molecular weight lowered, and the carbon-to-hydrogen ratio reduced (Marchant and 

Westhoff 1985; Speight 1990). 

About a dozen other thermal processes have been described in the literature. Experiments 

utilizing fluidized bed pyrolysis have been conducted on Utah tar sands at the University of Utah 

(Marchant and Westhoff 1985; Speight 1997). 

Table B-7 provides available data describing potential impact-producing factors that 

could be associated with a surface retort facility. These data were derived from information 

published by Daniels et al. (1981) on the basis of a proposed 20,000-bbl/day-capacity plant 

designed for the recovery of oil from a diatomaceous earth tar sands deposit near McKittrick, 

California. The proposed retort facility was a Lurgi-Ruhrgas retort. The volatile emissions data 

presented in this table are likely to exceed those that would be expected from one of the Utah tar 

sands deposits because the bitumen is more volatile at McKittrick. In addition, the particulate 

emissions are likely to exceed emissions from a Utah deposit because the diatomaceous earth tar 

sands at McKittrick are less tightly bound than the sandstone deposits in Utah. The table presents 

the original numbers estimated for the McKittrick project and extrapolated numbers for larger 

operations. It should be noted that the numbers were extrapolated linearly because no 

information is available to justify doing otherwise; linear extrapolations are likely to result in 

conservative overestimates of potential impacts. 
Final OSTS PEIS B-37 

TABLE B-7 Potential Impact-Producing Factors Associated with a 

Surface Retort Facility 

Production Capacity (bbl/day syncrude)b,c

Impact-Producing Factora 20,000 25,000 50,000 100,000 

 

Total land disturbance (acres) 2,600 3,250 6,500 13,000 

Water use (bbl/day)d 11,950 14,940 29,880 59,760 

Noise (dBA at 500 ft) 73–88 –e – – 

Air emissions (tons/yr) 

 Retortf

 

 TSP 954 1,192 2,384 4,768 

 SOx 1,002 1,253 2,506 5,011 

 NOx 393 492 983 1,966 

 Fuel burning equipmentg 

 TSP 21 26 52 104 

 SOx 24 30 61 122 

 NOx 104 131 261 522 

 CO 17 22 44 87 

 THC 3 4 9 17 

 Storage tanksh 

 THC 28 35 70 140 

 Valves, pumps, compressorsi

 

 THC 3 4 9 17 

a CO = carbon monoxide; NOx = nitrogen oxides; SOx = sulfur oxides; 

THC = total hydrocarbons (includes methane and photochemically 

nonreactive compounds); TSP = total suspended particulates (includes all 

particulate matter up to about 100 m in diameter). 

b Data derived from Daniels et al. (1981) for a proposed 

20,000-bbl/day-capacity plant designed for recovery of oil from a 

diatomaceous earth tar sands deposit near McKittrick, California. Numbers 

for larger production capacities were extrapolated linearly, which is likely 

to result in conservative overestimates of potential impacts. 

c bbl = barrel; 1 bbl syncrude = 42 gal, 1 bbl water = 55 gal. 

d Approximately 100% of the process water would need to be fresh water 

(Daniels et al. 1981). 

e A dash indicates noise level not calculated. 

f

 These data are based upon a Lurgi-Ruhrgas retort operating with a 97% 

efficient lime injection and scrubbing system to control SOx emissions and 

a 99.5% efficient electrostatic precipitator to control TSP emissions. These 

data were modeled on the basis of the following: stack height = 76 m 

(249.3 ft), volume = 193.4 m3/s (2,081.7 ft3/s), and temperature = 88C 

(190.4F). The particulate emissions are likely to exceed emissions from a 

Utah deposit because the diatomaceous earth tar sands at McKittrick are 

less tightly bound than the sandstone deposits in Utah. 

Footnotes continued on next page. 
Final OSTS PEIS B-38 

TABLE B-7 (Cont.)

g The fuel burning equipment includes a distillation furnace, hydrogen plant, 

and hydrogenation unit and includes a 50% efficient ammonia injection 

system to control NOx emissions. These data were modeled on the basis of 

the following: stack height = 76 m (249.3 ft), volume = 22 m3/s 

(236.8 ft3/s), and temperature = 88C (500F). The volatile emissions data 

presented in this table are likely to exceed those that would be expected 

from one of the Utah tar sands deposits because the bitumen is more 

volatile at McKittrick. In addition, the particulate emissions are likely to 

exceed emissions from a Utah deposit because the diatomaceous earth tar 

sands at McKittrick are less tightly bound than the sandstone deposits in 

Utah. 

h Equipped with a double-sealed floating roof. 

i

 Assumes equipment is subjected to a strict maintenance program.

B.6 UPGRADING 

Upgrading recovers the light components from the recovered bitumen and changes the 

heavy components into synthetic crude oil. By-products, which can be used directly or as raw 

materials for other processes, are also produced. Bitumen has a higher carbon-to-hydrogen ratio 

than crude oil. Some upgrading processes remove carbon (e.g., a coking operation) and others 

add hydrogen (e.g., a hydrogenation that converts unsaturated hydrocarbons in the saturated 

analogs) to reduce this ratio. Upgrading also decreases the specific gravity (density) of the 

synthetic crude oil to a level suitable for a refinery feedstock. Although there are variations 

between different production operations, four main processes are used to upgrade bitumen: 

coking (thermal conversion), catalytic conversion, distillation (fractionation), and hydrotreating 

(Speight 1990, 1997; Meyer 1995; Oil Sands Discovery Center 2006b). 

The recovery process has a determining influence on the ancillary processes associated 

with upgrading. If combustion recovery were used, the viscosity of the bitumen might need to be 

reduced prior to upgrading. If a steam, hot water, or hot gas injection were used, the injected 

fluids would probably need to be separated from the recovered bitumen/fluid mixture. In 

addition, the viscosity of the bitumen might need to be reduced. Similarly, if solvent recovery 

were used, the solvent and bitumen would need to be separated and the viscosity of the bitumen 

might need to be reduced (BLM 1984). 

 Limited data are available to describe the potential impact-producing factors that could be 

associated strictly with upgrading processes; usually, the data are provided for an entire plant, 

including extraction and upgrading facilities. Table B-8 provides data describing potential 

impact-producing factors that could be associated with the upgrading facilities used for 

processing oil shalespecifically, The Oil Shale Corporation (TOSCO) II aboveground retort 

facility. Given that kerogen oil (raw shale oil) derived from oil shale requires more extensive 

upgrading than bitumen recovered from tar sands, these data are likely to result in conservative 

overestimates of potential impacts. These data were derived from information published by the 
Final OSTS PEIS B-39 

TABLE B-8 Potential Impact-Producing Factors Associated 

with Upgrading Facilities 

Production Capacity (bbl/day syncrude)b,c

Impact-Producing 

Factora 25,000 47,000 50,000 100,000 

 

Water use (bbl/day)d 481,910 906,000 963,830 1,927,660 

Air emissions (tons/yr) 

 Particulates 31 58 62 123 

 SOx

e 271 510 542 1,085 

 NOx 221 416 442 885 

 CO 27 51 54 108 

 Hydrocarbons 5 9 10 19 

a CO = carbon monoxide; NOx = nitrogen oxides; SOx = sulfur 

oxides. 

b Data derived from DOE (1983) for a proposed 47,000-bbl/daycapacity TOSCO II aboveground retort (indirect mode) for 

production of syncrude from oil shale. Numbers for larger and 

smaller production capacities were extrapolated linearly, which is 

likely to result in conservative overestimates of potential impacts. 

c bbl = barrel; 1 bbl syncrude = 42 gal, 1 bbl water = 55 gal. 

d Represents evaporative losses from the coker unit. 

e Includes emissions from tail gas incinerator. 

DOE (1983) on the basis of a 47,000-bbl/day syncrude facility, including hydrogenation and 

hydrotreating units. 

B.6.1 Coking (Thermal Conversion) 

The molecules in recovered bitumen must be reduced in average molecular weight. If 

heated to high temperatures, long, heavy hydrocarbon molecules break apart into shorter, lighter 

molecules. This process is called cracking and proceeds faster at higher temperatures 

(Meyer 1995; Oil Sands Discovery Center 2006c). There are two types of coking: delayed 

coking and fluid coking. Suncor uses delayed coking, and Syncrude uses fluid coking in its 

Athabasca operations. 

 Delayed coking is a batch process. Recovered bitumen is heated to 925F and pumped 

into one side of a double-sided coker where it cracks into vapor and coke. The vapors escape 

from the vessel for condensation and further processing, and the coke remains behind. In about 

12 hours, the first side is full of coke and the cracking operation shifts to the other side. The solid 

coke is cut out by use of a water drill (Oil Sands Discovery Center 2006b). 
Final OSTS PEIS B-40 

 Fluid coking is a continuous process. Bitumen is heated to 925F (500C) and blown into 

a vessel containing small spheres of coke suspended in an upward flow of steam. The large 

molecules in the bitumen are cracked, and the resulting smaller molecules are carried out of the 

top of the vessel as a vapor for condensation and further processing. The remaining coke 

agglomerates with the coke spheres, which eventually become large enough to settle to the 

bottom of the vessel from which they are removed. At the Syncrude operation, the process 

recovers about 86 bbl of synthetic crude for every 100 bbl of recovered bitumen. In another 

variation, the heated bitumen is sprayed into the entire height and circumference of the vessel 

and cracks into a gas that is removed from the top of the vessel and a fine coke powder that is 

removed from the bottom (Meyer 1995; Oil Sands Discovery Center 2006b). 

 Both fluid and delayed coking produce coke, distillate oils, and light gases. Upwards of 

75% of the bitumen is converted to liquids, with fluid coking giving 1 to 5% more than delayed 

coking. Most of the coke is used to produce heat for the upgrading operations. More is produced 

than is needed and is stockpiled for storage. Sulfur occurs throughout the distillates from both 

processes. Nitrogen occurs in all fractions but is concentrated in the higher boiling point 

fractions. Naphtha and gas oil require the addition of hydrogen to be suitable as refinery feeds 

(Speight 1997; Oil Sands Discovery Center 2006b). 

B.6.2 Catalytic Conversion 

Catalytic conversion is really a thermal conversion enhanced by using catalysts. Catalysts 

help chemical reactions occur but are not themselves chemically changed by the reactions. For a 

catalyst to be effective, the hydrocarbon molecules in the bitumen must contact the so-called 

active sites on the catalyst. When large hydrocarbon molecules contact the active sites, they 

crack into smaller molecules. The catalyst also impedes the progress of larger hydrocarbon 

molecules so that they can continue to crack into smaller pieces. In hydroprocessing, hydrogen is 

added to the process to improve the carbon-to-hydrogen ratio (Oil Sands Discovery 

Center 2006b). 

B.6.3 Distillation (Fractionation) 

Distillation is a very common refinery process. The functioning of a distillation tower 

depends on the fact that different substances boil at different temperatures. The tower is 

essentially kept hotter at the bottom and cooler at the top. Vapors collected from the coker are 

introduced at the bottom and rise up through the tower. Heavier hydrocarbons with higher 

boiling points condense near the bottom of the tower. Lighter hydrocarbons with lower boiling 

points move upward and condense at different levels depending on their boiling points. The 

condensed liquids are removed from the tower (Oil Sands Discovery Center 2006b). 

An efficiency gain is realized in processing bitumen if the output of the coker is separated 

into several streams for additional processing. In particular, the naphtha component requires 

special processing. At Suncor, the coker distillate is distilled into three fractions: naphtha, 

kerosene, and gas oil. At Syncrude, the coker distillate is distilled into two fractions: naphtha and 
Final OSTS PEIS B-41 

mixed gas oil. The products of additional processing, including hydrotreating, are blended to 

produce synthetic crude oil (Speight 1997). 

B.6.4 Hydrotreating 

Hydrotreating is used on the gas oils, kerosene, and naphtha resulting from the upgrading 

of bitumen. It is one of the most commonly used chemical processes for adding hydrogen to 

organic molecules. In hydrotreating, the feedstock is mixed with excess hydrogen at high 

pressure and temperatures of 300 to 400C (570 to 750F) in the presence of catalysts. The 

process can also remove sulfur, nitrogen, and metals as well as undesirable organics from the 

feedstock. The addition of hydrogen also helps stabilize the produced synthetic crude so that its 

chemical composition does not change in transit between the syncrude plant and the refinery. In 

the production of synthetic crude oil, the gases from hydrotreating (all of which are typically 

flammable) are usually desulfurized and used as fuels on-site (Meyer 1995; Speight 1997; 

Oil Sands Discovery Center 2006b). 

B.6.5 Other Upgrading Processes 

Hydrocracking is an upgrading process that cracks the bitumen in the presence of 

hydrogen and produces higher liquid yields than coking (up to 104 bbl of synthetic fuel per 

100 bbl of raw bitumen) because of the uptake of hydrogen. Products from hydrocracking have 

lower contents of sulfur- and nitrogen-containing compounds than products from coking. Despite 

the need to consume hydrogen and operate at high pressures, hydrocracking has been chosen for 

use in two projects in Canada (Meyer 1995; Speight 1997). 

In partial coking, the froth from the hot water recovery process is distilled at atmospheric 

pressure, thereby removing water and minerals. 

Flexicoking uses a gasifier to gasify excess solid coke with a mixture of gas and air. The 

product is a low-heating-value gas that can be used on-site. This process produces a heavy pitch 

rather than coke as a by-product by using steam stripping in a delayed coking process. The yield 

of liquids is also increased. 

The Alberta Oil Sands Technology and Research Authority Taciuk Processor 

simultaneously extracts and upgrades the bitumen from oil sands to produce a distillate oil 

(Meyer 1995). Heat alone is used to separate bitumen from sand, crack it, and drive off the 

hydrocarbons. Much of the heat for the process is obtained from the separated sand, which 

contains residual coke. The sand-coke is burned, and the heated sand is used to preheat 

unprocessed oil sands and then discarded. The Taciuk process has several advantages over the 

combination recovery-upgrading procedure described above. These include increased product 

yield, a simplified process flow, reduction of bitumen losses to tailings, elimination of the need 

for tailings ponds, improvement in energy efficiency compared with the hot water extraction 

process, and elimination of requirements for chemical and other additives. 
Final OSTS PEIS B-42 

B.7 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

Aerocomp, Inc., 1984, Final Air Quality for the Combined Hydrocarbon EIS, Eastern and SouthCentral Utah ̧ prepared for U.S. Department of the Interior, Bureau of Land Management, 

Aerocomp Document 88TR01, Costa Mesa, Calif., March. 

Alberta Economic Development, 2006, Oil Sands Industry Update. Available at www.albertacanada.com/oandg/files/pdf/oilSandsUpdate_Dec2005.pdf. Accessed March 1, 2006. 

Beer, J.J., 2005, “Sequence Stratigraphy of Fluvial and Lacustrine Deposits in the Lower Part of 

the Chinle Formation, South Central Utah, United States: Paleoclimatic and Tectonic 

Implications,” Masters thesis, University of Minnesota. Available at http://www.d.umn.edu/ 

geology/research/thesis.html. Accessed Nov. 13, 2006. 

Blackett, R.E., 1996, Tar-Sand Resources of the Uinta Basin, Utah, A Catalogue of Deposits, 

Open-File Report 335, Utah Geological Survey. 

BLM (Bureau of Land Management), 1984, Utah Combined Hydrocarbon Leasing Regional 

Final Environmental Impact Statement, Volume 1, Regional Analyses, Utah State Office, Salt 

Lake City, Utah, June. 

Daniels, J.J., et al., 1981, Technology Assessment: Environmental, Health, and Safety Impacts 

Associated with Oil Recovery from U.S. Tar-Sand Deposits, UCRL-53210, Lawrence Livermore 

Laboratory, University of California, Livermore, Calif., Oct. 13. 

Donnelly, J.K., and D.R. Pendergast, 1999, Nuclear Energy in Industry: Application to Oil 

Production, presented at Climate Change and Energy Options Symposium, Canadian Nuclear 

Society, Ottawa, Canada, Nov. 1719. 

DOE (U.S. Department of Energy), 1983, Energy Technology Characterizations Handbook, 

Environmental Pollution and Control Factors, 3rd ed., DOE/EP-0093, Office of Environmental 

Analysis, Washington, D.C. 

Dunbar, R.B., and T.W. Sloan, 2003, Does Nuclear Energy Have a Role in the Development of 

Canada’s Oil Sands?, Paper 2003-096, presented at the Petroleum Society’s Canadian 

International Petroleum Conference 2003, Calgary, Alberta, Canada, June 1012, 2003. 

Dusseault, M.B., 2001, Comparing Venezuelan and Canadian Heavy Oil and Tar Sands, 

Paper 2001-061, presented at the Petroleum Society’s Canadian International Petroleum 

Conference 2001, Calgary, Alberta, Canada, June 1214, 2001. Available at http://www.energy. 

gov.ab.ca/docs/oilsands/pdfs/RPT_Chops_app3.pdf. Accessed March 14, 2006. 
Final OSTS PEIS B-43 

Glassett, J.M., and J.A. Glassett, 1976, The Production of Oil from Intermountain West Tar 

Sands Deposits, final report to the U.S. Bureau of Mines, Eyring Research Institute, Provo, Utah. 

Grosse, D.W., and L. McGowan, 1984, Tar Sands Leachate Study, EPA 600/2-84-113, 

U.S. Environmental Protection Agency, Industrial Environmental Research Laboratory, 

Cincinnati, Ohio, Feb. 

Han, S., and C.D. Chang, 1994, “Fuels, Synthetic, Liquid Fuels,” in Kirk-Othmer Encyclopedia 

of Chemical Technology. Available at www.mrw.interscience.wiley.com/kirk/articles/ 

liquihan.a01/pdf_fs.html. Accessed Feb. 16, 2006. 

Isaacs, E.E., 1998, “Recovery Methods for Heavy Oil and Bitumen in the 21st Century,” in 

Proceedings of the 7th Unitar International Conference on Heavy Crude and Tar Sands, Beijing, 

China, Oct. 27–30. 

Kohler, J., 2006, personal communication from Kohler (Bureau of Land Management, Utah 

State Office, Salt Lake City) to S.J. Thompson (Bureau of Land Management, Washington 

Office), Oct. 24. 

Lewin & Associates, 1983, Major Tar Sand and Heavy Oil Deposits of the United States, 

prepared for the Interstate Oil Compact Commission in cooperation with the U.S. Geological 

Survey and U.S. Department of Energy, July. 

Marchant, L.C., and J.D. Westhoff, 1985, In Situ Recovery of Oil from [sic] Utah Tar Sand: 

A Summary of Tar Sand Research at the Laramie Energy Technology Center, 

DOE/METC-86/2023, U.S. Department of Energy Research, Morgantown Energy Technology 

Center, Laramie Project Office, Laramie, Wyo., Oct. 

Meyer, R., 1995, “Bitumen,” in Encyclopedia of Energy Technology and the Environment, 

Vol. 1, A. Bisio and S. Boots (editors), John Wiley & Sons, New York, N.Y. 

National Academy of Sciences, 1980, “Appendix II: Mining and Processing of Oil Shale and Tar 

Sands,” in Surface Mining of Non-Coal Minerals, Washington, D.C. 

Nevtah Capital Management Corp., 2006, Corporate Update: Nevtah/Black Sands Complete 

First Production Plant. Available at http://www.nevtahoilsands.com/. Accessed August 17, 2006 

and July 26, 2012. 

Oblad, A.G., et al., 1987, “Tar Sand Research and Development at the University of Utah,” Ann. 

Rev. Energy 12:283–336. 

Oil Sands Discovery Center, 2006a, Surface Mining: Extraction, Alberta Oil Sands Discovery 

Center Fact Sheet. Available at www.oilsandsdiscovery.com/oil_sands_story/pdfs/extraction.pdf. 

Accessed Feb. 28, 2006. 
Final OSTS PEIS B-44 

Oil Sands Discovery Center, 2006b, Upgrading, Alberta Oil Sands Discovery Center Fact Sheet. 

Available at www.oilsandsdiscovery.com/oil_sands_story/pdfs/upgrading.pdf. Accessed 

Feb. 28, 2006. 

Ritzma, H.R., 1979, Oil-impregnated Rock Deposits of Utah, Utah Geological and Mineral 

Survey, Map 47, scale 1:1,000,000. 

Schamel, S., and J. Baza, 2003, “Heavy Oil Resources of Utah: An Emerging Opportunity?”, 

presented at the American Association of Petroleum Geologists (AAPG) Annual Meeting, 

May 9May 14, Salt Lake City, Utah. 

Schumacher, M.M., 1978, Enhanced Oil RecoverySecondary and Tertiary Methods, Noyes 

Data Corporation, Park Ridge, N.J. 

Short, N., 2006, Remote Sensing Tutorial, National Aeronautics and Space Administration. 

Available at http://rst.gsfc.nasa.gov/Sect2/Sect2_3.html. Accessed Oct. 24, 2006. 

Singh, S., et al., 2005, Cost Analysis of Advanced Technologies for Production of Heavy Oil and 

Bitumen in West Canada. Available at www.worldenergy.org/wec-geis/publications/default/ 

tech_papers/17th_congress/2_1_03.asp. Accessed March 1, 2006. 

Speight, J.G., 1990, “Tar Sand,” in Fuel Science and Technology Handbook, J.G. Speight 

(editor), Marcel Dekker, Inc., New York, N.Y. 

Speight, J.G., 1995, Tar Sands, Recovery and Processing, Vol. 4, A. Bisio and S. Boots (editors), 

John Wiley & Sons, New York, N.Y. 

Speight, J.G., 1997, “Tar Sands,” in Kirk-Othmer Encyclopedia of Chemical Technology. 

Available at www.mrw.interscience.wiley.com/kirk/articles/ tarspei.a01/pdf_fs.html. Accessed 

Feb. 16, 2006. 

Spencer, G.B., et al., 1969, Domestic Tar Sands and Potential Recovery Methods—A Review, 

presented at the Interstate Oil Compact Commission Meeting, Salt Lake City, Utah, Dec. 8–10. 

Temple Mountain Energy, 2011, Products, Resource Assessment and Location, Process and 

Operations, and Environmental Footprint. Available at http://templemountainenergy.com/. 

Accessed July 11, 2012. 

University of Utah, 2007, A Technical, Economic, and Legal Assessment of North American 

Heavy Oil, Oil Sands, and Oil Shale Resources, prepared for the U.S. Department of Energy, 

September, 2007. 

USGS (U.S. Geological Survey), 1980a, Argyle CanyonWillow Creek, Utah Tar Sand Leasing 

Minutes No. 9, Minutes of the Mineral Land Evaluation Committee, Nov. 10. 
Final OSTS PEIS B-45 

USGS, 1980b, Asphalt RidgeWhiterocks and Vicinity, Utah Tar Sand Leasing Minutes No. 3, 

Minutes of the Mineral Land Evaluation Committee, Sept. 23. 

USGS, 1980c, Circle Cliffs East and West Flanks, Utah Tar Sand Leasing Minutes No. 5, 

Minutes of the Mineral Land Evaluation Committee, Sept. 23. 

USGS, 1980d, Hill Creek, Utah Tar Sand Leasing Minutes No. 6, Minutes of the Mineral Land 

Evaluation Committee, Nov. 10. 

USGS, 1980e, Pariette, Utah Tar Sand Leasing Minutes, Minutes of the Mineral Land 

Evaluation Committee, Nov. 10. 

USGS, 1980f, P.R. Spring, Utah Tar Sand Leasing Minutes, Minutes of the Mineral Land 

Evaluation Committee, Sept. 23. 

USGS, 1980g, Raven RidgeRim Rock and Vicinity, Utah Tar Sand Leasing Minutes No. 8, 

Minutes of the Mineral Land Evaluation Committee, Nov. 10. 

USGS, 1980h, San Rafael Swell, Utah Tar Sand Leasing Minutes No. 7, Minutes of the Mineral 

Land Evaluation Committee, Nov. 10. 

USGS, 1980i, Sunnyside and Vicinity, Utah Tar Sand Leasing Minutes No. 4, Minutes of the 

Mineral Land Evaluation Committee, Sept. 23. 

USGS, 1980j, Tar Sand Triangle, Utah Tar Sand Leasing Minutes No. 2, Minutes of the Mineral 

Land Evaluation Committee, Sept. 23. 

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Land Evaluation Committee, Nov. 10. 

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(Geolex Database). Available at http://ngmdb.usgs.gov. Accessed Oct. 24, 2006. 

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Operational Update and Grant of Options, Press Release, May 29, 2012, Calgary Alberta. 

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Oil Sands Rush, The Pembina Institute, Nov. 

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Lake City, Utah) to J. Kohler (BLM Utah State Office, Salt Lake City, Utah), July 21. 

 
Final OSTS PEIS B-46 

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Final OSTS PEIS B-47 

ATTACHMENT B1: 

ANTICIPATED REFINERY MARKET RESPONSE 

TO FUTURE TAR SANDS PRODUCTION 

 
Final OSTS PEIS B-48 

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Final OSTS PEIS B-49 

ATTACHMENT B1: 

ANTICIPATED REFINERY MARKET RESPONSE 

TO FUTURE TAR SANDS PRODUCTION 

1 INTRODUCTION 

As noted in the discussion in Attachment A1 to Appendix A regarding refinery market 

response to future oil shale production, crude feedstocks, regardless of their provenance, all 

compete for acceptance into the U.S. refinery market based on a number of factors. These 

include value factors of the feedstock itself (i.e., critical chemical and physical parameters of the 

feedstock), reliability and consistency of supply, the logistics of transporting the feedstocks from 

points of recovery or generation to refining facilities, the extent to which existing refinery 

processing configurations align with feedstock parameters and their processing demands, and 

how efficiently those feedstocks can be converted to products currently in high demand. 

Collectively, all such factors contribute to a “refining margin” that is unique for every refinery 

and that is constantly changing on the basis of the availability of crude feedstocks as well as 

changing market demands for refinery products (e.g., distillate fuels, feedstock intermediates 

delivered to other refineries for further processing, and petrochemical feedstocks). While oil 

shale and tar sands are fundamentally different resources with respect to their depositional 

environments, their chemical compositions, their extraction and production technologies, and 

their marketable products, many of the same factors influencing penetration of oil shalederived 

crude feedstocks into the refining market can be seen to be in effect for tar sandsderived 

feedstocks. 

Attachment A1 of Appendix A of this PEIS gives an overview of the U.S. refinery 

market, including discussions of critical parameters in the crude oil refinery process, market 

responses to feedstock value parameters, refinery utilization factors, current refinery capacity, 

the Petroleum Administration for Defense District (PADD) system, current crude sources 

(including Canadian syncrude production), and other possible market drivers. This brief 

overview discusses how tar sandsderived crude feedstocks might be incorporated into the 

U.S. refinery market and how the availability of these new crude feedstocks may influence 

decisions regarding construction, expansion, or reconfiguration of processing capabilities. 

In a manner very similar to the anticipated market development pathways for oil 

shalederived crude feedstocks, the following factors predominate in supporting refinery market 

adjustments to tar sandsderived crude feedstock: 

• The investment into and expansion of refining capacity are solely determined 

by the investor’s long-term expectation of refining margins. Only those crude 

feedstock sources that can demonstrate long-term availability and consistent 

quality factors are likely to be considered as drivers for refinery processing 

capacity expansions or crude feedstock displacements. 
Final OSTS PEIS B-50 

• New crude feedstock sources displace sources in existing markets based on 

how well their quality parameters align with existing or expanding refining 

capability; the market will take proportionately longer to accept new sources 

with quality factors substantially different from existing or alternatively 

available sources; conversely, refineries will more readily consider an 

expansion in capacity within their current processing configurations if new 

feedstock sources become available and can be seen to result in satisfactory 

refining margins. 

• Incremental expansion at existing facilities is the expected primary way in 

which tar sandsderived crude feedstock will be introduced into the refinery 

market. Given the modest ultimate production levels forecasted both 

collectively and at individual facilities, there will be little to no impetus to 

build new refineries solely in response to this U.S. tar sandsderived 

feedstock’s newly established availability. 

• Only high-volume feedstock streams of proven reliability and consistency will 

precipitate major refinery expansions and/or displacements, or major 

expansions and/or construction of long-distance pipelines to link the feedstock 

to distant refineries. 

• Pipelines do not drive refinery market investments. Pipeline operators react to 

emerging markets and provide transportation linkage between the source and 

refiner. 

• Intuitively, domestic sources of crude feedstocks are more desirable than 

foreign sources simply because of their inherently more secure status. 

However, to retain their advantage, such domestic sources must also compare 

favorably with imported feedstocks with respect to overall product yield and 

other quality parameters (e.g., contaminant and acid content). 

2 IMPORTANT CHARACTERISTICS OF TAR SANDS RESOURCES 

AND RESULTING MARKETABLE PRODUCTS 

Production of crude feedstock and/or asphalt from many facilities producing from tar sands 

deposits in Utah may approach a total of about 300,000 bbl/day over the next 20 years 

(20072027).1 It is anticipated that most of the tar sandsderived feedstocks will be crude 

feedstock, with a smaller portion being produced as asphalt. Table 1 provides a comparison of 

some critical chemical and physical parameters of various tar sands deposits within selected 

Special Tar Sand Areas (STSAs) in Utah. 

 

1 To facilitate discussion of potential effects of tar sands development, the BLM assumed a commercial 

production level of approximately 300,000 bbl/day. 
Final OSTS PEIS B-51 

TABLE 1 Critical Chemical and Physical Properties of Selected Tar Sands Deposits 

Source: Gwynn (2006). 

Although it can be anticipated that development of each of the STSA deposits will follow 

very different cost and logistical schedules to generate marketable product, the refining market is 

generally insensitive to resource development costs and logistical demands and impediments. 

Therefore, for the purposes of this analysis, all tar sands developers are considered to be in the 

same starting position with respect to finding markets for their products, irrespective of the 

overall costs each developer has incurred in getting to that point. 

Although the cost of resource development is outside the scope of determining the 

competitiveness of the resulting products to the refinery market, critical chemical and physical 

parameters of those products are not. Thus, for example, the Sunnyside deposit that would 
Final OSTS PEIS B-52 

produce raw bitumen with an American Petroleum Institute (API) gravity2 of 5.5 puts the 

developer at a distinct disadvantage compared with developers of other deposits whose raw 

bitumen API gravities are higher, since the Sunnyside developer would need to invest greater 

effort to improve the gravity of his product for economical pipeline transport. However, as can 

be seen from Table 1, API gravities for any U.S. tar sands bitumen can range from a low of 

5.5 to a high of 14.4. Consequently, even the bitumen with the highest API gravity is still not 

acceptable for pipeline transport, suggesting that all developers would be faced with the 

requirement to improve on the quality of the raw bitumen they recovered before having any 

realistic opportunity of finding both a refining market and an economical way of getting their 

product to that market. 

Likewise, developers whose raw bitumen has the lowest percentages of refining catalystsfouling contaminants, such as sulfur and nitrogen, would have an initial competitive edge over 

sources where the amounts of these contaminants are higher. In addition to threatening the safe 

operation of refinery processing units, adding to the cost of operation by reducing the life of 

expensive catalysts and adding to processing unit downtime for catalyst replacement, the 

presence of both nitrogen and sulfur contaminants may cause a refinery to incur heavier 

regulatory burdens. Severe limitations could be placed on resulting processing emissions, which 

would require significant investments in pollution control devices before necessary operating 

permits could be secured. Even without emission limitations, the recently promulgated standards 

for low-sulfur diesel fuels for on-road vehicles further increases the costs of processing by 

requiring additional expensive sulfur removal steps to meet product specifications. Premature 

catalyst replacements, increased regulatory controls, and more rigorous product specifications 

can each severely impact refining margins and thus reduce the attractiveness of the feedstock. To 

remain competitive with intrinsically higher quality feedstocks, purveyors of high-sulfur, highnitrogen, and low API gravity feedstocks must consider discounting or, alternatively, carrying 

the costs themselves of improving these parameters before offering their product to refineries. 

Crude feedstock quality is among the most critical of factors affecting refinery market 

penetration. Because there has been very little commercial development of U.S. tar sands 

deposits, there is virtually no empirical evidence on which to base any presumptions of the 

quality factors for U.S. tar sandsderived products; however, irrespective of the recovery 

technology employed, recovery of bitumen from its natural setting is simply a physical 

separation process and is not expected to substantially change its chemical composition. 

Consequently, it is safe to assume that the quality factors displayed by bitumen in its natural 

setting will survive virtually unchanged throughout any separation processes (see Table 1). 

Tar sands deposits in Canada are fundamentally different from tar sands in the 

United States. The presence of a free water sheath surrounding the inorganic sand and separating 

it from the bitumen in Canadian deposits (known as “water-wet tar sand”) facilitates the 

separation of the bitumen from the sand using relatively inexpensive and highly effective 

(but water-intensive) separation technologies. Those same technologies, while technically 

 

2 API gravity is an arbitrary scale for expressing the specific gravity or density of liquid petroleum products. 

Devised by the API and the National Bureau of Standards, API gravity is expressed as degrees API. API 

gravities are the inverse of specific gravity. Thus, heavier viscous petroleum liquids have the lower API values. 
Final OSTS PEIS B-53 

available to developers of U.S. tar sands, will not produce the same efficiencies of separation as 

they do for Canadian developers and would be executed at a higher cost in U.S. development or 

not at all because of the unavailability of the required volumes of water. Amended technologies 

to those practiced in Canada, as well as alternative technologies, are nonetheless available for 

U.S. tar sands, although at higher overall costs and/or reduced recovery efficiencies. As noted 

above, however, such development costs are not of particular concern to refiners; decisions 

regarding acceptance of new feedstocks are based on the quality, availability, and cost of the 

feedstocks and the refining margins of the resulting products, and disregard the difficulty or 

efficiency of resource recovery. In this sense, raw bitumen recovered from U.S. deposits can be 

expected to be generally equivalent to Canadian bitumen in critical quality factors, despite 

expected higher recovery costs. Likewise, synthetic crude resulting from upgrading of U.S. tar 

sandsderived bitumen is expected to be generally equivalent to synthetic crude that results from 

upgrading Canadian-derived bitumen to an equivalent extent, again, costs notwithstanding. 

Consequently, those same refineries that now are configured to receive significant quantities of 

Canadian syncrude or raw bitumen can be expected to find U.S. tar sandsderived feedstocks 

equally attractive from a quality perspective. Other factors of attractiveness, such as reliability 

and consistency of supply over time, have not been established for U.S. tar sandsderived 

feedstocks, however, and are not likely to be equivalent to Canadian analogs, based on the 

relative magnitudes, accessibility, and quality of the respective tar sands resources and the 

maturity of the Canadian tar sands industry and its supporting transportation infrastructures. 

3 ISSUES ASSOCIATED WITH UPGRADING 

As discussed above, all tar sands deposits are not equal with respect to the products they 

might potentially offer to refineries. Obtaining equality by improving upon or eliminating 

unattractive chemical and physical properties of the raw bitumen involves upgrading of the raw 

bitumen by either removing carbon (coking reactions) or adding hydrogen (hydrogenation) 

Reacting bitumen with hydrogen results in two distinct types of reactions: hydrocracking (adding 

hydrogen to complex, unsaturated molecules to make smaller, more desirable saturated 

hydrocarbons) and hydrotreating (converting sulfur- and nitrogen-bearing constituents to 

hydrogen sulfide and ammonia, respectively, both of which can be subsequently easily removed 

from the product stream). Upgrading can be performed to whatever extent is desired, yielding 

ever-increasing quality of resulting products with proportionally increasing costs. Upgraded 

products are generally referred to as synthetic crude, regardless of the extent of upgrading. Even 

modest degrees of upgrading would require a substantial investment in resources (e.g., electric 

power, natural gas, and water), expensive reactants such as hydrogen, processing equipment, and 

related infrastructure. Developers of tar sands deposits that exist in relatively remote, arid areas 

with limited access to required resources and other logistical constraints would be at a 

disadvantage in pursuing this strategy. Consequently, any upgrading performed at the tar sands 

development site would be expensive and impossible without significant investment in 

supporting infrastructures. Nonetheless, the analyses in this PEIS anticipate that some modest 

amount of upgrading of raw bitumen would occur at U.S. tar sands developments. 
Final OSTS PEIS B-54 

An additional strategic option exists that is unique to tar sands. The raw bitumen itself is 

a legitimate constituent of conventional crude oil and, without further chemical alteration, can 

serve as a feedstock for properly configured refineries. Some logistical impediments still exist 

for this development path, however. The relatively low API gravity of raw bitumen (see Table 1) 

preempts its transport by pipeline. However, diluents such as raw naphtha, raw gas oil, or other 

crude oil distillation condensates, any of which would be in abundance in integrated refineries, 

can be shipped to the tar sands development and mixed with the raw bitumen to form a solution 

(known in the industry as “dil-bit” or “dilbit”) that can be transported by conventional pipeline. 

Once arriving at the refinery, the diluent can be separated and used again for pipelining 

subsequent batches of raw bitumen. However, dilution ratios as high as 30% by volume diluent 

may be necessary (Brierley et al. 2006), and transporting the diluent to the mine site in requisite 

volumes by truck would ensure that any strategy involving dilbit would be expensive. 

Nevertheless, as will be discussed later, evolution in processing capabilities in the refining 

industry to add greater coking capacity is compatible with this strategic option, and production 

and shipment of diluted bitumen are already being pursued by many Canadian tar sands 

developers. Of the more than 2.17 million bbl/day of crude feedstocks imported into the 

United States from Canada, approximately 400,000 bbl/day consists of un-upgraded bitumen 

(transported as dilbit), sold primarily to refineries configured to process heavy crudes.3 Finally, a 

smaller fraction of Canadian crude imports is transported as “Syn-dil-bit,” a blend of synthetic 

crude, distillation condensates, and bitumen. Such mixtures, however, are typically sold to 

refineries configured to process light to medium crudes. Each of the bitumen mixtures described 

above commands its own unique processing scheme, and major challenges remain for refiners of 

such bitumen mixtures. Bitumen dilutions typically are assembled to meet a target API gravity of 

20; however, most will still contain significant volumes of residuum and have a high sulfur 

content. By comparison, the synthetic crudes resulting from upgrading of raw bitumens would be 

characterized by virtually no residual and relatively low sulfur content.4 Distillates yielded in 

their subsequent refining, however, would have high aromatic character, which would necessitate 

greater degrees of subsequent hydrotreating to produce rigorously specified transportation fuels. 

Further, distillate suites also would typically include relatively high volumes of polyaromatic gas 

oil, which would reduce the yields in subsequent downstream fluid catalytic cracking (FCC) 

units. 

4 EVOLVING CRUDE FEEDSTOCK MARKETS 

Currently, light crude (API gravity of 34 or higher) represents approximately 50% of the 

crude oil available on the world market. Much of the availability and thus more rapid depletion 

of light crudes are due to the Organization of Petroleum Exporting Countries (OPEC) quota 

system. This quota on total production volumes provides incentives to OPEC producers to sell 

 

3 To facilitate import of bitumen, pipelines specifically designed to deliver diluent to Canadian tar sands mine sites 

are also now being constructed. 

4 Although synthetic crudes are typically low in overall sulfur content, the specific sulfur-bearing species that 

remain are difficult to treat. Significant effort is required to hydrotreat synthetic crude distillate fractions to meet 

the recently promulgated ultra-low-sulfur on-road diesel fuel specifications. 
Final OSTS PEIS B-55 

the higher margin light crudes. Production of light sour crude is expected to increase by 

9 million bbl/day by 2015, but the production of light sweet crude is expected to increase by only 

1 to 2 million bbl/day over the same period (Phillips et al. 2003). Availability of light sweet 

crude is expected to continue to decline as production in key areas declines. At the same time, 

availability of heavier synthetics and bitumen blends is increasing and is expected to reach 

almost 3 million bbl/day by the year 2015 (Brierley et al. 2006). Concurrently, demand for 

lighter distillate fuels continues to increase, and specifications for such fuels become more 

rigorous. Consequently, refiners throughout the country are focusing their attention on expanding 

their capacity for “bottom of the barrel” processing and seeking out heavier crude feedstocks, 

including synthetics. Traditionally, heavier crude feedstocks were converted to low-value fuel 

oils, asphalts, and lube stocks, with these relatively low-value products commanding severe 

discounting of the parent feedstock. However, reconfiguration to add coking, delayed coking, 

FCC, and hydrocracking capacities allows refineries to switch to heavier crude stocks and still 

meet market demands for lighter, more rigorously specified fuels.5 Deep discounting of heavier 

crudes allows refineries to obtain amortization of their reconfiguration costs over a reasonable 

period while still maintaining adequate refining margins. Increased “bottom of the barrel” 

processing capacity is driven not only by “upstream” factors, such as crude source availability, 

but also by “downstream” factors such as increased markets for transportation fuels with a 

coincident decline in the market for heavier residuals, an increasing demand for anode-grade 

coke,6 and a continued inclination by the refinery industry to meet changing processing and 

product demands by reconfiguring or expanding capacities at existing refineries rather than 

building new grass-roots crude processing capacity. 

Crude feedstocks from Canadian tar sands production can be seen as significant 

competition for U.S. tar sandsderived synthetics and bitumen. Not only is the Canadian tar 

sands resource substantially larger, more contiguous, and more homogeneous than the 

U.S. resource, the Canadian tar sands industry is mature, and the volumes of Canadian imports 

are expected to grow significantly in the near term. For example, by 2015, a forecasted Canadian 

syncrude import volume of approximately 4.5 million bbl/day could represent as much as 28% of 

the U.S. refinery industry’s crude consumption nationwide.7

Canadian imports into PADD 4 refiners, the region in which the Utah tar sands deposits 

are located, has increased from 2000 to 2005 by approximately 40%, as shown in Table 2. 

 

5 Phillips et al. (2003) reports that approximately 50% of the worldwide coking capacity is concentrated in the 

United States and totaled more than 2,000,000 bbl/day of installed capacity in 2003. In the 15 years previous to 

2003, delayed coking capacity had grown by 56% in the United States, followed by hydrocracking (37%) and 

FCC (14%). 

6 Anode grade coke is used in aluminum smelting and generally requires a crude feedstock that is low in sulfur 

and low in metals but that typically commands a high price, guaranteeing high refining margins even with the 

purchase of more expensive crude. 

7 The Energy Information Administration (EIA) forecasts that by 2015, the total volume of crude actually 

consumed by all U.S. refineries will be 16.3 million bbl/day. For clarification against refinery capacities 

discussed earlier, assuming continuing refinery utilization rates of 93%, this volume infers 17.5 million bbl 

per stream day refinery distillation capacity, which can be reasonably expected to come from incremental 

expansions of existing facilities. EIA crude volume consumption forecasts can be downloaded from 

http://www.eia.doe.gov/oiaf/aeo/pdf/aeotab_11.pdf. 
Final OSTS PEIS B-56 

TABLE 2 PADD 4 Crude Imports by Mode of Transportation

Year (1,000s of bbl/day) 

Mode of 

Transportation 2000 2001 2002 2003 2004 2005 

 

Total 505 501 522 527 555 559 

Pipeline 474 468 488 489 510 508 

Domestic 287 263 257 253 248 247 

Canadian 187 205 230 236 261 260 

Trucks 31 33 34 38 45 52 

Domestic 31 33 34 38 45 52 

Canadian 0 50 0 0 0 0 

Source: EIA (2006a). 

The majority of this was upgraded synthetic crudes. These crudes (after upgrading) are being 

offered at prices roughly equivalent to domestic conventional crudes in the region. The 

attractiveness of the synthetic crudes over conventional domestic crudes is based on the lack of 

light ends, such as butane and propane, and the lack of the bottoms or residual. Both of these 

fractions are of less value than the “middle of the barrel” transportation fuel progenitors and 

sometimes even below the cost of the crude, thereby destroying overall value. In addition, the 

domestic crude in the area has a higher sulfur content, which requires additional capital 

investment and operating expense to meet low-sulfur fuel specifications. 

The overall markets for residual fuel oils have diminished over time. The key remaining 

market is heavy, relatively high-sulfur “bunker fuels” used primarily in ocean-going vessels. 

PADD 4 refineries do not have ready access to this market, primarily because of their geographic 

location. Therefore, there has been an incentive to import upgraded synthetic crudes, which lack 

a residual cut. Aside from acquiring a synthetically derived crude, which lacks a bottoms or 

residual product, it must either be sold as lower value asphalts and fuel oils or be upgraded into 

transportation fuels. The most common process technologies in the upgrading of bottoms 

(as found in bitumen, but not in upgraded synthetic crudes) are forms of thermal cracking called 

cokers. They produce roughly 65% transportation fuels and 35% petroleum coke from the 

residual portion of a full crude barrel. PADD 4 thermal cracking capacity has been relatively flat 

since 2001 (except for normal capacity creep through normal maintenance and debottlenecking) 

as shown in Table 3. This represents coking capacity at only 4 of the 16 PADD 4 refineries. This 

leaves a significant portion of the market with available options to invest in this heavy upgrading 

utilizing this new crude resource. Currently, two coker projects are under construction in 

PADD 4, with one more announced. In addition, there is one coker being constructed adjacent to, 

but outside PADD 4, at Borger, Texas, which is to be supplied as part of a new strategic 

partnership between Encana and ConocoPhillips. 

Because of the Canadian tar sands industry’s maturity and other important circumstantial 

factors such as resource availability, many Canadian developers have begun extensively 
Final OSTS PEIS B-57 

TABLE 3 PADD 4 Thermal Cracking Downstream Refining Capacity 

Year (1,000s of bbl/stream day) 

Coking Type 2001 2002 2003 2004 2005 2006 

 

Total 45,700 45,700 46,850 47,250 47,950 48,850 

Delayed 36,800 36,800 37,950 37,950 37,950 38,450 

Fluid 8,900 8,900 8,900 9,300 10,000 10,400 

Source: EIA (2006b). 

upgrading their products to eliminate problematic characteristics of earlier products and enhance 

more desirable characteristics without proportional increases in costs. For example, 

Brierley et al. (2006) report that Suncor markets a light sweet crude, Suncor Oil Sands Blends A 

(OSA), that is the product of hydrotreating the products of delayed coking performed at the 

Suncor mine site. Suncrude Canada Ltd. markets a fully hydrogenated blend, Syncrude Sweet 

Blend (SSB), utilizing fluidized bed coking technology. Husky Oil now operates a heavy crude 

upgrading system consisting of a combination of ebullated-bed hydroprocessing and delayed 

coking to produce Husky Sweet Blend (HSB). The Athabasca Oil Sands Project uses ebullated 

bed hydroprocessing to produce Premium Albian Synthetic (PAS). Upgraded Canadian 

synthetics display very favorable characteristics over un-upgraded bitumens, with API gravities 

as high as 38.6 and sulfur contents as low as 0.1% by weight (Brierley et al. 2006). Light sweet 

synthetic crudes produced at mine site upgrading facilities command a premium price on the 

market (but still discounted relative to conventional light sweet crudes) and are comparable to 

conventional light sweet crudes in many respects. However, because of the high aromatic 

character of the parent bitumen, even these upgraded light sweet synthetic crudes are attractive 

only to refineries configured specifically to handle them. 

In recent years, strategic mine site upgrading decisions have not been made unilaterally 

by Canadian developers, but, instead, are the products of extensive collaboration with individual 

refineries. The result has been the production of synthetic feedstocks uniquely suited to a 

particular refinery’s processing capabilities and, at the same time, reconfiguration strategies 

undertaken by the refineries to ensure full compatibility with particular synthetic crude sources. 

The highly integrated agreements between feedstock supplier and refiner that result from such 

collaborations are not easily overturned or displaced. However, while such one-on-one 

collaborations can yield both increased overall efficiencies and maximum refining yields, it is 

generally acknowledged that, as the Canadian tar sands industry continues to grow, there will be 

an increasing need to direct synthetic crude production into a few “marker” categories in 

consultation with major refining market centers as opposed to individual refineries, rather than 

allow a continuing expansion in the number of “boutique feedstocks” (OSEW/SPP 2006). 

Irrespective of any controls being placed on the variety of synthetic crudes being 

developed, it will continue to be the case that Canadian tar sands developers will have much 

greater opportunities to undertake bitumen upgrading at their mine sites than will 
Final OSTS PEIS B-58 

U.S. developers. The ability to upgrade at the mine site, together with purchasing agreements 

already in place for synthetic crudes with specific properties, gives a distinct advantage to 

Canadian developers over their U.S. counterparts in the competition for refinery market share, 

especially in the near term. 

Notwithstanding the extensive mine site upgrading discussed previously, the potential 

refinery market for raw bitumen would be only incrementally different from the market available 

to producers of relatively heavy conventional or synthetic crudes, including synthetic crudes 

from tar sands. Refineries configured to accept heavier crude feedstocks, including Canadian 

synthetics upgraded to various degrees, would be in an ideal position with respect to processing 

capability to accept the raw bitumen. However, processing schemes are established against the 

characteristics of a particular crude feedstock or feedstock blend, and myriad process 

modifications are required before even modest changes in feedstock character are made. Thus, 

simple replacements of feedstocks are not necessarily straightforward operations even if the 

required processing units are in place. In addition to the unique processing requirements of each 

feedstock, available processing capacity for new sources is likely to be very limited. This is 

especially the case for refineries that have recently reconfigured to accept products from 

Canadian sources that currently import both synthetic crude and dil-bit into the United States as 

heavy crude feedstocks. All of the above being said, it is the case that PADD 4 refineries in 

closest proximity to the STSAs were some of the first U.S. refineries to reconfigure to accept 

Canadian synthetic crude. Refineries in Denver, Salt Lake City, and Cheyenne, among others, 

have reconfigured to accept Canadian feedstocks, including raw bitumens, and would be the 

most likely candidates for receipt of U.S. tar sandsderived crude feedstocks and/or raw 

bitumen. 

The evolution of the refining industry toward heavier feedstocks bodes well for the tar 

sands industry in a general sense; however, there are still substantial supplies of conventional 

crude oils of equivalent densities and qualities against which unconventional or synthetic crudes 

such as those from tar sands must still compete. Those other conventional sources aside, 

however, of more immediate interest and concern to U.S. tar sands developers are the current and 

anticipated productions of Canadian tar sandsderived synthetic crudes, and especially the 

upgraded synthetic crudes that are now being offered. 

5 CONCLUSIONS 

Bitumen and synthetic crude oil derived from Canadian tar sands represent the most 

immediate and direct competition to U.S. tar sandsderived feedstocks for refinery market share. 

The enormous size of the Canadian tar sands resources, the maturity of the Canadian tar sands 

industry, the proven reliability and consistency of Canadian products, the ever expanding 

pipeline infrastructure devoted to delivering Canadian tar sands to U.S. refineries, and the ability 

of Canadian developers to undertake extensive upgrading of recovered bitumen at their mine 

sites to remove unfavorable characteristics all give Canadian developers substantial market 

advantages over U.S. developers. 
Final OSTS PEIS B-59 

Refineries in PADD 4 are geographically closest to each of the STSAs and have also 

already undertaken reconfiguration of their processing streams to accept heavy synthetic crude 

feedstocks, making them the most likely candidates to receive U.S. tar sandsderived feedstocks. 

However, Canadian imports of bitumen and synthetic crude are already being received at these 

refineries, and unused processing capacity is not expected to be available in any appreciable 

amount. It is possible that the current investment rate of transportation of Canadian crudes to 

alternative markets, such as the Gulf Coast (PADD 3), the West Coast (PADD 5), and 

international export to China and Asia could produce more competition for Canadian crudes over 

the long run and provide more economic room for tar sandsderived crude feedstock in PADD 4. 

With a projected maximum collective production rate approaching a total of about only 

300,000 bbl/day, the U.S. tar sands developments would not be large enough to single-handedly 

or collectively motivate significant expansions in either long-range crude pipeline transportation 

networks or refinery expansions, suggesting that penetration into the refinery market would be 

limited to refineries in the immediate vicinity of the STSAs, primarily the properly configured 

PADD 4 refineries. Only modest expansions of crude oil pipeline networks already in place in 

PADD 4 would be required to connect STSAs to PADD 4 refineries. 

The market for PADD 4 refinery products is geographically constrained, thus even if 

additional processing capacity were to be made available by PADD 4 refinery expansions, 

construction and/or expansion of product pipelines to distant markets would need to occur before 

that additional processing capacity could be utilized. 

6 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

Brierley, G., et al., 2006, Changing Refinery Configuration for Heavy and Synthetic Crude 

Processing, presented at the Annual Meeting of the National Petroleum Refiners Association, 

Salt Lake City, Utah, March 1921. 

EIA (Energy Information Administration), 2006a, “Petroleum Navigator, Number and Capacity 

of Petroleum Refineries.” Available at http://tonto.eia.doe.gov/dnav/pet/pet_pnp_cap1_dcu_ 

R40_a.htm. Accessed Jan. 26, 2007. 

EIA, 2006b, “Petroleum Navigator, Downstream Charge Capacity of Operable Petroleum 

Refineries.” Available at http://tonto.eia.doe.gov/dnav/pet/pet_pnp_capchg_dcu_R40_a.htm. 

Accessed Jan. 27, 2007. 

Gwynn, J.W., 2006, “Utah’s Oil Sands Resources,” presented at the Western U.S. Oil Sands 

Conference, University of Utah Heavy Oil Center, Sept. 21. 
Final OSTS PEIS B-60 

OSEW/SPP (Oil Sands Expert Workgroup, Security and Prosperity Partnership), 2006, (Draft) 

Workshop Working Report, Houston, Texas, Jan. 2425. 

Phillips, G., et al., 2003, “Drivers for Additional Delayed Coking Capacity in the Refining 

Industry,” Petroleum Economist, Sept. 
Final OSTS PEIS C-1 

APPENDIX C: 

PROPOSED LAND USE PLAN AMENDMENTS 

ASSOCIATED WITH ALTERNATIVES 2, 3, AND 4 

FOR OIL SHALE AND TAR SANDS 
Final OSTS PEIS C-2 

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Final OSTS PEIS C-3 

APPENDIX C: 

PROPOSED LAND USE PLAN AMENDMENTS 

ASSOCIATED WITH ALTERNATIVES 2, 3, AND 4 

FOR OIL SHALE AND TAR SANDS 

The U.S. Department of the Interior, Bureau of Land Management (BLM), develops land 

use plans to guide activities, establish management goals and approaches, and establish land use 

allocations within a planning area. Current land use plans are called Resource Management Plans 

(RMPs); in the past, such plans were called Management Framework Plans (MFPs), and some 

MFPs are still in use. Analyses conducted in this programmatic environmental impact statement 

(PEIS) support the amendment of specific land use plans in those field offices where oil shale 

and tar sands resources are located, as discussed in Chapters 2 and 6 of the PEIS. 

For oil shale, 8 of the 10 land use plans cited in BLM’s Notice of Intent (Federal 

Register, Vol. 76, No. 72, April 14, 2011) would be amended1: 

• Colorado 

 Glenwood Springs RMP (BLM 1988, as amended by the 2006 Roan 

Plateau Plan Amendment [BLM 2006a, 2007, 2008a]) 

 Grand Junction RMP (BLM 1987) 

 White River RMP (BLM 1997a, as amended by the 2006 Roan Plateau 

Plan Amendment [BLM 2006a, 2007, 2008a]) 

• Utah 

 Price RMP (BLM 2008b) 

 Vernal RMP (BLM 2008c) 

• Wyoming 

 Green River RMP (BLM 1997b, as amended by the Jack Morrow Hills 

Coordinated Activity Plan [BLM 2006b]) 

 Kemmerer RMP (BLM 2010) 

 Rawlins RMP (BLM 2008d) 

For tar sands, four Utah land use plans would be amended: 

• Monticello RMP (BLM 2008e) 

• Price RMP (BLM 2008b) 

 

1 Because the estimated surface acreages overlying the most geologically prospective oil share resources are zero 

for the Monticello and Richfield Field Offices, the corresponding land use plans will not be amended. 
Final OSTS PEIS C-4 

• Richfield RMP (BLM 2008f) 

• Vernal RMP (BLM 2008c) 

Table C-1 presents the proposed amendments for land use plans associated with 

Alternatives 2 through 4 for oil shale along with the rationale for each amendment. Table C-2 

presents the same information for amendments for land use plans associated with Alternatives 2 

through 4 for tar sands. The BLM would amend no land use plans under Alternative 1 for oil 

shale or tar sands, leaving the 2008 Record of Decision (BLM 2008g) in place.2 

 

2 As discussed in Section 2.3.3, Naval Oil Shale Reserves 1 and 3 in Colorado are closed to leasing under all 

alternatives, including Alternative 1, the No Action Alternative. Affected land use plans in Colorado that show 

these lands as open based on the 2008 PEIS (BLM 2008h) would be corrected to show these lands as closed. 
TABLE C-1 Proposed Land Use Plan Amendments and Rationale Associated with Alternatives 2 through 4 for Oil 

Proposed Amendment and Rationale Alternative 2 Alternative 3 Alternat

Colorado: Glenwood Springs RMP None. None. Amendment: Designate 3,10

the most geologically prospeincluding split estate lands wgovernment owns the minerapplication for leasing for codevelopment in accordance and state regulations and BLRationale: All lands within prospective oil shale area thcommercial leasing under Abe excluded under Alternatiestimate presented here reprexcluded from commercial lAlternative 4. 

None. None. Amendment: Specify that ap

commercial leases using surwill not be accepted in the p

Rationale: Surface mining wareas where the overburden because 500 ft is assumed to amount of overburden wheroccur economically, using toWithin the most geologicallarea defined in the Piceance areas where the overburden very limited, and it would blogical mining unit (Section 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatColorado: Grand Junction RMP Amendment: Designate 180 acres of land within the most geologically prospective oil shale area, including split estate lands where the federal government owns the mineral rights, as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing by existing laws and 

regulations, Executive Orders, or administrative land use plan designation, or have not been specifically excluded by the BLM for other reasons, will be available for application for commercial leasing. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 2. 

None. Amendment: Designate 3,70

the most geologically prospeincluding split estate lands wgovernment owns the minerapplication for leasing for codevelopment in accordance and state regulations and BLRationale: All lands within prospective oil shale area thcommercial leasing under Abe excluded under Alternatiestimate presented here reprexcluded from commercial lAlternative 4. 

Amendment: Specify that applications for commercial leases using surface mining technologies will not be accepted in the planning area. 

None. Same as Alternative 2. 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatColorado: Grand Junction RMP (Cont.) Rationale: Surface mining will be allowed only in areas where the overburden is 0 to 500 ft thick because 500 ft is assumed to be the maximum amount of overburden where surface mining can occur economically, using today’s technologies. Within the most geologically prospective oil shale area defined in the Piceance Basin in Colorado, the areas where the overburden is 0 to 500 ft thick are very limited, and it would be difficult to assemble a logical mining unit (Section 2.3.1). Colorado: White River RMP 

Amendment: Designate 26,000 acres of land within the most geologically prospective oil shale area, including split estate lands where the federal government owns the mineral rights, as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. The RMP amendments will retain the existing decision regarding the Multimineral Zone that requires that the commercial development of oil shale, nahcolite, and dawsonite will only be allowed in this area if recovery technologies are implemented to ensure that each of these minerals can be recovered without preventing recovery of the others (see Section 2.3.3). In addition, the current decision to not close lands within the “Piceance dome area” to leasing for oil shale development will be retained. 

Amendment: Designate 26,880 acres (25,600 acres for ongoing leases; 1,280 for proposed leases) of land within the most geologically prospective oil shale area, including split estate lands where the federal government owns the mineral rights, as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. The RMP amendments will retain the existing decision regarding the Multimineral Zone that requires that the commercial development of oil shale, nahcolite, and dawsonite will only be allowed in this area if recovery technologies are implemented to ensure that each of these minerals can be recovered without preventing recovery of the others (see Section 2.3.3). 

Amendment: Designate 333,the most geologically prospeincluding split estate lands wgovernment owns the minerapplication for leasing for codevelopment in accordance and state regulations and BLamendments will retain the regarding the Multimineral Zthe commercial developmenand dawsonite will only be arecovery technologies are imthat each of these minerals cpreventing recovery of the oIn addition, the current deciwithin the “Piceance dome ashale development will be re
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatColorado: White River RMP (Cont.) Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing by existing laws and regulations, Executive Orders, or administrative land use plan designation, or have not been specifically excluded by the BLM for other reasons, will be available for application for commercial leasing. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 2. The decision to maintain the restrictions associated with the Multimineral Zone will continue 

protection of the potential commercial value of all mineral resources within this area. The BLM also has determined that it will not preclude commercial oil shale leasing in areas, such as the Piceance dome area, where extensive oil and gas leases exist. 

Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing under Alternative 2 will also not be excluded under Alternative 3. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 3. The decision to maintain the restrictions associated with the Multimineral Zone will continue protection of the potential commercial value of all mineral resources within this area. 

Rationale: All lands within prospective oil shale area thcommercial leasing under Abe excluded under Alternatiestimate presented here reprexcluded from commercial lAlternative 4. The decision restrictions associated with twill continue protection of tvalue of all mineral resourceBLM also has determined thcommercial oil shale leasing Piceance dome area, where leases exist. 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatColorado: White River RMP (Cont.) Amendment: Specify that applications for commercial leases using surface mining technologies will not be accepted in the planning area. Rationale: Surface mining will be allowed only in areas where the overburden is 0 to 500 ft thick because 500 ft is assumed to be the maximum amount of overburden where surface mining can occur economically, using today’s technologies. Within the most geologically prospective oil shale area defined in the Piceance Basin in Colorado, 

the areas where the overburden is 0 to 500 ft thick are very limited, and it would be difficult to assemble a logical mining unit (Section 2.3.1). 

Same as Alternative 2. Same as Alternative 2. 

Utah: Price RMP 

Amendment: Designate 4 acres of land within the most geologically prospective oil shale area as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. 

None. Amendment: Designate 5 ac

most geologically prospectivavailable for application for oil shale development in accfederal and state regulations 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatUtah: Price RMP (Cont.) Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing by existing laws and regulations, Executive Orders, or administrative land use plan designation, or have not been specifically excluded by the BLM for other reasons, will be available for application for commercial leasing. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 2. Rationale: All lands within 

prospective oil shale area thcommercial leasing under Abe excluded under Alternatiestimate presented here reprexcluded from commercial lAlternative 4. Amendment: Specify that applications for 

commercial leases using surface mining technologies will not be accepted in the planning area. Rationale: Surface mining will be allowed only in areas where the overburden is 0 to 500 ft thick because 500 ft is assumed to be the maximum amount of overburden where surface mining can occur economically, using today’s technologies. In Utah, these lands fall within the Vernal RMP planning area. 

None. Same as Alternative 2. 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatUtah: Vernal RMP Amendment: Designate 357,000 acres of land within the most geologically prospective oil shale area, including split estate lands where the federal government owns the mineral rights and the Hill Creek Extension, as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. Specify that the Ute Indian Tribe will be consulted regarding potential leasing for commercial oil shale development on 57,657 acres of split estate lands located in the Hill Creek Extension of the Uintah 

and Ouray Reservation prior to considering any parcel for leasing. Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing by existing laws and regulations, Executive Orders, or administrative land use plan designation, or have not been specifically excluded by the BLM for other reasons, will be available for application for commercial leasing. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 2. During the tribal consultation process conducted in conjunction with this PEIS, the Ute Indian Tribe requested that such consultation be conducted. 

Amendment: Designate 5,760 acres (5,120 acres for ongoing leases; 640 for proposed leases) of land within the most geologically prospective oil shale area as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing under Alternative 2 will also not be excluded under Alternative 3. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 3. 

Amendment: Designate 660,the most geologically prospeincluding the Hill Creek extlands where the federal govemineral rights and the Hill Cavailable for application for oil shale development in accfederal and state regulations Specify that the Ute Indian Tregarding potential leasing fdevelopment on 57,657 acrelocated in the Hill Creek ExOuray Reservation prior to cfor leasing. Rationale: All lands within prospective oil shale area thcommercial leasing under Abe excluded under Alternatiestimate presented here reprexcluded from commercial lAlternative 4. During the triconducted in conjunction wiIndian Tribe requested that sconducted. 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatUtah: Vernal RMP (Cont.) Amendment: Specify that applications for commercial leases using surface mining technologies will be accepted only within an area of about 133,194 acres within the most geologically prospective oil shale area where overburden is 0 to 500 ft thick (Figure 2.3-1). Applications for commercial leasing using surface mining technologies will not be accepted in any other areas. Same as Alternative 2. Same as Alternative 2. Rationale: Surface mining will be allowed only in areas where the overburden is 0 to 500 ft thick 

because 500 ft is assumed to be the maximum amount of overburden where surface mining can occur economically, using today’s technologies. 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatWyoming: Green River RMP Amendment: Designate 210,000 acres of land within the most geologically prospective oil shale area, including split estate lands where the federal government owns the mineral rights, as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing by existing laws and regulations, Executive Orders, or administrative 

land use plan designation, or have not been specifically excluded by the BLM for other reasons, will be available for application for commercial leasing. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 2. 

None. Amendment: Designate 765,

the most geologically prospeincluding split estate lands wgovernment owns the minerapplication for leasing for codevelopment in accordance and state regulations and BLRationale: All lands within prospective oil shale area thcommercial leasing under Abe excluded under Alternatiestimate presented here reprexcluded from commercial lAlternative 4. 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatWyoming: Green River RMP (Cont.) Amendment: Specify that applications for commercial leases using surface mining technologies will be accepted only within an area of about 380,220 acres within the most geologically prospective oil shale area where overburden is 0 to 500 ft thick (Figure 2.3-1). Applications for commercial leasing using surface mining technologies will not be accepted in any other areas. Rationale: Surface mining will be allowed only in areas where the overburden is 0 to 500 ft thick 

because 500 ft is assumed to be the maximum amount of overburden where surface mining can occur economically, using today’s technologies. 

None. Same as Alternative 2. 

Wyoming: Kemmerer RMP 

Amendment: Designate 50,000 acres of land within the most geologically prospective oil shale area, including split estate lands where the federal government owns the mineral rights, as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. 

None. Amendment: Designate 144,

the most geologically prospeincluding split estate lands wgovernment owns the minerapplication for leasing for codevelopment in accordance and state regulations and BL
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatWyoming: Kemmerer RMP (Cont.) Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing by existing laws and regulations, Executive Orders, or administrative land use plan designation, or have not been specifically excluded by the BLM for other reasons, will be available for application for commercial leasing. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 2. Rationale: All lands within 

prospective oil shale area thcommercial leasing under Abe excluded under Alternatiestimate presented here reprexcluded from commercial lAlternative 4. Amendment: Specify that applications for commercial leases using surface mining 

technologies will not be accepted in the planning area. Rationale: Surface mining will be allowed only in areas where the overburden is 0 to 500 ft thick because 500 ft is assumed to be the maximum amount of overburden where surface mining can occur economically, using today’s technologies. In Wyoming, these lands fall within the Green River RMP planning area. 

None. Same as Alternative 2. 
TABLE C-1 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternatWyoming: Rawlins RMP Amendment: Designate 33,100 acres of land within the most geologically prospective oil shale area, including split estate lands where the federal government owns the mineral rights, as available for application for leasing for commercial oil shale development in accordance with applicable federal and state regulations and BLM policies. None. Amendment: Designate 59,0

the most geologically prospeavailable for application for oil shale development in accfederal and state regulations 

Rationale: All lands within the most geologically prospective oil shale area that are not excluded from commercial leasing by existing laws and regulations, Executive Orders, or administrative land use plan designation, or have not been specifically excluded by the BLM for other reasons, will be available for application for commercial leasing. The acreage estimate presented here represents those lands not excluded from commercial leasing under Alternative 2.

Rationale: All lands within prospective oil shale area thcommercial leasing under Abe excluded under Alternatiestimate presented here reprexcluded from commercial lAlternative 4. 

Amendment: Specify that applications for 

commercial leases using surface mining technologies will not be accepted in the planning area. Rationale: Surface mining will be allowed only in areas where the overburden is 0 to 500 ft thick, because 500 ft is assumed to be the maximum amount of overburden where surface mining can occur economically, using today’s technologies. In Wyoming, these lands fall within the Green River RMP planning area. 

None. Amendment: Specify that ap

commercial leases using surwill not be accepted in the pRationale: Surface mining wareas where the overburden because 500 ft is assumed to amount of overburden wheroccur economically, using toWyoming, these lands fall wRMP planning area. 

a Commercial leasing as used herein includes both commercial and RD&D leasing.
TABLE C-2 Proposed Land Use Plan Amendments and Rationale Associated with Alternatives 2 through 4 for Tar 

Proposed Amendment and Rationale Alternative 2 Alternative 3 Altern

Utah: Monticello RMP Amendment: Designate the following amounts of land within the specific Special Tar Sand Areas (STSAs) as available for application for leasing for commercial tar sands development in accordance with applicable federal and state regulations and BLM policies: White Canyon: 45 acres Rationale: All lands within the designated STSAs that are not excluded from commercial leasing by existing laws and regulations, 

Executive Orders, or administrative land use plan designation, or have not been specifically excluded by the BLM for other reasons, will be available for application for commercial leasing. In addition, lands that are identified as requiring special management or resource protection in existing land use plans also will be excluded in order to provide maximum protection to the resources in those areas. The acreage estimates presented here represent those lands not excluded from commercial leasing under Alternative 2. 

None. Amendment: Designate t

land within the specific application for leasing fodevelopment in accordanfederal and state regulatiWhite Canyon: 7,001 acRationale: All lands witSTSAs that are not excluleasing under Alternativexcluded under Alternatestimates presented here not excluded from commAlternative 4. 
TABLE C-2 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternUtah: Price RMP Amendment: Designate the following amounts of land within the specific STSAs as available for application for leasing for commercial tar sands development in accordance with applicable federal and state regulations and BLM policies: Sunnyside: 20,400 acres San Rafael: 8,961 acres None. Amendment: Designate t

land within the specific application for leasing fodevelopment in accordanfederal and state regulatiSunnyside: 72,360 acres San Rafael: 72,146 acres Utah: Richfield RMP Amendment: Designate the following amounts of land within the specific STSAs as available for 

application for leasing for commercial tar sands development in accordance with applicable federal and state regulations and BLM policies: Tar Sand Triangle: 101 acres 

None. Amendment: Designate t

land within the specific application for leasing fodevelopment in accordanfederal and state regulatiTar Sand Triangle: 24,93
TABLE C-2 (Cont.) Proposed Amendment and Rationale Alternative 2 Alternative 3 AlternUtah: Vernal RMP Amendment: Designate the following amounts of land within the specific STSAs as available for application for leasing for commercial tar sands development in accordance with applicable federal and state regulations and BLM policies: Asphalt Ridge: 2,123 acres Hill Creek: 45,357 acres Pariette: 830 acres P.R. Spring: 42,631 acres Raven Ridge: 9,119 acres Amendment: Designate the following amounts of land within the specific STSAs as available for application for leasing for commercial tar sands development in accordance with applicable federal and state regulations and BLM policies: Asphalt Ridge: 2,123 acres Amendment: Designate t

land within the specific application for leasing fodevelopment in accordanfederal and state regulatiArgyle Canyon: 12,296 Asphalt Ridge: 5,435 acHill Creek: 62,152 acres Pariette: 10,161 acres P.R. Spring: 154,516 acrRaven Ridge: 14,364 acr

a Commercial leasing as used herein includes both commercial and RD&D leasing. 
Final OSTS PEIS C-20 

REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

BLM (Bureau of Land Management), 1987, Grand Junction Resource Area Resource 

Management Plan and Record of Decision, Grand Junction District, Colo., Jan. 

BLM, 1988, Record of Decision and Resource Management Plan, Glenwood Springs Resource 

Area, Grand Junction District, Colo., June. 

BLM, 1997a, White River Record of Decision and Approved Resource Management Plan, White 

River Resource Area, Colo., Craig District, Meeker, Colo., July. 

BLM, 1997b, Record of Decision and Green River Resource Management Plan, Green River 

Resource Area, Rock Springs District Office, Wyo., Oct. 

BLM, 2006a, Roan Plateau Planning Area, Including Former Naval Oil Shale Reserves 

Numbers 1 & 3, Resource Management Plan Amendment & Environmental Impact Statement, 

Final, Colorado State Office, Aug. Available at http://www.blm.gov/rmp/co/roanplateau/ 

final_eis_document.htm. 

BLM, 2006b, Record of Decision and Jack Morrow Hills Coordinated Activity Plan/Proposed 

Green River Resource Management Plan Amendment, Rock Springs Field Office, Wyo., July. 

BLM, 2007, Record of Decision for the Approval of Portions of the Roan Plateau Management 

Plan Amendment and Environmental Impact Statement, Glenwood Springs Field Office, Colo., 

June. 

BLM, 2008a, Record of Decision for the Resource Management Plan Amendment for Portions of 

the Roan Plateau Planning Area Designated as Areas of Critical Environmental Concern Public 

Lands in Garfield County, CO, March. 

BLM, 2008b, Proposed Resource Management Plan and Final Environmental Impact Statement 

for the Price Field Office, Price Field Office, Utah, Aug. 

BLM, 2008c, Proposed Resource Management Plan Revision and Final Environmental Impact 

Statement for the Vernal Field Office Planning Area, Vernal Field Office, Utah, Aug. 

BLM, 2008d, Record of Decision and Approved Resource Management Plan, Rawlins District 

Office, Great Divide Resource Area, Wyo. 

BLM, 2008e, Proposed Resource Management Plan and Final Environmental Impact Statement, 

Monticello Field Office, Utah, Aug. 
Final OSTS PEIS C-21 

BLM, 2008f, Richfield Field Office Proposed Resource Management Plan & Final 

Environmental Impact Statement, Richfield Field Office, Utah, Aug. 

BLM, 2008g, Approved Resource Management Plan Amendments/Record of Decision (ROD) for 

Oil Shale and Tar Sands Resources To Address Land Use Allocations in Colorado, Utah, and 

Wyoming and Final Programmatic Environmental Impact Statement, Nov. 17. 

BLM, 2008h, Proposed Oil Shale and Tar Sands Resource Management Plan Amendments to 

Address Land Use Allocation in Colorado, Utah, and Wyoming and Final Programmatic 

Environmental Impact Statement, FES 08-32, Sept. Available at http://ostseis.anl.gov/. 

BLM, 2010 Record of Decision for the Kemmerer Resource Management Plan and Rangeland 

Program Summary Document, Kemmerer Resource Area, Rock Springs District, Wyo. 
Final OSTS PEIS C-22 

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Final OSTS PEIS D-1 

APPENDIX D: 

FEDERAL, STATE, AND COUNTY REGULATORY REQUIREMENTS 

POTENTIALLY APPLICABLE TO OIL SHALE AND TAR SANDS 

DEVELOPMENT PROJECTS 

 
Final OSTS PEIS D-2 

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Final OSTS PEIS D-3 

APPENDIX D: 

FEDERAL, STATE, AND COUNTY REGULATORY REQUIREMENTS 

POTENTIALLY APPLICABLE TO OIL SHALE AND TAR SANDS 

DEVELOPMENT PROJECTS 

D.1 REGULATORY CITATIONS AND STATUTORY AUTHORITIES 

The tables that follow list the major federal, state, and county laws, Executive Orders, 

and other compliance instruments that establish permits, approvals, or consultations that may 

apply to the construction and operation of either an oil shale development project or development 

within a Special Tar Sand Area on public lands in Colorado, Utah, and Wyoming. The general 

application of these federal, state, and county authorities and other regulatory considerations 

associated with such construction and operation are discussed in Chapter 2. 

 Tables D-1 through D-15 are organized by general environmental impact categories. The 

citations in the tables are those of the general statutory authority that governs the indicated 

category of activities to be undertaken under the proposed action and alternatives. Under such 

statutory authority, the lead federal, state, or county agency may have promulgated implementing 

regulations that set forth the detailed procedures for permitting and compliance. Table D-16 

gives the federal and state leasing and permitting requirements applicable to Colorado, Utah, and 

Wyoming. 

Definitions of abbreviations used in the tables are provided here. 

App. Appendix 

BLM Bureau of Land Management 

CCDC Carbon County Development Code (Carbon County, Utah)

CFR Code of Federal Regulations 

CRS Colorado Revised Statues

DCC Duchesne County Code (Duchesne County, Utah) 

ECGP Emery County General Plan (Emery County, Utah) 

ECZO Emery County Zoning Ordinance (Emery County, Utah) 

GCLUC Grand County Land Use Code (Grand County, Utah)

GCLUR Garfield County Land Use Resolution (draft) (Garfield County, Colorado) 
Final OSTS PEIS D-4 

LCLUR Lincoln County Land Use Regulations (Lincoln County, Wyoming)

MCMP Moffat County Master Plan (Moffat County, Colorado) 

NA Not applicable 

P.L. Public Law 

RBCLUR Rio Blanco County Land Use Resolution (Rio Blanco County, Colorado)

RBCMP Rio Blanco County Master Plan (Rio Blanco County, Colorado) 

SCDUDC Sweetwater County Draft Unified Development Code (Sweetwater County, 

Wyoming)

SCZDRR Sublette County Zoning and Development Regulations Resolutions

(Sublette County, Wyoming) 

SJCZO San Juan County Zoning Ordinance (San Juan County, Utah) 

UCA Utah Code Annotated (Grand County, Utah) 

UCC Utah County Code (Utah County, Utah)

UCUC Uintah County Utah Code (Uintah County, Utah) 

USC United States Code

WCLUR Wayne County Land Use Ordinances and Land Use Regulations 

WCC Wasatch County Code (Wasatch County, Utah)

WS Wyoming Statutes
Final OSTS PEIS D-5 

TABLE D-1 Air Quality 

Authority Citation 

 

Federal • Clean Air Act (42 USC 7401 et seq.) 

 

Colorado 

 State 

 County 

• Air Quality Control (CRS 25-7-101 et seq.) 

• Garfield County: Air Quality (GCLUR 7-208) 

• Rio Blanco County: Air (RBCLUR 258) 

 

Utah 

 State 

 County 

• Air Conservation Act (UCA 19-2-101 et seq.) 

• Carbon County: NA 

• Duchesne County: Extraction of Earth Products (DCC 17.52.052) 

• Emery County: NA 

• Garfield County: NA 

• Grand County: NA 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: NA 

• Wasatch County: Prohibition of Undesirable Emissions (WCC 16.28.02) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Air Quality (WS 35-11-201 et seq.) 

• Lincoln County: NA 

• Sublette County: Air Quality (SCZDRR Ch. III, Sec. 17) 

• Sweetwater County: NA 

• Uinta County: NA 
Final OSTS PEIS D-6 

TABLE D-2 Cultural Resources and Native Americans 

Authority Citation 

 

Federal • Native American Graves Protection and Repatriation Act (25 USC 3001 et seq.) 

• American Indian Religious Freedom Act (42 USC 1996 et seq.) 

• Archaeological Resources Protection Act (16 USC 470(aa) et seq.) 

• Archaeological and Historic Preservation Act (16 USC 469 et seq.) 

• Historic Sites, Buildings, and Antiquities Act (Historic Sites Act) (16 USC 461 et seq.) 

• Antiquities Act (16 USC 431 et seq.) 

• National Historic Preservation Act (16 USC 470 et seq.) 

• Theft and Destruction of Government Property (18 USC 641 et seq., 1361 et seq.) 

• Executive Order 11593, “Protection and Enhancement of the Cultural Environment,” 

May 15, 1971 (U.S. President 1971) 

• Executive Order 13007, “Indian Sacred Sites,” May 29, 1996 (U.S. President 1996b) 

• Executive Order 13175, “Consultation and Coordination with Indian Tribal Governments,” 

November 9, 2000 (U.S. President 2000) 

• Executive Order 13287, “Preserve America,” March 5, 2003 (U.S. President 2003) 

 

Colorado 

 State 

 County 

• Historical, Prehistorical, and Archeological Resources (CRS 24-80-401 et seq.) 

• Unmarked Human Graves (CRS 24-80-1301 et seq.) 

• Garfield County: Areas with Archaeological, Paleontological, or Historical Importance 

(GCLUR 7-211) 

• Rio Blanco County: Policy H & CR-1A through 1G (RBCMP) 

 

Utah 

 State 

 County 

• History Development (UCA 9-8-102 et seq.) 

• Native American Graves Protection and Repatriation Act (UCA 9-9-102 et seq.) 

• Carbon County: HMC Historic Mining Camp Zone (CCDC 4.2.21) 

• Duchesne County: NA 

• Emery County: Position StatementPreservation of Cultural and Historical Heritage Resources 

(ECGP p. 36) 

• Garfield County: NA 

• Grand County: NA 

• San Juan County: NA 

• Uintah County: Historic Preservation Commission (UCUC 2.24) 

• Utah County: Historic Preservation Commission (UCC 25) 

• Wasatch County: NA 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Protection of Prehistoric Ruins (WS 36-1-114 et seq.) 

• Lincoln County: NA 

• Sublette County: NA 

• Sweetwater County: NA 

• Uinta County: NA 
Final OSTS PEIS D-7 

TABLE D-3 Energy Project Siting 

Authority Citation 

 

Federal • Natural Gas Act (15 USC 717 et seq.) 

• Natural Gas Policy Act (15 USC 3301 et seq.) 

• Federal Power Act (16 USC 791a et seq.) 

• Public Utilities Regulatory Policies Act (16 USC 2601 et seq.) 

• Energy Supply and Environmental Coordination Act (15 USC 791 et seq.) 

• Energy Policy and Conservation Act (42 USC 6201 et seq.) 

• Surface Mining Control and Reclamation Act (30 USC 1201 et seq.) 

• Accountable Pipeline Safety and Partnership Act of 1996 (49 USC 60101 et seq.) 

• Energy Policy Act of 2005 (P.L. 109-58) 

• Executive Order 12898, “Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations,” February 16, 1994 (U.S. President 1994) 

 

Colorado 

 State 

 County 

• Local Government RegulationLocation, Construction, or Improvement of Major Electrical or 

Natural Gas FacilitiesLegislative Declaration (CRS 29-20-108) 

• Garfield County: Fiscal Impact Mitigation Program (GCLUR Article IV, Division 5) 

• Rio Blanco County: NA 

 

Utah 

 State 

 County 

• Electric Power Facilities Act (UCA 54-9-101 et seq.) 

• Natural Gas Pipeline Safety Act (UCA 54-13-1 et seq.) 

• Electricity Facility Review Board Act (UCA 54-14-101 et seq.) 

• Carbon County: Major Underground and Surface Mine Developments (CCDC 5.4); Major 

Utility Transmissions and Railroad Projects (CCDC 5.5) 

• Duchesne County: NA 

• Emery County: Mining, Grazing, and Recreation (MG &R-1) Zone (ECZO 9-4); Gas and Oil 

Wells (ECZO 11-2-1); Oil and Gas Operation (ECZO 11-3-4); and Position StatementOil and 

Gas Exploration and Production (ECGP p. 31) 

• Garfield County: NA 

• Grand County: Site Development Standards (GCLUC 6) 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: NA 

• Wasatch County: NA 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Industrial Development and Siting (WS 35-12-101 et seq.) 

• Electric Utilities (WS 37-16-101 et seq.) 

• Wyoming Energy Commission (WS 30-7-101) 

• Lincoln County: NA 

• Sublette County: NA 

• Sweetwater County: Commercial Wind Energy Conversion Systems (SCDUDC X.7) 

• Uinta County: NA 
Final OSTS PEIS D-8 

TABLE D-4 Floodplains and Wetlands 

Authority Citation 

 

Federal • Clean Water Act (33 USC 1344) 

• Rivers and Harbors Act of 1899 (33 USC 401 et seq.) 

• Executive Order 11988, “Floodplain Management,” May 25, 1977 

(U.S. President 1977a) 

• Executive Order 11990, “Protection of Wetlands,” May 24, 1977 (U.S. President 

1977b)

 

Colorado 

 State 

 County 

• Drainage of State Lands (CRS 37-30-101 et seq.) 

• Marsh Land (CRS 37-33-101 et seq.) 

• Colorado Mined Land Reclamation Act (CRS 34-32-101 et seq.) 

• Garfield County: Protection of Wetlands and Waterbodies (GCLUR 7-203) 

• Rio Blanco County: Wetlands (RBCLUR 256) 

 

Utah 

 State 

 County 

• Plan Preparation (UCA 10-9a-403) 

• Plan Preparation (UCA 17-27a-403) 

• Carbon County: FPO (Floodplain Overlay Zone) (CCDC 4.2.22) 

• Duchesne County: NA 

• Emery County: Wetlands (ECGP p. 80) 

• Garfield County: NA 

• Grand County: Floodplains, Natural, and Historic Drainages (GCLUC 6.8) 

• San Juan County: Construction Subject to Geologic, Flood, or Other Natural 

Hazard (SJCZO 9-1) 

• Uintah County: Floodplain Regulations (UCUC 17.84); Flood Hazard Areas 

(UCUC 14.12) 

• Utah County: NA 

• Wasatch County: Stream Corridor/Wetland Development Standards 

(WCC 16.28.04) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Legislative Policy and Intent (WS 35-11-309 et seq.) 

• Application for Permit; Generally; Denial; Limitations 

(WS 35-11-406 (b)(v); (xv)) 

• Lincoln County: Flood Overlay (LCLUR App. I) 

• Sublette County: Flood Areas (SCZDRR Ch. III, Sec. 13) 

• Sweetwater County: Nature of Surface Water Facilities (SCDUDC IX.4.2) 

• Uinta County: NA 
Final OSTS PEIS D-9 

TABLE D-5 Groundwater, Drinking Water, and Water Rights 

Authority Citation 

 

Federal • Safe Drinking Water Act (42 USC 300(f) et seq.) 

 

Colorado 

 State 

 County 

• Water Right Determination and Administration (CRS-37-92-101 et seq.) 

• Reservoirs (CRS 37-87-101 et seq.) 

• Underground Water (CRS 37-90-101 et seq.) 

• Water Well Construction and Pump Installation Contractors (CRS 37-91-101 et seq.) 

• Water Quality Control (CRS 25-8-101 et seq.) 

• Colorado Mined Land Reclamation Act (CRS 34-32-101 et seq.) 

• Garfield County: NA 

• Rio Blanco County: NA 

 

Utah 

 State 

 County 

• Safe Drinking Water Act (UCA 19-4-101 et seq.) 

• Ground Water Recharge and Recovery Act (UCA 73-3b-101 et seq.) 

• Appropriation (UCA 73-3-1 et seq.) 

• Determination of Water Rights (UCA 73-4-1 et seq.) 

• Withdrawal of Unappropriated Water (UCA 73-6-1 et seq.) 

• Carbon County: Culinary Water (CCDC 6.7.2) 

• Duchesne County: NA 

• Emery County: Water Quality and Quantity (ECGP p. 57); Water Rights/Allocation 

(ECGP p. 59); and Groundwater (ECGP p. 76) 

• Garfield County: NA 

• Grand County: NA 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: Potable Water (UCC 13-4-3-4); Wells (UCC 17-3-3-8) 

• Wasatch County: Adequate Water Rights Required (WCC 10.01.01) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Water Rights; Administration and Control (WS 41-3-101) 

• Board of Control; Adjudication of Water Rights (WS 41-4-101) 

• Prohibited Acts (WS 35-11-301 et seq.) 

• Protection of the Surface Owner (WS 35-11-416(b)) 

• Lincoln County: Wellhead and Source Water Protection Standards (LCLUR 6.27) 

• Sublette County: Water Supply and Distribution Systems (SCZDRR Ch. III, Sec. 2); 

• Sweetwater County: Public Water Construction and Installation Requirements 

(SCDUDC IX.5.3); Private Wells and Water Systems (SCDUDC IX.5.4); Easements for Public 

Water, Sewer, Drainage, and Other Utilities (SCDUDC IX.5.6) 

• Uinta County: NA 
Final OSTS PEIS D-10 

TABLE D-6 Hazardous Materials 

Authority Citation 

 

Federal • Hazardous Materials Transportation Act (49 USC 5101 et seq.) 

• Emergency Planning and Community Right-to-Know Act of 1986 (42 USC 11001 et seq.) 

• Oil Pollution Control Act (33 USC 2701 et seq.) 

• Pollution Prevention Act of 1990 (42 USC 13101 et seq.) 

• Comprehensive Environmental Response, Compensation, and Liability Act (42 USC 9601 et seq.) 

• Executive Order 12856, “Federal Compliance with Right-to-Know Laws and Pollution Prevention 

Requirements,” August 6, 1993 (U.S. President 1993) 

 

Colorado 

 State 

 County 

• Implementation of Title III of Superfund Act (CRS 24-32-2601 et seq.) 

• Hazardous Substances (CRS 25-5-501 et seq.) 

• Pollution Prevention (CRS 25-16.5-101 et seq.) 

• Colorado Mined Land Reclamation Act (CRS 34-32-101 et seq.) 

• Garfield County: Additional Standards Applicable to Storage Areas and Facilities 

(GCLUR 7-819) 

• Rio Blanco County: NA 

 

Utah 

 State 

 County 

• Hazardous MaterialsTransportation Regulations (UCA 41-6a-1639) 

• Hazardous Materials EmergencyRecovery of Expenses (UCA 53-2-105) 

• Carbon County: NA 

• Duchesne County: Title 3, Chapter 1, Nuisance Ordinance, DCC 

• Emery County: NA 

• Garfield County: NA 

• Grand County: Waste Materials Management (GCLUC 3.2.4L) 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: Hazardous Materials (UCC 9-7) 

• Wasatch County: Hazardous Materials Planning (WCC 7.09) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Authority of Department to Adopt Rules and Regulations Governing Drivers, Equipment, and 

Hazardous Materials (WS 31-18-303) 

• Application for Permit; Generally; Denial; Limitations (WS 35-11-406 (b)(ix)) 

• Mineral Mining Permits and Testing Licenses (WS 35-11-426) 

• Lincoln County: NA 

• Sublette County: NA 

• Sweetwater County: NA 

• Uinta County: NA 
Final OSTS PEIS D-11 

TABLE D-7 Hazardous Waste and Polychlorinated Biphenyls 

Authority Citation 

 

Federal • Solid Waste Disposal Act, as amended by the Resource Conservation 

and Recovery Act and the Hazardous Solid Waste Amendments of 1984 

(42 USC 6901 et seq.) 

• Toxic Substances Control Act (15 USC 2605(e)) 

 

Colorado 

 State 

 County 

• Hazardous Waste (CRS 25-15-101 et seq.) 

• Colorado Mined Land Reclamation Act (CRS 34-32-101 et seq.) 

• Garfield County: NA 

• Rio Blanco County: NA 

 

Utah 

 State 

 County 

• Solid and Hazardous Waste Act (UCA 19-6-101 et seq.) 

• Carbon County: NA 

• Duchesne County: NA 

• Emery County: NA 

• Garfield County: NA 

• Grand County: Waste Transport and Transporters (GCLUC 3.2.4L.2) 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: NA 

• Wasatch County: Solid Waste (WCC 13) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Solid Waste Management (WS 35-11-501 et seq.) 

• Lincoln County: NA 

• Sublette County: NA 

• Sweetwater County: NA 

• Uinta County: NA 
Final OSTS PEIS D-12 

TABLE D-8 Land Use 

Authority Citation 

 

Federal • Federal Land Policy and Management Act of 1976 (43 USC 1701 et seq.) 

• Mineral Leasing Act (30 USC 181 et seq.) 

• Coastal Zone Management Act, as amended by Coastal Zone Reauthorization Amendments of 

1990 (16 USC 1451 et seq.) 

• Wild and Scenic Rivers Act (16 USC 1271 et seq.) 

• National Trails System Act (16 USC 1241 et seq.) 

• National Park Service Organic Act (16 USC 1 et seq.) 

• Wilderness Act (16 USC 1311 et seq.) 

• Federal Land Exchange Facilitation Act (43 USC 1716) 

• Federal Land Transaction Facilitation Act (43 USC 2301 et seq.) 

• Farmland Protection and Policy Act (7 USC 4201) 

• Soil and Water Resources Conservation Act of 1977 (16 USC 2001 et seq.) 

• Oregon and California Grant Lands Act of 1937 (43 USC 1181(a, b, df)) 

• An Act to Establish the Glen Canyons National Recreation Area in the States of Arizona and 

Utah (16 USC 460(dd)) 

 

Colorado 

 State 

 County 

• Areas and Activities of State Interest (CRS 24-65.1-101 et seq.) 

• Local Government Land Use Control Enabling Act (CRS 29-20-101 et seq.) 

• County Planning (CRS 30-28-101 et seq.) 

• (Municipal) Planning and Zoning (CRS 31-23-101 et seq.) 

• Colorado Mined Land Reclamation Act (CRS 34-32-101 et seq.) 

• Garfield County: Fiscal Impact Mitigation Program (GCLUR Article IV, Division 5) 

• Rio Blanco County: Process Generation, Collection, and Distribution Systems (RBCLUR 407); 

Special and Conditional-Use Permits (RBCLUR 54) 

 

Utah 

 State 

 County 

• Quality Growth Act (UCA 11-38-101 et seq.) 

• Environmental Institutional Control Act (UCA 19-10-101 et seq.) 

• Municipal Land Use, Development, and Management (UCA 10-9a-101 et seq.) 

• County Land Use, Development, and Management (UCA 17-27a-101 et seq.) 

• Critical Land near State Prison: Definitions – Preservation as Open Land – Management and 

Use of Land – Restrictions on Transfer – Wetlands Development – Conservation Easement 

(UCA 23A-5-222) 

• Utah Mined Land Reclamation Act (UCA 40-8-1 et seq.) 

• Carbon County: Carbon County Development Code 

• Duchesne County: Conditional Use Permit (DCC 17.52) 

• Emery County: Zoning Ordinance for Emery County; Public Lands, Federal and State Agencies 

(ECGP p. 16) 

• Garfield County: Zoning Ordinance 

• Grand County: Zoning District Regulation (GCLUC 2) 

• San Juan County: San Juan County Zoning Ordinance 

• Uintah County: Mining and Grazing Zone (UCUC 17.60) 

• Utah County: Utah County Land Use Ordinance; Agriculture Protection Area (UCC 26) 

 
Final OSTS PEIS D-13 

TABLE D-8 (Cont.) 

Authority Citation 

 

Utah 

(Cont.) 

 County • Wasatch County: Land Use and Development Code (WCC 16) 

• Wayne County: General Development Standards Applicable to All Property and Land Uses 

(WCLUR 16) 

 

Wyoming 

 State 

 County 

• Land Quality (WS 35-11-401 et seq.) 

• Mineral Leases (WS 36-6-101 et seq.) 

• Carey Act Lands (WS 36-7-101 et seq.) 

• Sale of State Lands (WS 36-9-101 et seq.) 

• United States Lands (WS 36-10-101 et seq.) 

• State Control of Certain Land (WS 36-12-101 et seq.) 

• Counties Planning and Zoning (WS 18-5-101 et seq.) 

• Abandoned Mine Reclamation Program (WS 35-11-1201 et seq.) 

• Lincoln County: Lincoln County Land Use Regulations 

• Sublette County: Conformity with Development Standards (SCZDRR Ch. III, Sec. 1); Mining 

Operations (SCZDRR Ch. III, Sec. 21) 

• Sweetwater County: Sweetwater Draft Unified Development Code; Sweetwater County Zoning 

Resolution 

• Uinta County: Land Use Certificate 
Final OSTS PEIS D-14 

TABLE D-9 Noise 

Authority Citation 

 

Federal • Noise Control Act, as amended by Quiet Communities Act (42 USC 4901 et seq.) 

 

Colorado 

 State 

 County 

• Noise Abatement (CRS 25-12-101 et seq.) 

• Garfield County: Submittal Requirements (GCLUR Article IV, Division 5) 

• Rio Blanco County: Noise (RBCLUR 260) 

 

Utah 

 State 

 County 

• No specific primary statutory authority 

• Carbon County: NA 

• Duchesne County: Nuisance Ordinance (DCC, Title 3, Chapter 1, Section 4(G)) 

• Emery County: NA 

• Garfield County: NA 

• Grand County: Noise (GCLUC 6.12.3) 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: Unreasonable Noise (UCC 12-3) 

• Wasatch County: Noise Ordinance (WCC 12.03) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• No specific primary statutory authority 

• Lincoln County: NA 

• Sublette County: Noise (SCZDRR Ch. III, Sec. 14) 

• Sweetwater County: NA 

• Uinta County: NA 
Final OSTS PEIS D-15 

TABLE D-10 Pesticides and Noxious Weeds 

Authority Citation 

 

Federal • Federal Insecticide, Fungicide, and Rodenticide Act (7 USC 136 et seq.) 

• Noxious Weed Act of 1974, as amended by Section 15Management of Undesirable Plants on 

Federal Lands, 1990 (7 USC 2801 et seq.) 

 

Colorado 

 State 

 County 

• Pesticide Act (CRS 35-9-101 et seq.) 

• Colorado Mined Land Reclamation Act (CRS 34-32-101 et seq.) 

• Garfield County: Fiscal Impact Mitigation Program (GCLUR Article IV, Division 5) 

• Rio Blanco County: Weeds and Invasive Species (RBCLUR 261) 

 

Utah 

 State 

 County 

• Utah Pesticide Control Act (UCA 4-14-1 et seq.) 

• Carbon County: NA 

• Duchesne County: (no title available) (DCC Title 3, Chapter 5) 

• Emery County: NA 

• Garfield County: NA 

• Grand County: Grading, Revegetation, and Restoration (GCLUC 6.9.9) 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: Standards of Weed Control (UCC 12-2-9) 

• Wasatch County: Weed Control (WCC 12.02) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Weed and Pest Control (WS 11-5-101 et seq.) 

• Lincoln County: Wyoming Statutes, Weed Control and Agricultural Uses (LCLUR App. I) 

• Sublette County: NA 

• Sweetwater County: NA 

• Uinta County: NA 
Final OSTS PEIS D-16 

TABLE D-11 Solid Waste 

Authority Citation 

 

Federal • Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act 

and the Hazardous Solid Waste Amendments of 1984 (42 USC 6901 et seq.) 

 

Colorado 

 State 

 County 

• Solid Waste Disposal Sites and Facilities (CRS 30-20-100.5 et seq.) 

• Garfield County: Additional Standards Applicable to Solid Waste Disposal Sites 

(GCLUR 7-818) 

• Rio Blanco County: Waste Disposal (RBCLUR 257) 

 

Utah 

 State 

 County 

• Solid Waste Management Act (UCA 19-6-501 et seq.) 

• Carbon County: NA 

• Duchesne County: DCC, Title 3, Chapter 4 

• Emery County: NA 

• Garfield County: NA 

• Grand County: Waste Materials Management (GCLUC 3.2.4L) 

• San Juan County: NA 

• Uintah County: Sanitation—Management of Solid Waste (UCUC 8.24) 

• Utah County: Solid Waste (UCC 20) 

• Wasatch County: Solid Waste (WCC 13) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Solid Waste Management (WS 35-11-501 et seq.) 

• Solid Waste Disposal Districts (WS 18-11-101 et seq.) 

• Definitions (WS 35-11-103 (d)(ii)) 

• Lincoln County: Solid Waste Disposal (LCLUR Sec 6.24) 

• Sublette County: Sanitary Landfills (SCZDRR Ch. III, Sec. 24) 

• Sweetwater County: Debris and Waste (SCDUDC IX.2.5) 

• Uinta County: NA 
Final OSTS PEIS D-17 

TABLE D-12 Source Water Protection 

Authority Citation 

 

Federal • Safe Drinking Water Act (42 USC 300h et seq.) 

 

Colorado 

 State 

 County 

• Water Quality Control (CRS 25-8-101 et seq.) 

• Garfield County: Protection of Water Quality from Pollutants (GCLUR 7-204) 

• Rio Blanco County: NA 

 

Utah 

 State 

 County 

• Water Quality Act (UCA 19-5-101 et seq.) 

• Carbon County: Culinary Water (CCDC 6.7.2) 

• Duchesne County: NA 

• Emery County: Water Quality and Quantity (ECGP p. 57) 

• Garfield County: NA 

• Grand County: Water Supply (GCLUC 7.8) 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: Water Systems Operated by Utah County (UCC 27); Emergency Water 

 Supplies (UCC 9-6-3) 

• Wasatch County: Water Quality (WCC 16.28.03) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Protection of Public Water Supply (WS 35-4-201 et seq.) 

• Prohibited Acts (WS 35-11-301 et seq.) 

• Application for Permit; Generally; Denial; Limitations (WS 35-11-406 (b)(ix)) 

• Lincoln County: Wellhead and Source Water Protection Standards (LCLUR 6.27) 

• Sublette County: NA 

• Sweetwater County: Water Supply (SCDUDC IX.1.4.2) 

• Uinta County: NA 
Final OSTS PEIS D-18 

TABLE D-13 Water Bodies and Wastewater 

Authority Citation 

 

Federal • Clean Water Act (33 USC 1251 et seq.) 

 

Colorado 

 State 

 County 

• Water Quality Control (CRS 25-8-101 et seq.) 

• Water and Wastewater Treatment Plant Operations (CRS 25-9-101 et seq.) 

• Colorado Mined Land Reclamation Act (CRS 34-32-101 et seq.) 

• Garfield County: Adequate Water Distribution and Wastewater Systems 

 (GCLUR 7-105); Stormwater Run-Off (GCLUR 7-207) 

• Rio Blanco County: Water Quality, Stormwater, Drainage (RBCLUR 255) 

 

Utah 

 State 

 County 

• Water Quality Act (UCA 19-5-101 et seq.) 

• Carbon County: Sewers (CCDC 6.7.3); Storm Drains and Facilities (CCDC 6.7.2) 

• Duchesne County: (Title 3, Chapter 1) 

• Emery County: Water Quality and Quantity (ECGP p. 57); Conveyance Systems 

 (ECGP p. 63); In-Stream Flow (ECGP p. 63); and Salinity (ECGP p. 65) 

• Garfield County: NA 

• Grand County: Sewage Disposal (GCLUC 5.8) 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: Location of Sewers (UCC 17-3-3-4); Ditches and Waterways 

 (UCC 17-3-3-5); and Protection of Watercourses (UCC 17-5-3-7) 

• Wasatch County: Water Quality (WCC 16.28.03); Wastewater Disposal Systems 

 (WCC 10.02) 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• Water Quality (WS 35-11-301 et seq.) 

• Application for Permit; Generally; Denial; Limitations (WS 35-11-406 (b)(ix)) 

Aquatic Invasive Species (WS 23-4-201 through 205) 

• Lincoln County: Small Wastewater Facility Permit (LCLUR 2.5.C); Small 

Wastewater Design Standards, Land Use Regulations (LCLUR App. E) 

• Sublette County: Erosion Control (SCZDRR Ch. III, Sec. 11); Drainage (SCZDRR 

 Ch. III, Sec. 12) 

• Sweetwater County: Wastewater and Sewage (SCDUDC IX.1.2.3); Storm Water 

Management (SCDUDC IX.1.2.4); Waterbodies and Watercourses (SCDUDC IX.2.6); 

Drainage and Storm Sewers (SCDUDC IX.4); and Water and Sewer Facilities 

(SCDUDC IX.5) 

• Uinta County: NA 
Final OSTS PEIS D-19 

TABLE D-14 Wildlife and Plants 

Authority Citation 

 

Federal • Fish and Wildlife Coordination Act (16 USC 661 et seq.) 

• Bald and Golden Eagle Protection Act (16 USC 668 et seq.) 

• National Wildlife Refuge System Administration Act (16 USC 668dd) 

• Migratory Bird Treaty Act (16 USC 703 et seq.) 

• Endangered Species Act (16 USC 1531 et seq.) 

• Wild Free-Roaming Horses and Burros Act (16 USC 1331 et seq.) 

• Executive Order 12996, “Management and General Public Use of the National Wildlife 

Refuge System,” March 28, 1996 (U.S. President 1996c) 

• Executive Order 13112, “Invasive Species,” February 8, 1999 (U.S. President 1999) 

• Executive Order 13186, “Responsibilities of Federal Agencies to Protect Migratory Birds,” 

January 17, 2001 (U.S. President 2001) 

 

Colorado 

 State 

 County 

• Nongame and Endangered Species Conservation (CRS 33-2-101 et seq.) 

• Migratory Birds, Possession of Raptors, Reciprocal Agreements (CRS 33-1-115) 

• Protection of Fishing Streams (CRS 33-5-101 et seq.) 

• Nongame and Endangered Species Conservation (CRS 33-2-101 et seq.) 

• Colorado Natural Areas (CRS 33-33-101 et seq.) 

• Colorado Mined Land Reclamation Act (CRS 34-32-101 et seq.) 

• Garfield County: Protection of Wildlife Habitat Areas (GCLUR 7-202); Additional 

Standards Applicable to Mining and Extraction Uses (GCLUR 7-813) 

• Rio Blanco County: Wildlife (RBCLUR 259) 

 

Utah 

 State 

 County 

• Wildlife Resources Code of Utah (UCA 23-13-1 et seq.) 

• Carbon County: NA 

• Duchesne County: NA 

• Emery County: Position StatementWilderness Designations and Other Public Lands 

 Management Considerations (ECGP p. 19) 

• Garfield County: NA 

• Grand County: NA 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: Wild Animals (UCC 5-2-10) 

• Wasatch County: Wildlife Habitat Protection (WCC 16.28.05) 

• Wayne County: NA 

 

Wyoming 

 State • Bird and Animal Provisions (WS 23-3-101 et seq.) 

• Predatory AnimalsControl Generally (WS 11-6-101 et seq.) 

• Application for Permit; Generally; Denial; Limitations (WS 35-11-406 (a)(vii)) 

Aquatic Invasive Species (WS 23-4-201 through 205) 

• Executive Order 2011-5 State of Wyoming Greater Sage-Grouse Core Area Protection 
Final OSTS PEIS D-20 

TABLE D-14 (Cont.)

Authority Citation 

 

Wyoming 

(Cont.) 

 County • Lincoln County: NA 

• Sublette County: NA 

• Sweetwater County: Preservation of Natural Features and Amenities (SCDUDC IX.9) 

• Uinta County: NA 
Final OSTS PEIS D-21 

TABLE D-15 Visual Resources 

Authority Citation 

 

Federal • Federal Land Policy and Management Act of 1976 (43 USC 7401 et seq.) 

 

Colorado 

 State 

 County 

• NA 

• Garfield County: NA 

• Rio Blanco County: Policy OP/PL – 2A (RBCMP) 

 

Utah 

 State 

 County 

• NA 

• Carbon County: NA 

• Duchesne County: NA 

• Emery County: NA 

• Garfield County: NA 

• Grand County: Operational Performance Standards, General (GCLUC Sec. 6.12.2) 

• San Juan County: NA 

• Uintah County: NA 

• Utah County: NA 

• Wasatch County: NA 

• Wayne County: NA 

 

Wyoming 

 State 

 County 

• NA 

• Lincoln County: NA 

• Sublette County: NA 

• Sweetwater County: NA 

• Uinta County: NA 
Final OSTS PEIS D-22 

TABLE D-16 Federal and State Leasing and Permitting Requirements 

Authority Citation 

 

Federal • Combined Hydrocarbon Leasing Act of 1981 (P.L. 97-78) 

• Energy Policy Act of 2005 (P.L. 109-58) 

 Leasing in Special Tar Sand Areas (70 FR 58610, codified at 43 CFR Part 3140) 

 Leasing in Special Tar Sand Areas (71 FR 28779, codified at 43 CFR Subpart 3141) 

 

Colorado  Permit from Division of Minerals and Geology Operations for actual mining activity 

 

Utah  Large Mining Operations (Rule R647-4) 

 

Wyoming  Mine permit required for mining kerogen either conventionally or in situ 

D.2 ADDITIONAL INFORMATION REGARDING THE REGULATORY 

 AND POLICY ENVIRONMENT 

D.2.1 Air Quality 

The U.S. Environmental Protection Agency (EPA) establishes and revises the National 

Ambient Air Quality Standards (NAAQS), as necessary, to protect public health and welfare, 

setting the absolute upper limits for specific air pollutant concentrations at all locations where the 

public has access. Although the EPA has revised both the ozone and PM2.5 (particulate matter 

with a mean aerodynamic diameter of 2.5 m or less) NAAQS, neither of these revised limits 

would be implemented by the states of Colorado, Utah, or Wyoming until their State 

Implementation Plans (SIPs) are formally approved by the EPA; until then, the EPA is 

responsible for implementing these revised standards. 

Potential development impacts must demonstrate compliance with all applicable local, 

state, tribal, and federal air quality regulations, standards, and implementation plans established 

under the Clean Air Act (CAA) and administered by the states (with EPA oversight). Air quality 

regulations require that proposed new or modified existing air pollutant emission sources 

(including potential future oil shale or tar sands projects) undergo a permitting review before 

their construction can begin. Therefore, the states have the primary authority and responsibility 

to review permit applications and to require emission permits, fees, and control devices prior to 

construction and/or operation. 

In addition, the U.S. Congress (through CAA Section 116) authorized local, state, and 

tribal air quality regulatory agencies to establish air pollution control requirements that are more 

(but not less) stringent than federal requirements (such as the Colorado and Wyoming sulfur 

dioxide [SO2] ambient air quality standards). If future oil shale or tar sands projects are 

proposed, additional site-specific air quality analyses would be performed, and additional 
Final OSTS PEIS D-23 

emission control measures (including emissions control technology analysis and determination) 

may be required by the applicable air quality regulatory agencies to ensure protection of air 

quality resources. In addition, under the federal CAA and Federal Land Policy and Management 

Act of 1976 (FLPMA), the Bureau of Land Management (BLM) cannot authorize any activity 

that does not conform to all applicable local, state, tribal, and federal air quality laws, statutes, 

regulations, standards, and implementation plans. 

Given the study area’s current attainment status, future development projects that have 

the potential to emit more than 250 tons/yr (or certain listed sources that have the potential to 

emit more than 100 tons/yr) of any criteria pollutant would be required to submit a 

preconstruction Prevention of Significant Deterioration (PSD) permit application, including a 

regulatory PSD Increment Consumption Analysis under the federal New Source Review and 

permitting regulations. Development projects subject to the PSD regulations must also 

demonstrate the use of “Best Available Control Technology” (BACT) and show that the 

combined impacts of all applicable sources would not exceed the PSD increments for SO2, 

nitrogen dioxide (NO2), or PM10 (particulate matter with a mean aerodynamic diameter of 

10 m or less). The permit applicant must also demonstrate that cumulative impacts from all 

existing and proposed sources would comply with the applicable ambient air quality standards 

throughout the operational lifetime of the permit applicant’s project. 

In addition, a regulatory PSD Increment Consumption Analysis may be conducted at any 

time by the states or the EPA, in order to demonstrate that the applicable PSD increment has not 

been exceeded by all applicable major or minor increment-consuming emission sources. The 

determination of PSD increment consumption is a legal responsibility of the applicable air 

quality regulatory agency (with EPA oversight). National Environmental Policy Act of 1969 

(NEPA) analyses may compare potential air quality impacts from a proposed project with 

applicable ambient air quality standards, PSD increments, and air quality related value (AQRV) 

impact threshold levels; this comparison, however, does not represent a regulatory air quality 

permit analysis. Comparisons with the PSD Class I and II increments are intended to evaluate a 

“threshold of concern” for potentially significant adverse impacts, but do not represent a 

regulatory PSD Increment Consumption Analysis. 

D.2.2 Cultural Resources 

Cultural resources that meet the eligibility criteria for listing on the National Register 

of Historic Places (NRHP) are considered “significant” resources and must be taken into 

consideration during the planning of federal projects. Federal agencies are also required to 

consider the effects of their actions on sites, areas, and other resources (e.g., plants) that are of 

religious significance to Native Americans1 as established under the American Indian Religious 

Freedom Act (Public Law [P.L.] 95-341). Archaeological resources on public lands and Indian 

lands are protected by the Archaeological Resources Protection Act of 1979, as amended 

(P.L. 96–95), and Native American graves and burial grounds are protected by the Native 

American Graves Protection and Repatriation Act of 1990 (P.L. 101-601). Cultural resources on 

 

1 These acts refer specifically to Native Americans, Native Alaskans, and Native Hawaiians. 
Final OSTS PEIS D-24 

federal lands are further considered by laws penalizing the theft or degradation of property of the 

U.S. government (Theft of Government Property [62 Stat. 764, 18 USC 1361] and FLPMA). A 

list of these and other regulatory requirements pertaining to cultural properties is presented in 

Table D-17. These laws are applicable to any project undertaken on federal land or requiring 

federal permitting or funding. 

 Cultural resources on BLM-administered land are managed primarily through the 

application of the above-identified laws. As required by Section 106 of the National Historic 

Preservation Act (NHPA), BLM field offices work with land use applicants to inventory and 

evaluate cultural resources in areas that may be affected by proposed development. The BLM 

has established a cultural resource management program as identified in its 8100 Series manuals 

and handbooks (Table D-18). The goal of the program is to locate, evaluate, manage, and protect 

cultural resources on public lands. (See Section 3.1, Land Use, for a description of designated 

Areas of Critical Environmental Concern [ACECs], some of which are designated specifically to 

protect cultural resources.) Guidance on how to apply the NRHP criteria to evaluate the 

eligibility of sites located on public lands is provided in numerous documents prepared by the 

National Park Service (NPS) and in the BLM 8100 Series manuals and handbooks. Further 

guidance on the application of cultural resource laws and regulations is provided through a 

national Programmatic Agreement (PA) developed among the BLM, the National Council of 

State Historic Preservation Officers (SHPOs), and the Advisory Council on Historic 

Preservation, and through state-specific Protocol Agreements concerning cultural resources. 

D.2.3 Noise 

 The Noise Control Act of 1972, as amended by the Quiet Communities Act of 1978 

(42 USC 4901 et seq.), delegates the authority to regulate noise to the states and directs 

government agencies to comply with local noise regulations. Of the three states in the study area, 

only Colorado has a regulation specifying quantitative limits on noise. Table D-19 lists the noise 

limits in Colorado’s Noise Abatement Law. Many local governments have enacted noise 

ordinances to manage community noise levels. These noise limits are typically applied to define 

noise sources and specify a maximum permissible noise level. They are commonly enforced by 

police but may also be enforced by the agency issuing development permits. 

 EPA guidelines recommend a day-night average sound level (Ldn) of 55 A-weighted 

decibels (dBA) as sufficient to protect the public from the effects of broadband environmental 

noise in quiet outdoor and residential neighborhoods (EPA 1974). The guidelines recommend an 

equivalent sound pressure level (Leq) of 70 dBA or less over a 40-year period to protect the 

general population against hearing loss from non-impulsive noise. The Federal Aviation 

Administration and the Federal Interagency Committee on Urban Noise have issued land use 

compatibility guidelines indicating that a yearly Ldn of less than 65 dBA is compatible with 

residential land uses and that, if a community determines it is necessary, levels up to 75 dBA 

may be compatible with residential uses and transient lodgings (but not mobile homes) if such 

structures incorporate noise reduction features (14 CFR Part 150, Appendix A). 
Final OSTS PEIS D-25 

TABLE D-17 Cultural Resource Laws and Regulations 

Law or Order Name Intent 

 

Antiquities Act of 1906 This law makes it illegal to remove cultural resources from federal 

land without permission. It also allows the President to establish 

historical monuments and landmarks. 

 

National Historic Preservation Act of 1966, 

as amended (NHPA) 

The NHPA creates the framework within which cultural resources 

are managed in the United States. The law requires that each state 

appoint a State Historic Preservation Officer (SHPO) to direct and 

conduct a comprehensive statewide survey of historic properties and 

maintain an inventory of such properties, and it created the Advisory 

Council on Historic Preservation, which provides national oversight 

and dispute resolution. Section 106 of the NHPA defines the process 

for identifying and evaluating cultural resources and determining 

whether a project will result in an adverse effect on the resource. It 

also addresses the appropriate process for mitigating adverse effects. 

Section 110 of the NHPA directs the heads of all federal agencies to 

assume responsibility for the preservation of listed or eligible 

historic properties owned or controlled by their agency. Federal 

agencies are directed to locate, inventory, and nominate properties to 

the NRHP, to exercise caution to protect such properties, and to use 

such properties to the maximum extent feasible. Additional 

provisions of Section 110 include documentation of properties 

adversely affected by federal undertakings, the establishment of 

trained federal preservation officers in each agency, and the 

inclusion of the costs of preservation activities as eligible agency 

project costs. The NHPA also establishes the processes for 

consultation among interested parties, the lead agency, and the 

SHPO, and for government-to-government consultation between 

U.S. government agencies and Native American Tribal governments. 

 

National Trails System Act (1968) The Act and its subsequent amendments authorized a national 

system of trails and defined four classes of trails: National Scenic 

Trails, National Historic Trails, National Recreation Trails, and 

Connecting or Side Trails. 

 

E.O. 11593, Protection and Enhancement of 

the Cultural Environment 

(U.S. President 1971) 

E.O. 11593 requires federal agencies to inventory their cultural 

resources and to record, to professional standards, any cultural 

resource that may be altered or destroyed. 

 

Archaeological and Historic Preservation 

Act (1974) (AHPA) 

The AHPA directly addresses impacts on cultural resources resulting 

from federal activities that would significantly alter the landscape. 

The focus of the law is data recovery and salvage of scientific, 

prehistoric, historic, and archaeological resources that could be 

damaged during the creation of dams and the impacts resulting from 

flooding, worker housing, creation of access roads, etc.; however, its 

requirements are applicable to any federal action. 
Final OSTS PEIS D-26 

TABLE D-17 (Cont.)

Law or Order Name Intent 

 

Federal Land and Policy Management Act 

(1976) 

The FLPMA requires the BLM to manage its lands for multiple use 

and sustained yield in a manner that will protect the quality of its 

environmental values, such as cultural resources. 

 

American Indian Religious Freedom Act of 

1978 (AIRFA) 

The AIRFA protects the right of Native Americans to have access to 

their sacred places. It requires consultation with Native American 

organizations if an agency action will affect a sacred site on federal 

lands. 

 

Archaeological Resources Protection Act of 

1979, as amended (ARPA) 

The ARPA establishes civil and criminal penalties for the 

destruction or alteration of archaeological resources and establishes 

professional standards for excavation. 

 

Native American Graves Protection and 

Repatriation Act of 1990 (NAGPRA) 

The NAGPRA requires federal agencies to consult with the 

appropriate Native American Tribes prior to the intentional 

excavation of Native American human remains and funerary objects. 

It requires the repatriation of Native American human remains found 

on the agencies’ land. 

 

E.O. 13006, Locating Federal Facilities on 

Historic Properties in our Nation’s Central 

Cities (U.S. President 1996a) 

E.O. 13006 encourages the reuse of historic downtown areas by 

federal agencies. 

 

E.O. 13007, Indian Sacred Sites 

(U.S. President 1996b) 

E.O. 13007 requires that an agency allow Native Americans to 

worship at sacred sites located on federal property. It also directs the 

agency to protect these locations from damage. 

 

E.O. 13175, Consultation and Coordination 

with Indian Tribal Governments 

(U.S. President 2000) 

E.O. 13175 requires federal agencies to coordinate and consult with 

Indian Tribal governments whose interests might be directly and 

substantially affected by activities on federally administered lands. 

 

E.O. 13287, Preserve America 

(U.S. President 2003) 

E.O. 13287 encourages the promotion and improvement of historic 

structures and properties to encourage tourism. 

 Changes to ambient sound levels can interfere with wildlife, including predator/prey 

relationships, territory establishment, foraging, mating behavior, and reproductive success. 

Sections 4.8 and 5.8 discuss these impacts in more detail. 

NPS policy states that “natural ambient” conditions (the sound levels that would occur in 

the absence of all noise caused by humans) are the baseline against which potential noise impacts 

should be judged. Site-specific environmental assessments would need to determine these levels 

and how development on adjacent BLM-administered lands might affect NPS-managed lands. 
Final OSTS PEIS D-27 

TABLE D-18 BLM Guidance Regarding Cultural Resource Management 

BLM 8100 Series Manuals and Handbooks 

8100 Manual: The Foundations for Managing Cultural Resources 

 

8110 Manual: Identifying and Evaluating Cultural Resources 

 

8120 Manual: Tribal Consultation under Cultural Resource Authorities 

 

H-8120-1: General Procedural Guidance for Native American Consultation 

 

8130 Manual: Planning for Uses of Cultural Resources 

 

8140 Manual: Protecting Cultural Resources 

 

8150 Manual: Permitting Uses of Cultural Resources 

 

8170 Manual: Interpreting Cultural Resources for the Public 

D.2.4 Paleontological Resources 

As nonrenewable resources, no matter how 

common or rare they may be, fossils of scientific value are 

offered some protection through the Antiquities Act of 

1906. Two other federal acts, the Archaeological Resources 

Protection Act of 1979 and the Federal Cave Resources 

Protection Act of 1988, protect fossils found in primary 

context and from significant caves, respectively. Fossils on 

federal lands (e.g., BLM-administered lands) are further 

protected by laws penalizing the theft or degradation of 

property of the U.S. Government (Theft of Government 

Property [62 Stat. 764, 18 USC 1361] and FLPMA). The 

Paleontological Resources Preservation Act, part of Title 

VI under the Omnibus Public Land Management Act of 

2009, requires that paleontological resources collected 

under a permit remain the property of the United States to 

be preserved for the public. The Act also requires that the 

nature and location of paleontological resources be kept 

confidential to protect them from theft and vandalism. Civil 

and criminal penalties may be imposed when theft and 

vandalism of publicly owned paleontological resources 

occur. 

TABLE D-19 Colorado Limits on 

Maximum Permissible Noise 

Levels 

 

Maximum Permissible

Noise Levela (dBA) 

Zone 

7 a.m. 

to 7 p.m.b

7 p.m. 

to 7 a.m. 

Residential 55 50 

Commercial 60 55 

Light industrial 70 65 

Industrial 80 75 

a At a distance of 25 ft from the 

property line. Periodic, impulsive, or 

shrill noises are considered a public 

nuisance at a level 5 dBA less than 

those tabulated. 

b For a period not to exceed 

15 minutes in any 1 hour, the 

tabulated noise levels may be 

exceeded by 10 dBA. 

Source: CRS 25-12-101 et seq. 
Final OSTS PEIS D-28 

D.2.5 Visual Resources 

The BLM’s responsibility to manage the scenic resources of the public lands is 

established by law as follows: 

The Federal Land Policy and Management Act of 1976 (FLPMA) states that “...public 

lands will be managed in a manner which will protect the quality of the scenic (visual) 

values of these lands.” This act prevents unnecessary or undue degradation of public 

lands. The FLPMA makes protecting scenic and other environmental values an explicit 

criterion that must be applied throughout the BLM’s land management activities 

(Ross 1979). 

The BLM also provides visual resource management guidance in its publications, 

including the following: 

• BLM Manual 8400 Series, Visual Resources Management (VRM), 

• Information Bulletin No. 98-135 (BLM 1998a), 

• Instruction Memorandum No. 98-164 (BLM 1998b), and 

• Instruction Memorandum No. 2009-167 (BLM 2009). 

The intent of these documents is to provide for the protection of visual resources throughout the 

public lands managed by the agency. 

D.3 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

BLM (Bureau of Land Management), 1998a, Visual Resource Management (VRM) Policy 

Restatement, Information Bulletin No. 98-135, U.S. Department of the Interior, May 22. 

Available at http://www.blm.gov/nstc/VRM/98135.html. Accessed Dec. 7, 2011. 

BLM, 1998b, Instruction Memorandum 98-164, Summary of Visual Resource Management 

(VRM) Issues Discussed in Southern Utah Wilderness Alliance, U.S. Department of the Interior, 

Sept. 8. Available at http://www.blm.gov/nstc/VRM/98164.html. Accessed Dec. 7, 2011. 

BLM, 2009, Instruction Memorandum 2009-167, Application of the Visual Resource 

Management Program to Renewable Energy, U.S. Department of the Interior, July 7. Available 

at http://www.blm.gov/wo/st/en/info/regulations/Instruction_Memos_and_Bulletins/national_ 

instruction/2009/IM_2009-167.html. Accessed Dec. 7, 2011. 
Final OSTS PEIS D-29 

EPA (U.S. Environmental Protection Agency), 1974, Information on Levels of Environmental 

Noise Requisite to Protect Public Health and Welfare with an Adequate Margin of Safety, 

EPA 550/9-74-004, Office of Noise Abatement and Control, Washington, D.C., March. 

Ross, R.W., 1979, “The Bureau of Land Management and Visual Resource Management – An 

Overview,” presented at National Conference on Applied Techniques for Analysis and 

Management of the Visual Resource, Incline Village, Nev., April 23–25. Available at 

http://www.fs.fed.us/psw/publications/documents/psw_gtr035/psw_gtr035_15_ross.pdf. 

Accessed Sept. 26, 2011. 

U.S. President, 1971, “Protection and Enhancement of the Cultural Environment,” Executive 

Order 11593, Federal Register 36:8921, May 15. 

U.S. President, 1977a, “Floodplain Management,” Executive Order 11988, Federal Register

42:26951, May 25. 

U.S. President, 1977b, “Protection of Wetlands,” Executive Order 11990, Federal Register, 

42:26961, May 25. 

U.S. President, 1993, “Federal Compliance with Right-to-Know Laws and Pollution Prevention 

Requirements,” Executive Order 12856, Federal Register 58:41981, Aug. 6. 

U.S. President, 1994, “Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations,” Executive Order 12898, Federal Register 59:7629, 

Feb. 16. 

U.S. President, 1996a, “Locating Federal Facilities on Historic Properties in Our Nation’s 

Central Cities,” Executive Order 13006, Federal Register 61:26071, May 24. 

U.S. President, 1996b, “Indian Sacred Sites,” Executive Order 13007, Federal Register

61:26771, May 29. 

U.S. President, 1996c, “Management and General Public Use of the National Wildlife Refuge 

System,” Executive Order 12996, Federal Register 61:13647, March 28. 

U.S. President, 2000, “Consultation and Coordination with Indian Tribal Governments,” 

Executive Order 13175, Federal Register 65:67249, Nov. 9. 

U.S. President, 1999, “Invasive Species,” Executive Order 13112, Federal Register 64:6183, 

Feb. 8. 

U.S. President, 2001, “Responsibilities of Federal Agencies to Protect Migratory Birds,” 

Executive Order 13186, Federal Register 66:3853, Jan. 17. 

U.S. President, 2003, “Preserve America,” Executive Order 13287, Federal Register 68:10635, 

March 5. 
Final OSTS PEIS D-30 

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Final OSTS PEIS E-1 

APPENDIX E: 

THREATENED, ENDANGERED, AND SENSITIVE SPECIES 

WITHIN THE OIL SHALE AND TAR SANDS STUDY AREA 
Final OSTS PEIS E-2 

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TABLE E-1 Federally Listed and State-Listed Threatened, Endangered, Candidate Species, Species of Special Conand BLM-Designated Sensitive Species That Occur in the Study Area Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants Abies concolor White fir NLe WY-SC WY-Sweetwater Green River Foothills and low

and in associatiooften on south-fshallow soils. OLittle Mountain 

Achnatherum swallenii Swallen mountain- ricegrass NL WY-SC WY-Lincoln, Sublette Green River Calcareous sand

and knobs at eleand 7,100 ft. 

Amsonia jonesii Jones blue star BLM NL UT-Duchesne, 

Emery, Garfield, Grand, San Juan, Uintah, Wayne 

Uinta; all STSAs Desert shrub, sa

juniper communwhite shale soils

Androstephium breviflorum 

Purple funnellily NL WY-SC WY-Sweetwater Green River and Washakie Shadscale, sageb

communities on substrates; 6,000 

Antennaria arcuata 

Meadow pussytoes 

BLM WY-SC WY-Sublette Green River Subirrigated me

level ground, or alkaline or clay 

Aquilegia scopulorum var.goodrichii 

Utah columbine BLM NL UT-Carbon, 

Duchesne, Emery, Grand, Uintah 

Uinta; all STSAs Coniferous fores

communities on scree slopes at 6
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Arabis vivariensis Park rockcress BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill Creek, P.R. Spring, Pariette, and Raven Ridge STSAs Limestone and s

mixed desert shrcommunities at 

Artemisia biennis var. diffusa Mystery wormwood BLM WY-SC WY-Sweetwater Green River and Washakie Clay flats and pl

6,500 ft. Astragalus bisulcatus var. haydenianus Hayden’s milkvetch NL WY-SC WY-Sweetwater, Uinta Green River and Washakie Clay or sandy so

associated with on rims, upper s

Astragalus calycosus var. calycosus 

King’s milkvetch 

NL WY-SC WY-Sweetwater, 

Uinta 

Green River and Washakie Pinyon-juniper w

and 12,000 ft. 

Astragalus coltonii var. 

moabensis 

Moab milkvetch NL WY-SC WY-Sweetwater, 

Uinta 

Green River and Washakie Pinyon-juniper a

communities bet

Astragalus debequaeus 

Debeque milkvetch 

BLM NL CO-Garfield Piceance Varicolored, fin

saline soils of thAtwell Gulch Mof dark clay intesandstone at elevand 6,400 ft. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Astragalus detritalis Debris milkvetch BLM NL CO-Rio Blanco; UT-Duchesne, Uintah Piceance and Uinta; Argyle Canyon, Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, and Sunnyside STSAs Pinyon-juniper a

communities; offrom sandy clayterraces with cob5,400 and 7,200 

Astragalus duchesnensis Duchesne milkvetch BLM NL CO-Rio Blanco; UT-Duchesne, Uintah Piceance and Uinta; Argyle Canyon, Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, and Sunnyside STSAs Salt desert shrub 

communities on around sandstonto 6,050 ft. 

Astragalus equisolensis 

Horseshoe milkvetch 

BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill 

Creek, P.R. Spring, Pariette, and Raven Ridge STSAs 

Primarily restricpinyon-juniper cHorseshoe Bend 

Astragalus hamiltonii 

Hamilton's milkvetch 

BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill 

Creek, P.R. Spring, Pariette, and Raven Ridge STSAs 

Desert scrub comsoils, sometimes and juniper; 5,30

Astragalus lentiginosus var. salinus 

Sodaville milkvetch 

NL WY-SC WY-Lincoln, 

Uinta 

Green River Moist, open, alk

drainages near c
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Astragalus musiniensis Ferron milkvetch BLM NL CO-Garfield; UT-Emery, Garfield, Grand, Wayne Piceance; P.R. Spring, San Rafael, Sunnyside, Tar Sand Triangle, and White Canyon STSAs Gullied bluffs, k

hillsides; in pinydesert shrub comshale, sandstonefrom them at eleand 7,000 ft. Astragalus naturitensis Naturita milkvetch BLM NL CO-Garfield; UT-San Juan Piceance; White Canyon STSA Sandstone mesaslopes in pinyonelevations betwe

Astragalus paysonii 

Payson’s milkvetch 

NL WY-SC WY-Lincoln, 

Sublette 

Green River Disturbed areas 

clear cuts, road cusually found on 9,600 ft. 

Astragalus piscator 

Fisher Towers milkvetch 

BLM NL UT-Garfield, 

Grand, San Juan, Wayne 

Tar Sand Triangle and White Canyon STSAs 

Sandy, sometimvalley benches aelevations betwe

Astragalus proimanthus 

Precocious milkvetch 

BLM WY-SC WY-Sweetwater Green River and Washakie Mainly in cushio

light-colored, sosoils where coarfrom shale on suof low, windy rielevations. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Astragalus racemosus var. treleasei Trelease’s racemose milkvetch BLM WY-SC WY-Sublette, Uinta Green River Silty loam soils 

primarily in sparflats, outcrops obadlands slopes grassland commbetween 6,500 a

Astragalus rafaelensis San Rafael milkvetch BLM NL UT-Emery, Grand P.R. Spring and San Rafael STSAs Banks of sandy 

at the foot of sanamong boulders elevations betwe

Atriplex falcata Sickle saltbush NL WY-SC WY-Sublette, 

Sweetwater, Uinta 

Green River and Washakie Sagebrush, shad

communities in substrates at elevand 2,000 m. 

Atriplex wolfii Wolf’s orache NL WY-SC WY-Sweetwater Green River and Washakie Alkaline flats. 

Boechera crandallii 

Crandall’s rockcress 

NL WY-SC WY-Sweetwater Green River and Washakie Stony soils over 

sagebrush comm

Boechera selbyi Selby’s 

rockcress 

NL WY-SC WY-Sweetwater Green River and Washakie Foothills and mo

Bolophyta ligulata 

Ligulate feverfew 

BLM NL CO-Rio Blanco Piceance Barren shale kno
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Brickellia microphylla var. scabra Little-leaved brickell-bush NL WY-SC WY-Sweetwater Green River and Washakie Dry rocky place

dunes, and wash1,200 and 2,400 

Carex specuicola Navajo sedge ESA-T NL UT-San Juan None Moist, sandy to 

spring pockets olimited soil devebetween 1,740 a

Ceanothus martinii Utah mountain lilac NL WY-SC WY-Lincoln, Sweetwater Green River and Washakie Steep sagebrush 

communities on clay soils at elev8,100 ft. 

Cercocarpus ledifolius var. intricatus 

Dwarf mountain mahogany 

NL WY-SC WY-Sweetwater Green River and Washakie Pinyon juniper-w

9,800 ft. 

Chamaechaenactis scaposa Fullstem NL WY-SC WY-Sweetwater Green River and Washakie Dry, open, relati

soils derived froor limestone, ansandy, or gravelpinyon-juniper wbetween 1,400 a

Chrysothamnus greenei 

Greene rabbitbrush 

NL WY-SC WY-Sweetwater Green River and Washakie Sandy washes an

desert habitats a1,300 and 2,000 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Cirsium aridum Cedar Rim thistle BLM WY-SC WY-Sublette, Sweetwater Green River and Washakie Barren, chalk hi

and shaley draw

Cirsium ownbeyi Ownbey’s thistle BLM WY-SC UT-Uintah; WY-Sweetwater Green River, Uinta, and Washakie; Raven Ridge STSA Dry sites or som

soils in sparsely pinyon-juniper warid grasslands, elevations betwe

Cirsium perplexans Adobe thistle BLM NL CO-Garfield Piceance Almost exclusiv

derived from shaWasatch Formatcommunities incwoodlands and smixed shrubland

Cleomella palmeriana var. 

goodrichii 

Goodrich cleomella 

BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill 

Creek, P.R. Spring, Pariette, and Raven Ridge STSAs 

Salt desert shrub slopes of heavy 5,400 ft. 

Collomia grandiflora 

Large-flower collomia 

NL WY-SC WY-Lincoln Green River Dry, open, or lig

Cryptantha barnebyi 

Barneby’s cat’seye BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill Creek, P.R. Spring, Pariette, 

and Raven Ridge STSAs 

Gently rolling wGreen River Forshadscale and picommunities bet
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Cryptantha caespitosa Caespitose cat’s-eye BLM NL CO-Rio Blanco; UT-Carbon, Duchesne, Uintah Piceance and Uinta; Argyle Canyon, Asphalt Ridge, Hill Creek, Raven Ridge, Pariette, P.R. Spring, and Sunnyside STSAs Sparsely vegetat

pinyon-juniper owith other cushibetween 6,200 a

Cryptantha gracilis Slender cryptantha NL WY-SC WY-Sweetwater Green River and Washakie Pinyon-juniper w

and 7,000 ft. Cryptantha grahamii Graham’s cat’s- eye BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill Creek, P.R. Spring, Pariette, 

and Raven Ridge STSAs 

Green River shasagebrush, pinyobrush communit4,550 and 6,750 

Cryptantha osterhoutii 

Osterhout cat’s-eye 

BLM NL UT-Emery, 

Garfield, Grand, San Juan, Wayne 

P.R. Spring, San Rafael, Tar Sand Triangle, and White Canyon STSAs 

Dry barren sites decomposed sanbetween 1,370 asandy soil in the mixed desert shrand pinyon-junipto 2,000 m. 

Cryptantha rollinsii 

Rollins’ cat’s-eye 

BLM WY-SC CO-Rio Blanco; 

UT-Duchesne, San Raphael, Uintah, Wayne; WY-Sweetwater 

Green River, Piceance, Uinta, and Washakie; Argyle Canyon, Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, San Rafael, and Sunnyside STSAs 

White shale slopFormation; in pidesert shrubland elevations betwe
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Cycladenia humilis var. jonesii Jones cycladenia ESA-T NL UT-Emery, Garfield, Grand, Uintah Hill Creek, Pariette, P.R. Spring, and San Rafael STSAs Known from a f

the Canyonlands Utah. Cymopterus duchesnensis Uinta Basin spring-parsley BLM NL CO-Rio Blanco; UT-Duchesne, Uintah Piceance and Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, and Raven Ridge STSAs Cold desert shrucommunities; sasemibarrens of Mshales; MorrisonGreen River Forbetween 4,700 a

Descurainia pinnata var. 

paysonii 

Payson’s tansy mustard 

NL WY-SC WY-Sweetwater Green River and Washakie Sandy flats and 

shrub cover. 

Descurainia torulosa 

Wyoming tansymustard 

BLM WY-SC WY-Sweetwater Green River and Washakie Sandy soil at the 

of volcanic brec10,500 ft. 

Downingia laeta Great Basin 

downingia 

NL WY-SC WY-Uinta Green River Vernal pools, ed

and in roadside 

Draba juniperina Uinta draba NL WY-SC WY-Sweetwater, 

Uinta 

Green River and Washakie Primarily on san

juniper woodlansagebrush-grassedge of juniper wcushion plant cosandy rims, and juniper thickets. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Elymus simplex var. luxurians Long-awned alkali wild-rye NL WY-SC WY-Sweetwater Green River and Washakie Sand dunes. Ephedra viridis var. viridis Green Mormon tea NL WY-SC WY-Sweetwater Green River and Washakie Sandy or rocky 

habitats. Eriastrum wilcoxii Wilcox eriastrum NL WY-SC WY-Sweetwater Green River and Washakie Sagebrush scrub woodland to 9,0

Erigeron compactus var. consimilis 

San Rafael daisy 

NL WY-SC WY-Sweetwater Green River and Washakie Shale soils in pin

and desert scrub 6,100 and 7,400 

Erigeron maguirei 

Maguire daisy ESA-T NL UT-Emery, 

Garfield, Wayne 

San Rafael STSA Cool, mesic was

partially shaded sandstone cliffs Navajo Sandstonmountain shrub, pine, and lower woodland commbetween 5,400 a

Eriogonum contortum 

Grand buckwheat 

BLM NL CO-Garfield; 

UT-Grand 

Piceance; P.R. Spring STSA Mancos Shale b

and other salt deelevations betwe
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Eriogonum corymbosum var. corymbosum Crisp-leaf wild buckwheat NL WY-SC WY-Sweetwater Green River and Washakie Sandy, gravelly, 

slopes, outcropsblackbrush, and and pinyon-junipwoodlands at eleand 2,700 m. Eriogonum divaricatum Divergent wild buckwheat NL WY-SC WY-Lincoln, Sublette, Sweetwater, Uinta Green River and Washakie Clay flats and slgreasewood, and and pinyon-junipelevations betwe

Eriogonum ephedroides 

Ephedra buckwheat 

BLM NL CO-Rio Blanco; 

UT-Uintah 

Piceance and Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, and Raven Ridge STSAs 

White shale soilFormation, in a juniper woodlanshrublands. 

Eriogonum hookeri 

Hooker wild buckwheat 

NL WY-SC WY-Sweetwater Green River and Washakie Sandy washes, f

saltbush, greasewmountain mahogpinyon-juniper wbetween 1,300 a

Frasera ackermanae 

Ackerman frasera 

BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill 

Creek, P.R. Spring, Pariette, and Raven Ridge STSAs 

Semibarren areaFormation on clscattered pinyonbetween 5,830 a
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Galium coloradoense Colorado bedstraw NL WY-SC WY-Sweetwater Green River and Washakie Shaded rocky or 

cliffs in desert spinyon-juniper. Gentianella tortuosa Utah gentian BLM NL CO-Rio Blanco; UT-Duchesne, Emery, Garfield, Uintah Piceance and Uinta Green River For

knolls and slope8,500 and 10,80

Gilia stenothyrsa Narrow-stem gilia BLM NL CO-Rio Blanco; UT-Carbon, 

Duchesne, Emery, Uintah 

Piceance and Uinta; Argyle Canyon, Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, San Rafael, and Sunnyside STSAs 

Silty to gravelly the Green River grassland, sagebmahogany, or picommunities at and 6,000 ft. 

Glossopetalon spinescens var. meionandrum 

Utah greasebush NL WY-SC WY-Sweetwater Green River and Washakie Gypsiferous and 

Hymenoxys lapidicola 

Rock hymenoxys 

BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill 

Creek, P.R. Spring, Pariette, and Raven Ridge STSAs 

Ponderosa pine communities; usbetween 6,000 a

Lathyrus lanszwertii var. 

lanszwertii 

Nevada sweetpea 

NL WY-SC WY-Uinta Green River Aspen and aspen

to 9,600 ft. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Lepidium barnebyanum Barneby ridge- cress ESA-E NL UT-Duchesne Uinta Pinyon-juniper c

developed soils marly shale outcFormation at eleand 1,985 m. Mipinyon-juniper c

Lepidium huberi Huber’s pepperplant BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill Creek, P.R. Spring, Pariette, and Raven Ridge STSAs Sagebrush, mou

juniper communconiferous foressubstrates at elevand 9,700 ft. 

Lepidium integrifolium var. 

integrifolium 

Entire-leaved peppergrass 

BLM WY-SC WY-Lincoln, 

Uinta 

Green River Moist meadows 

Lesquerella congesta 

Dudley Bluffs bladderpod 

ESA-T NL CO-Rio Blanco Piceance Barren, white sh

River and Uinta exposed along dfrom downcuttinbetween 6,000 a

Lesquerella macrocarpa 

Large-fruited bladderpod 

BLM WY-SC WY-Lincoln, 

Sublette, Sweetwater 

Green River and Washakie Barren or sparse

hills and bencheelevations betwe
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Lesquerella multiceps Western bladderpod BLM WY-SC WY-Lincoln Green River Rock outcrops, t

on open ridges aopenings at elev9,500 ft. Lesquerella parviflora Piceance bladderpod BLM NL CO-Garfield, Rio Blanco Piceance Endemic to outcShale Formation grows on ledges open areas. Lesquerella 

parvula 

Narrow-leaved bladderpod 

NL WY-SC WY-Sweetwater, 

Uinta 

Green River and Washakie Knolls, slopes, a

sagebrush and mcommunities at and 2,700 m. 

Lesquerella prostrata 

Prostrate bladderpod 

NL WY-SC WY-Lincoln, 

Uinta 

Green River Plains, hills, and 

grass, and junipeelevations betwe

Listera borealis Northern 

twayblade 

BLM NL CO-Garfield; 

UT-Duchesne, San Juan; WY-Sublette 

Green River, Piceance, and Uinta; Argyle Canyon, Pariette, and White Canyon STSAs 

Moist, shady sprbetween 8,700 a
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Lomatium latilobum Canyonlands lomatium BLM NL UT-Grand, San Juan None Entrada sandston

between fins and soil and in crevicommunities are juniper, or pondbrush at elevatio2,207 m. Lomatium triternatum var. anomalum Ternate desert- parsley NL WY-SC WY-Lincoln Green River Dry to moist ope

elevations. 

Lygodesmia doloresensis 

Dolores River skeletonplant 

BLM NL UT-Grand P.R. Spring STSA Juniper-desert sh

communities on from sandstone the undivided loGroup, which apMoab, Utah, at eand 1,441 m. 

Mentzelia goodrichii 

Goodrich’s blazinstar 

BLM NL UT-Duchesne, 

Uintah 

Uinta; Asphalt Ridge, Hill Creek, P.R. Spring, Pariette, and Raven Ridge STSAs 

Shale substrates Formation in scaDouglas-fir, and communities; el8,100 and 8,800 

Mentzelia rhizomata 

Roan Cliffs blazingstar 

BLM NL CO-Garfield Piceance Steep talus slope

Parachute Creek River Formation
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Mimulus eastwoodiae Eastwood monkey-flower BLM NL UT-Garfield, Grand, San Juan Tar Sand Triangle and White Canyon STSAs Seeps. Minuartia nuttallii Nuttall sandwort BLM NL UT-Duchesne; WY-Lincoln, Sublette, Sweetwater, Uinta Green River, Uinta, and Washakie; Argyle Canyon and Pariette STSAs Sagebrush hills 

especially on gra

Monolepis pusilla Red poverty- weed NL WY-SC WY-Sweetwater Green River and Washakie Saline or alkalinOpuntia polyacantha var. juniperina 

Juniper pricklypear NL WY-SC WY-Sublette, Sweetwater Green River and Washakie Pinyon-juniper w

between 1,600 a

Opuntia polyacantha var. rufispina 

Rufous-spine prickly-pear 

NL WY-SC WY-Lincoln, 

Sweetwater 

Green River and Washakie Sagebrush grass

shrublands, and slopes and butte

Oxytheca dendroidea 

Tree-like oxytheca 

NL WY-SC WY-Sweetwater Green River and Washakie Desert hills and 

Oxytropis besseyi var. obnapiformis 

Maybell locoweed 

NL WY-SC WY-Sweetwater, 

Uinta 

Green River and Washakie Found on steep, 

chalk badlands. 

Packera crocata Saffron 

groundsel 

NL WY-SC WY-Sweetwater Green River and Washakie Wet meadows, a

outcrops at eleva3,500 m. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Parthenium ligulatum Ligulate feverfew BLM NL CO-Rio Blanco; UT-Wayne Piceance; Tar Sand Triangle STSA Barren shale kno

5,400 and 6,500 

Pediocactus despainii San Rafael cactus ESA-E NL UT-Emery, Wayne San Rafael STSA Hills, benches, a

grassland with spinyon pines. Pediocactus winkleri Winkler cactus ESA-T NL UT-Emery, Wayne San Rafael STSA Alkaline, fine-te

derived from the Associated with communities at and 1,600 m. 

Pediomelum aromaticum 

Paradox breadroot 

BLM NL UT-Grand, 

San Juan 

White Canyon STSA Shallow rocky s

juniper woodlanunderstory. 

Penstemon acaulis var. acaulis 

Stemless beardtongue 

BLM WY-SC WY-Sweetwater Green River and Washakie Semibarren subs

and sagebrush-gelevations betwe

Penstemon debilis Parachute 

beardtongue 

ESA-T NL CO-Garfield Piceance Oil shale outcro

white shale talus of the Parachute Green River For
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Penstemon gibbensii Gibbens’ beardtongue BLM WY-SC WY-Sweetwater Green River and Washakie Sparsely vegetat

sandy-clay slope1,675 and 2,350 vegetation is pinsagebrush, or gr

Penstemon grahamii Graham’s beardtongue ESA- PT; BLM NL CO-Rio Blanco; UT-Duchesne, Uintah Uinta; Hill Creek, Pariette, P.R. Spring, and Raven Ridge STSAs Exposed raw sha

derived from the Evacuation CreeRiver Formation to 2,600 m. Mosthe surface of thledge. 

Penstemon harringtonii 

Harrington beardtongue 

BLM NL CO-Garfield Piceance Open sagebrush 

pinyon-juniper htypically rocky lloams derived frbedrock at eleva9,200 ft. 

Penstemon laricifolius ssp. 

exilifolius 

White beardtongue 

NL WY-SC WY-Sublette Green River Regionally ende

of Wyoming and rocky, gravelly oridgetops. Also popen woodlandsranges between 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Penstemon scariosus var. albifluvis White River beardtongue ESA-C NL CO-Rio Blanco; UT-Uintah Piceance; Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, and Raven Ridge STSAs Mixed desert sh

communities on slopes of the Grelevations betwe

Penstemon scariosus var. garrettii Garrett’s beardtongue NL WY-SC WY-Sweetwater, Uinta Green River and Washakie Rolling semibar

soils, on gentle csmall slate fragmtalus slopes covebelow steep cliff7,600 and 8,400 

Phacelia argillacea 

Clay phacelia ESA-E NL UT-Utah, 

Wasatch 

Argyle Canyon Steep slopes in s

mountain brush clay soils; 6,000 

Phacelia argylensis 

Argyle Canyon phacelia 

BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill 

Creek, P.R. Spring, Pariette, and Raven Ridge STSAs 

Pinyon-juniper acommunities at 

Phacelia demissa Intermountain 

phacelia 

NL WY-SC WY-Sweetwater Green River and Washakie Desert shrub oft

elevations betwe

Phacelia glandulosa var. 

deserta 

Desert glandular phacelia 

NL WY-SC WY-Lincoln, 

Sublette, Sweetwater 

Green River and Washakie Desert scrub, sa

communities, anclay soils; 5,000 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Phacelia incana Western phacelia NL WY-SC WY-Sweetwater Green River and Washakie Rocky or sandy-

sagebrush, shadsmountain mahogbetween 6,000 a

Phacelia salina Nelson phacelia NL WY-SC WY-Lincoln, Sublette, Sweetwater, Uinta Green River and Washakie Alkaline flats anPhacelia scopulina var. submutica 

Debeque phacelia 

ESA-T NL CO-Garfield Piceance Sparsely vegetat

chocolate-brown Gulch and Shire Formation at eleand 6,200 ft. 

Phacelia tetramera 

Tiny phacelia NL WY-SC WY-Sweetwater Green River and Washakie Alkaline soils an

sagebrush-grasselevations betwe

Philadelphus microphyllus var. 

occidentalis 

Little-leaf mock-orange 

NL WY-SC WY-Sweetwater Green River and Washakie Rocky canyon s

8,500 ft. 

Phlox albomarginata 

White-margined phlox 

NL WY-SC WY-Lincoln Green River Open, rocky pla

elevations. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Phlox pungens Beaver Rim phlox BLM WY-SC WY-Lincoln, Sublette Green River Sparsely vegetat

shales in the Greelevations betwe

Physaria condensata Tufted twinpod BLM WY-SC WY-Lincoln, Sublette, Uinta Green River Sparsely vegetat

ridges at elevatio2,130 m. Physaria dornii Dorn’s twinpod BLM WY-SC WY-Lincoln, Uinta Green River Dry, sparsely ve

shaley slopes anmountain mahogelevations betwe

Physaria obcordata 

Dudley Bluffs twinpod 

ESA-T NL CO-Rio Blanco Piceance Barren white ou

exposed by creeto the Parachute shalebearing Gelevations betwe

Physocarpus alternans 

Dwarf ninebark NL WY-SC WY-Sweetwater Green River and Washakie Pinyon-juniper w

and 10,200 ft. 

Populus deltoides var. wislizeni 

Fremont cottonwood 

NL WY-SC WY-Sweetwater Green River and Washakie Stream banks, sa

riparian areas at 6,000 ft. 

Potentilla multisecta 

Deep Creek cinquefoil 

NL WY-SC WY-Sweetwater, 

Uinta 

Green River and Washakie Rocky subalpine 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Psilocarphus brevissimus Dwarf woolly- heads NL WY-SC WY-Sublette Green River Grasslands to 8,

Ranunculus aestivalis Autumn buttercup ESA-E NL UT-Garfield None Sevier River Va

seeps and springmarshy or bog-lsurrounding regsagebrush-dominbetween 1,938 a

Ranunculus flabellaris 

Yellow watercrowfoot NL WY-SC WY-Uinta Green River Ponds, mudflats

streams at eleva6,700 ft. 

Rorippa calycina Persistent sepal 

yellowcress 

BLM WY-SC WY-Sweetwater Green River and Washakie Riverbanks and 

sandy soils near elevations betwe

Sambucus cerulea Blue elderberry NL WY-SC WY-Sweetwater Green River and Washakie Moist, well-drai

seral communitimoist forest habcliff bases, streaand riparian woowithin drier, mo(sagebrush, moujuniper, ponderofence rows and r10,000 ft. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Schoenocrambe argillacea Clay reed- mustard ESA-T NL UT-Uintah Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, and Raven Ridge STSAs Mixed desert sh

precipitous, typiof the EvacuatioGreen River Forconsist of at-theand fine-texturebetween 1,463 a

Schoenocrambe barnebyi Barneby reed- mustard ESA-E NL UT-Emery, Wayne San Rafael STSA Mixed desert sh

steep, typically nred, selenium-ricthe Moenkopi anelevations betwe

Schoenocrambe suffrutescens 

Shrubby reedmustard ESA-E NL UT-Duchesne, Uintah Uinta; Hill Creek, Pariette, P.R. Spring, and Sunnyside 

STSAs 

Mixed desert shsome locations, desert shrub, on layers of the Evaof the Green Rivon level to modesurfaces. Soils atextured and are fragments at eleand 1,981 m. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Sclerocactus brevispinus Pariette cactus ESA-T NL UT-Duchesne, Uintah Uinta; Hill Creek, Pariette, P.R. Spring, and Sunnyside STSAs Endemic to high

soils; currently kbadlands in the PDuchesne Count4,950 ft. Sclerocactus glaucus Colorado hookless cactus ESA-T NL CO-Garfield Piceance and Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, and Sunnyside STSAs Rocky hills, mesbenches; in deseelevations betwe

Sclerocactus wetlandicus 

Uinta Basin hookless cactus 

ESA-T NL UT-Carbon, 

Duchesne, Uintah 

Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, and Sunnyside STSAs 

Course soils dergravel river and or rocky surfaceto 6,200 ft. 

Sclerocactus wrightiae

Wright fishhook cactus 

ESA-E NL UT-Emery, 

Wayne 

San Rafael and Tar Sand Triangle STSAs 

Barren, alkaline scattered shrubsgrasses, or scatteelevations betweSoils vary from fine sands that mcontent or contaSoil crusts are uground surface isandstone or basboulders. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Senecio spartioides var. multicapitatus Many-headed broom groundsel NL WY-SC WY-Sweetwater Green River and Washakie Plains, open slop

dunes in pinyonponderosa pine fan early coloniz

Silene douglasii Douglas’ campion NL WY-SC WY-Lincoln Green River Sagebrush and l

communities at and 9,500 ft. Spiranthes diluvialis Ute ladies’- tresses ESA-T NL UT-Duchesne, Garfield, Uintah, 

Wayne 

Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, and Raven Ridge STSAs 

Moist to very wor in abandoned still retain ample springs, seeps, aelevations betwe

Thelesperma caespitosum 

Green River greenthread 

BLM WY-SC WY-Sweetwater Green River and Washakie White shales of 

Formation in assjuniper and moucommunities; ap

Thelesperma pubescens 

Uinta greenthread 

BLM WY-SC WY-Sweetwater, 

Uinta 

Green River and Washakie Sparsely vegetat

cobble soils of thin grassland, sagprostrate forb coelevations betwe
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Plants (Cont.) Townsendia aprica Last chance townsendia ESA-T NL UT-Emery, Wayne San Rafael STSA Pinyon-juniper a

communities on gravelly clay soiFormation at eleand 2,440 m. Townsendia microcephala Cedar Mountain Easter-daisy BLM WY-SC WY-Sweetwater, Uinta Green River and Washakie Rocky slopes anBishop ConglomMountains. Townsendia 

strigosa 

Strigose Easterdaisy BLM NL UT-Duchesne, Uintah Uinta; Argyle Canyon, Asphalt Ridge, Hill Creek, 

Pariette, P.R. Spring, and Raven Ridge STSAs 

Desert scrub and between 4,700 a

Yucca sterilis Spanish bayonet BLM NL UT-Uintah Uinta; Asphalt Ridge, Hill 

Creek, P.R. Spring, Pariette, and Raven Ridge STSAs 

Sandy soils in sajuniper, and shaelevations betwe

Invertebrates 

Oreohelix eurekensis 

Eureka mountainsnail 

BLM UT-SC UT-Duchesne, 

Grand 

None Terrestrial; fores

and fir with open interspersed stanand scrub oak. 

Oreohelix yavapai 

Yavapai mountainsnail 

BLM UT-SC UT-San Juan None Terrestrial; aspe

open areas of groutcrops. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Invertebrates (Cont.) Physa utahensis Utah physa BLM UT-SC UT-Garfield None Vegetated spring

Pyrgulopsis plicata Black Canyon pyrg BLM UT-SC UT-Garfield None Known only fro

Black Canyon, EGarfield Countypresumably stric

Speyeria nokomis nokomis Great Basin silverspot butterfly BLM NL UT-Duchesne, Uintah Uinta; Argyle Canyon, Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, and Raven Ridge STSAs Streamside mea

areas with an abgenerally desert 

Fish 

Catostomus discobolus 

Bluehead sucker BLM WY-SC CO-Garfield, 

Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; all STSAs 

Wide range of stcold, clear mounturbid streams; rAdults prefer mowater above rubprefer quiet shal
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Fish (Cont.) Catostomus latipinnis Flannelmouth sucker BLM WY-SC CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta Green River, Piceance, Uinta, and Washakie; all STSAs Moderate to larg

and deeper runs mouths of small and backwaters. 

Gila copei Leatherside 

chub 

BLM UT-SC, 

WY-SC 

UT-Duchesne, Emery, Garfield, Wayne; WY-Lincoln, Uinta 

Green River Adults occur in 

riffles of cold crrivers. Young ocquiet pockets ne

Gila cypha Humpback chub ESA-E CO-T UT-Carbon, 

Emery, Garfield, Grand, San Juan, Uintah, Wayne 

Uinta; Asphalt Ridge, Hill Creek, Sunnyside, Tar Sand Triangle, and White Canyon STSAs 

Large rivers. Adincluding deep tcanyon pools, anledges in modereddies. Young hbackwaters over Presumed to havWyoming. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Fish (Cont.) Gila elegans Bonytail ESA-E NL UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne Uinta; Asphalt Ridge, Hill Creek, Pariette, Raven Ridge, Sunnyside, Tar Sand Triangle, and White Canyon STSAs Main stream of m

Wild bonytail beextirpated in the Colorado River. experimental reimade. Gila robusta Roundtail chub BLM CO-SC, WY-SC CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, 

Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, San Rafael, Sunnyside, Tar Sand Triangle, and White Canyon STSAs 

Rocky runs, rapand small to larg

Oncorhynchus clarkii pleuriticus 

Colorado River cutthroat trout 

BLM CO-SC, 

WY-SC 

CO-Garfield, Rio Blanco; UT-Duchesne, Garfield, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; Argyle Canyon STSA 

Requires cool, cvegetated stream bank stability; inform of deep pois also importancold water; thriv
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Fish (Cont.) Oncorhynchus clarkii utah Bonneville cutthroat trout BLM WY-SC WY-Lincoln, Uinta Green River Habitats ranging 

streams with conriparian trees to sage-steppe grasherbaceous riparmay be importanwinter habitat fo

Ptychocheilus lucius Colorado pikeminnow ESA-E CO-T CO-Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, 

Grand, San Juan, Uintah, Wayne 

Piceance and Uinta; Asphalt Ridge, Hill Creek, Pariette, Raven Ridge, Sunnyside, Tar Sand Triangle, and White Canyon STSAs 

Medium to large small, quiet backvarious habitats, strongly flowing flooded bottoms(especially durinthroughout the GRiver. Presumed in Wyoming. 

Rhinichthys osculus thermalis 

Kendall Warm Springs dace 

ESA-E NL WY-Sublette Green River Narrowly endem

spring outflow alimestone ridge. eddies where pla

Xyrauchen texanus 

Razorback sucker 

ESA-E CO-E CO-Garfield, 

Rio Blanco; UT-Carbon, Emery Garfield, Grand, San Juan, Uintah, Wayne 

Piceance and Uinta; Asphalt Ridge, Hill Creek, Pariette, Raven Ridge, Sunnyside, Tar Sand Triangle, and White Canyon STSAs 

Habitats include and eddies of mBelieved to have Wyoming. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Amphibians Bufo boreas Boreal toad BLM CO-E; UT-SC; WY-SC CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Uintah, Wayne; WY-Lincoln, Sublette, Uinta Green River, Piceance, and Uinta Marshes, wet m

ponds, glacial keinterspersed in s(lodgepole pine, subalpine fir, an

Bufo microscaphus Arizona toad BLM UT-SC UT-Garfield, San Juan None Irrigation ditche

well as streams bcottonwoods. 

Hyla arenicolor Canyon treefrog BLM NL UT-Garfield, 

Grand, Wayne, San Juan 

Tar Sand Triangle and White Canyon STSAs 

Temporary or pearid scrub and mof elevations bet

Rana luteiventris Columbia 

spotted frog 

BLM WY-SC UT-Utah, 

Wasatch; WY-Lincoln, Sublette 

Argyle Canyon, Green River, and Uintah 

Rarely found far water; usually at of streams, lakesmarshes. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Amphibians (Cont.) Rana pipiens Northern leopard frog BLM CO-SC, WY-SC CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, 

Uinta 

Green River, Piceance, Uinta, and Washakie; all STSAs 

Wet meadows, mkettle ponds, beareservoirs, stream

Spea intermontana 

Great basin spadefoot 

BLM WY-SC CO-Garfield, 

Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; all STSAs 

Pinyon-juniper wand semidesert scanyons, broad dfloodplains. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Reptiles Charina bottae Northern rubber boa NL WY-SC WY-Lincoln, Uinta WY-Green River Foothills and low

water is present of flat rocks, log

Crotalus oreganus concolor Midget faded rattlesnake BLM CO-SC CO-Garfield, Rio Blanco; WY-Sweetwater Green River, Piceance, and Washakie High, cold deser

sagebrush, with outcrops and exp

Elaphe guttata Corn snake BLM UT-SC UT-Grand, San Juan White Canyon STSA Rocky hillsides, 

and river bottomarroyos, in barnywooded areas. 

Gambelia wislizenii 

Longnose leopard lizard 

BLM CO-SC CO-Garfield Piceance Flat or gently slo

large percentage of greasewood asandy soils and bor near the mout

Liochlorophis vernalis 

Smooth greensnake 

BLM UT-SC UT-Carbon, 

Duchesne, Grand, San Juan, Uintah 

Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, Sunnyside, and White Canyon STSAs 

Meadows, grassshrublands, streaopen, moist woo

Pituophis catenifer deserticola 

Great Basin gophersnake 

NL WY-SC WY-Lincoln, 

Sweetwater, Uinta 

WY-Green River, Washakie Sagebrush and d

is deep, loose soshelter. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Reptiles (Cont.) Sauromalus ater Common chuckwalla BLM UT-SC UT-Garfield, San Juan None Rocky desert; la

outcrops. Urosaurus ornatus wright Northern tree lizard NL WY-SC WY-Sweetwater, Uinta WY-Green River, Washakie Rocky cliffs, canexposures of bedin sagebrush and 

Xantusia vigilis Desert night lizard BLM UT-SC UT-Garfield, San Juan Tar Sand Triangle and White Canyon STSAs Arid and semiar

leaves and trunkand other large ppinyon-juniper, and chaparral-oa

Birds 

Accipiter gentilis Northern 

goshawk 

BLM WY-SC CO-Garfield, 

Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; all STSAs 

Variety of forest seen during mig

Aechmophorus clarkii 

Clark’s grebe NL WY-SC WY-Lincoln Green River Marshes, lakes, 

tall plants growiof large areas of 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Aegolius funereus Boreal owl NL WY-SC WY-Lincoln, Uinta Green River and Washakie Mature spruce-f

pine forests inte

Ammodramus bairdii Baird’s sparrow BLM WY-SC WY-Uinta Green River Prairies, open gr

fields. Nesting olightly grazed m

Ammodramus savannarum Grasshopper sparrow NL UT-SC; WY-SC UT-Duchesne, Uintah, Utah, Wasatch; WY-Lincoln, 

Sweetwater, Uinta 

Green River, Uinta, and Washakie; Argyle Canyon, Asphalt Ridge, Pariette, P.R. Spring, Raven Ridge, Sunnyside 

Grasslands, praiBreeds in grasslvegetation and ibare ground. 

Amphispiza belli Sage sparrow BLM NL WY-Lincoln, 

Sublette, Sweetwater, Uinta 

Green River and Washakie Breeds in sagebr

migration, occurtypes of shrubla

Aphelocoma californica 

Western scrubjay NL WY-SC WY-Sweetwater Green River and Washakie Oak, pinyon, an

and riparian woo
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Asio flammeus Short-eared owl BLM UT-SC; WY-SC UT-Carbon, Duchesne, Emery, Grand, Garfield, San Juan, Uintah, Wayne; WY-Lincoln, Sweetwater, Uinta Green River, Uinta, and Washakie; Asphalt Ridge, Pariette, San Rafael, Tar Sand Triangle, and White Canyon STSAs Large open area

including marshold fields, river savanna, and opnests on high gr

Athene cunicularia 

Burrowing owl BLM CO-T, 

UT-SC, WY-SC 

CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; all STSAs 

Open grasslandsburrows dug by 

Baeolophus ridgwayi 

Juniper titmouse NL WY-SC WY-Sweetwater Green River and Washakie Pinyon-juniper w
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Botaurus lentiginosus American bittern NL WY-SC WY-Lincoln, Sweetwater, Uinta Green River, Washakie Breeds primarily 

marshes, includiwhere cattails, splentiful, and mpatches of open vegetation. Bucephala islandica Barrow’s goldeneye BLM NL CO-Garfield, Rio Blanco Piceance In winter, on res

summer, on mouponds in foreste

Buteo regalis Ferruginous 

hawk 

BLM CO-SC, 

UT-SC, WY-SC 

CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; all STSAs 

Grasslands and srare in pinyon-juwinter, near praiand winter residshrublands and a

Calcarius mccownii 

McCown’s longspur 

NL WY-SC WY-Sweetwater None Sparse short-gra

stubble fields, anbare ground. Neon high, barren hexposures. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Centrocercus minimus Gunnison sage- grouse ESA-C UT-SC UT-Grand, San Juan P.R. Spring, White Canyon STSA Sagebrush shrub

found in native ograsslands, aspeadjacent to or insagebrush. Centrocercus urophasianus Greater sage- grouse ESA-C, BLM CO-SC, UT-SC, WY-SC CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, 

Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; Argyle Canyon, Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, and Sunnyside STSAs 

Sagebrush shrubfound in native ograsslands, aspeadjacent to or insagebrush. 

Charadrius montanus 

Mountain plover 

BLM CO-SC, 

UT-SC, WY-SC 

CO-Rio Blanco; WY-Lincoln, Sublette, Sweetwater 

Green River, Piceance, and Washakie 

Casual migrant iColorado. In Wyopen areas such towns, tablelandheavily grazed s

Chlidonias niger Black tern NL WY-SC WY-Lincoln, 

Sweetwater, Uinta 

None Marshes and aqu

50 ac in size. Necolonies in emerwater’s edge. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Coccyzus americanus occidentalis Western yellow- billed cuckoo ESA-C, BLM WY-SC UT-Duchesne, Garfield, Grand, San Juan, Uintah, Wayne Uinta; Asphalt Ridge STSA Lowland riparia

Cygnus buccinator Trumpeter swan NL WY-SC WY-Lincoln, Sublette, Sweetwater Green River and Washakie Ponds, lakes, an

areas of reeds, semergent vegeta

Cypseloides niger Black swift BLM CO-SC, UT-SC CO-Garfield, Rio Blanco; 

UT-Duchesne, Uintah 

Piceance and Uinta; Argyle Canyon, Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, and Raven Ridge STSAs 

Nests on cliffs nForaging birds oover montane anhabitats. 

Dolichonyx oryzivorus 

Bobolink BLM UT-SC UT-Carbon, 

Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne 

Uinta; all STSAs Breeds in tall gr

meadows, prairifields, and hayfivegetation. Duririce fields, marsareas. 

Egretta thula Snowy egret NL WY-SC WY-Lincoln, 

Sublette, Sweetwater, Uinta 

Green River and Washakie Grassy marshes, 

and wet meadowcolonies in emershrubs on island
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Empidonax traillii extimus Southwestern willow flycatcher ESA-E NL UT-Carbon, Emery, Garfield, Grand, San Juan, Uintah, Wayne Uinta; P.R. Spring, San Rafael, Tar Sand Triangle, and White Canyon STSAs Nests in riparian 

sandbars vegetator other shrubs. Falco peregrinus anatum American peregrine falcon BLM CO-SC CO-Garfield, Rio Blanco; WY-Sublette, Sweetwater Green River, Piceance, and Washakie Nests on cliffs aconiferous and rand winter residreservoirs, riversmay be seen in gareas, and other 

Gavia immer Common loon NL WY-SC WY-Lincoln, 

Sublette, Sweetwater, Uinta 

Green River and Washakie Breeds in clear-w

both shallow and shoreline or islainland lakes and 

Glaucidium gnoma 

Northern pygmy-owl 

NL WY-SC WY-Lincoln, 

Uinta 

Green River Forests or open 

and mountains. Fother openings. woodpecker holcavities. 

Grus americana Whooping crane ESAXN CO-E CO-Garfield, Rio Blanco Piceance Rare migrant in 

on mudflats arouagricultural area
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Grus canadensis tabida Greater sandhill crane NL CO-SC; WY-SC CO-Garfield, Rio Blanco; WY-Lincoln, Sweetwater, Uinta Green River, Piceance, and Washakie Migrants occur o

reservoirs, moisagricultural areawith grassy humbeaver ponds, anwith willows or 

Gymnogyps californianus California condor ESA-E NL UT-Grand Tar Sand Triangle and White Canyon STSAs Mountainous are

elevations, especareas with cliffs forages in grasslmountain plateaRoosts in snags trees near impor

Haliaeetus leucocephalus 

Bald eagle BLM CO-T, 

WY-SC 

CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, Uinta, and Washakie; all STSAs 

Near reservoirs winter, they may semideserts and near prairie dog 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Icterus parisorum Scott’s oriole NL WY-SC WY-Sweetwater Green River and Washakie Pinyon-juniper a

foothills, desert more elevated se

Lanius ludovicianus Loggerhead shrike NL WY-SC WY-Lincoln, Sublette, Sweetwater, Uinta Green River and Washakie Breeds in open c

trees and shrubsand, occasionall

Leucosticte atrata Black rosy- finch NL WY-SC WY-Sweetwater, Lincoln Green River and Washakie Nesting typically 

above 10,000 ft rock outcrops. Wcultivated lands, residential areas

Melanerpes lewis Lewis’s 

woodpecker 

BLM UT-SC; 

WY-SC 

UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Uinta 

Green River and Uinta; all STSAs 

Lowland and fooagricultural areatall deciduous tr

Myiarchus cinerascens 

Ash-throated flycatcher 

NL WY-SC WY-Lincoln, 

Sweetwater, Uinta 

WY-Green River, Washakie Obligate species 

Most abundant iwoodlands on stsparsely covered 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Numenius americanus Long-billed curlew BLM CO-SC, UT-SC, WY-SC CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta Green River, Piceance, Uinta, and Washakie; all STSAs Short-grass prair

fallow fields. Nestanding water. Mshorelines and in 

Nycticorax nycticorax 

Black-crowned night-heron 

NL WY-SC WY-Lincoln, 

Sweetwater, Uinta 

WY-Green River, Washakie Marshes, swamp

shores of lakes acolonies in emeredge of water. 

Oreoscoptes montanus 

Sage thrasher BLM WY-SC WY-Lincoln, 

Sublette, Sweetwater, Uinta 

Green River and Washakie Shrublands, scru

Breeds in sagebrarid or semiarid 

Pelecanus erythrorhynchos 

American white pelican 

BLM UT-SC CO-Garfield, 

UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne 

Piceance and Uinta; all STSAs Large reservoirs 

islands. A migra
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Picoides arcticus Black-backed woodpecker NL WY-SC WY-Lincoln Green River Boreal and mon

especially in aretrees such as burless frequently iwinter, in decidu

Picoides tridactylus Three-toed woodpecker BLM UT-SC UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne Uinta; Argyle Canyon, Hill Creek, P.R. Spring, Sunnyside, Tar Sand Triangle, and White Canyon STSAs Dense coniferou

fir and spruce at in lodgepole pinmixed-conifer fo

Plegadis chihi White-faced ibis BLM WY-SC CO-Garfield, 

Rio Blanco; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River, Piceance, and Washakie 

Migrant and summeadows, marsh shorelines. 

Psaltriparus minimus 

Bushtit NL WY-SC WY-Sweetwater, 

Uinta 

Green River and Washakie Woodlands and 

scattered trees astreamsides, pinassociations. 

Rallus limicola Virginia rail NL WY-SC WY-Lincoln, 

Sublette, Sweetwater, Uinta 

Green River and Washakie Freshwater mars

vegetation. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Sitta pygmaea Pygmy nuthatch NL WY-SC WY-Lincoln, Sublette Green River Pine forest and w

ponderosa pine; juniper woodlan

Sphyrapicus thyroideus Williamson’s sapsucker NL WY-SC WY-Lincoln, Sublette, Sweetwater, Uinta Green River and Washakie Montane conifer

and lodgepole p

Spizella breweri Brewer’s sparrow BLM WY-SC WY-Lincoln, Sublette, 

Sweetwater, Uinta 

Green River and Washakie Sagebrush, grass

Breeding habitat with low sagebr

Sterna caspia Caspian tern NL WY-SC WY-Lincoln Green River Breeds on sandy 

shell banks of la

Sterna forsteri Forster’s tern NL WY-SC WY-Lincoln Green River Nests on inland Strix occidentalis lucida 

Mexican spotted owl 

ESA-T NL UT-Emery, 

Garfield, Grand, San Juan, Uintah, Wayne 

Uinta; Raven Ridge, Tar Sand Triangle, and White Canyon STSAs 

Most common wcanopy forests ouneven-aged staand many snags most favorable. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Birds (Cont.) Tympanuchus phasianellus columbianus Columbian sharp-tailed grouse BLM CO-SC CO-Garfield, Rio Blanco Piceance Gambel oak and 

often intersperseshrublands, aspeand irrigated meDisplay grounds 

Mammals Antrozous pallidus Pallid bat NL WY-SC WY-Sweetwater Green River and Washakie Arid deserts and 

rocky outcrops a

Brachylagus idahoensis 

Pygmy rabbit BLM UT-SC, 

WY-SC 

UT-Garfield, Wayne; WY-Lincoln, Sublette, Sweetwater, Uinta 

Green River and Washakie; Tar Sand Triangle STSA 

Dense stands of deep loose soils

Corynorhinus townsendii pallescens 

Townsend’s big-eared bat 

BLM CO-SC, 

UT-SC, WY-SC 

CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne; WY-Sweetwater 

Green River, Piceance, Uinta, and Washakie; all STSAs 

Semidesert shruwoodlands, and 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Mammals (Cont.) Cynomys gunnisoni Gunnison’s prairie dog ESA-C; BLM UT-SC UT-Grand, San Juan P.R. Spring and White Canyon STSA High mountain v

(elevations betwthat are open or with shrubs, jun

Cynomys leucurus White-tailed prairie dog BLM UT-SC, WY-SC UT-Carbon, Duchesne, Emery, Grand, Uintah; WY-Lincoln, Sublette, 

Sweetwater, Uinta 

Green River, Uinta, and Washakie; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, and San Rafael STSAs 

Open shrublandand mountain vainvades pastures lower elevations

Cynomys parvidens 

Utah prairie dog ESA-T NL UT-Garfield, 

Wayne 

None Grasslands in le

areas with deep, vegetation that por through. 

Euderma maculatum 

Spotted bat BLM UT-SC, 

WY-SC 

CO-Garfield, Rio Blanco; UT-Duchesne, Garfield, Grand, San Juan, Uintah, Wayne; WY-Sweetwater 

Green River, Piceance, Uinta, and Washakie; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, San Rafael, Tar Sand Triangle, and White Canyon STSAs 

Ponderosa pine pinyon-juniper wsemidesert shrubrocky cliffs with 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Mammals (Cont.) Glaucomys sabrinus Northern flying squirrel NL WY-SC WY-Lincoln, Sublette, Sweetwater, Uinta Green River and Washakie Coniferous, deci

riparian forests. Gulo gulo Wolverine NL CO-E, WY-SC CO-Garfield, Rio Blanco; WY-Lincoln, Sublette Green River and Piceance Boreal forests an

Idionycteris phyllotis 

Allen’s bigeared bat BLM UT-SC UT-Garfield, Grand, San Juan, 

Wayne 

P.R. Spring, Tar Sand Triangle, and White Canyon STSAs 

Mountainous areboulders and in forests, or riparistreams and pon

Lasiurus blossevillii 

Western red bat BLM UT-SC UT-Carbon, 

Emery, Grand, Garfield, San Juan, Wayne 

P.R. Spring, San Rafael, Tar Sand Triangle, and White Canyon STSAs 

Riparian habitatcottonwoods, oawalnuts; rarely f

Lontra Canadensis 

River otter NL WY-SC WY-Lincoln, 

Sublette, Sweetwater, Uinta 

Green River and Washakie Bog lakes and ri

containing semiburrows. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Mammals (Cont.) Lynx canadensis Canada lynx ESA-T CO-E, WY-SC CO-Garfield, Rio Blanco; UT-Emery, Uintah; WY-Lincoln, Sublette, Uinta Green River, Piceance, and Uinta; Asphalt Ridge STSA Northern conifer

stands with relatwell-developed 

Martes Americana American marten NL WY-SC WY-Lincoln, Sublette, Sweetwater, Uinta Green River and Washakie Mature and old-

forests. Occupierotten log, or un

Microtus mogollonensis 

Mogollon vole BLM UT-SC UT-San Juan None Mountain meado

woodland. 

Microtus richardsoni 

Water vole NL WY-SC WY-Lincoln, 

Sublette, Uinta 

Green River Subalpine and a

water, especially or glacial stream

Mustela nigripes Black-footed 

ferret 

ESAXN CO-E CO-Rio Blanco; UT-Carbon, 

Duchesne, Emery, Grand, San Juan, Uintah; WY-Sublette, Sweetwater 

Green River, Piceance, Uinta, and Washakie; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, San Rafael, and Sunnyside STSAs 

Historically occuthe shortgrass ansemidesert shrub
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Mammals (Cont.) Myotis evotis Long-eared myotis BLM WY-SC WY-Lincoln, Sublette, Sweetwater, Uinta Green River and Washakie Conifer and dec

mines. Myotis ciliolabrum Western small- footed bat NL WY-SC WY-Lincoln, Sublette, Sweetwater, Uinta Green River and Washakie Rocky areas sucrock outcrops. Aforests, sagebrusprairie. Roosts in and mines. 

Myotis thysanodes 

Fringed myotis BLM UT-SC, 

WY-SC 

CO-Garfield, Rio Blanco; UT-Duchesne, Garfield, Grand, San Juan, Uintah, Wayne; WY-Sublette 

Green River, Piceance, and Uinta; Argyle Canyon, Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, Tar Sand Triangle, and White Canyon STSAs 

Ponderosa pine oakbrush, and sa

Myotis volans Long-legged 

myotis 

NL WY-SC WY-Lincoln, 

Sublette, Sweetwater, Uinta 

Green River and Washakie Open, mature fo

trees, including forests. 
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Mammals (Cont.) Nyctinomops macrotis Big free-tailed bat BLM UT-SC CO-Garfield; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne Piceance and Uinta; Asphalt Ridge, Hill Creek, Pariette, P.R. Spring, Raven Ridge, San Rafael, Tar Sand Triangle, and White Canyon STSAs Roosts in crevic

buildings. Ovis canadensis Bighorn sheep NL WY-SC WY-Lincoln, Sublette, Sweetwater Green River and Washakie Montane habitat

xeric, alpine to g

foothills and riv

Perognathus flavus 

Silky pocket mouse 

BLM UT-SC UT-San Juan None Sandy soils in ar

and pinyon-junipbottoms, hillside

Peromyscus crinitus 

Canyon mouse NL WY-SC WY-Sweetwater Green River and Washakie Rocky habitats: 

talus, boulders, c

Peromyscus truei Pinon mouse NL WY-SC WY-Sweetwater Green River and Washakie Among rocks or 

variety of habitajuniper woodlanlimestone cliffs, 

Sorex nanus Dwarf shrew NL WY-SC WY-Lincoln, 

Sublette, Sweetwater, Uinta 

Green River and Washakie Occupies a varie

tundra, through elevation forestsshortgrass prairi
TABLE E-1 (Cont.) Scientific Name Common Name Federal Statusa State Statusb States and Counties in Which Species Could Occurc Oil Shale Basins and Special Tar Sand Areas in Which Species Could Occurd 

Mammals (Cont.) Sorex preblei Preble’s shrew NL WY-SC WY-Lincoln, Uinta Green River Arid and semiar

communities. Tamias dorsalis utahensis Cliff chipmunk NL WY-SC WY-Sweetwater Green River Rocky outcrops, 

recorded presencvicinity of Flam

Thomomys clusius Wyoming pocket gopher BLM WY-SC WY-Sweetwater Green River and Washakie Well-drained, of

tops and edges ocut washes, and 

Thomomys idahoensis 

Idaho pocket gopher 

BLM WY-SC WY-Lincoln, 

Sublette, Uinta 

Green River Open sagebrush

subalpine mountrelatively shallo

Vulpes macrotis Kit fox BLM CO-E, 

UT-SC 

CO-Garfield, Rio Blanco; UT-Carbon, Duchesne, Emery, Garfield, Grand, San Juan, Uintah, Wayne 

Piceance and Uinta; all STSAs Semidesert shru

pinyon-juniper w

Vulpes velox Swift fox BLM WY-SC WY-Sweetwater Green River and Washakie Open flat prairie

rolling terrain an

Footnotes on following page. 
TABLE E-1 (Cont.) a Federal listings: BLM = listed by the BLM as sensitive; C = candidate for listing; E = listed as endangered; ESA = Endangered Spe

for listing as threatened; T = listed as threatened; XN = experimental population, nonessential. b State listings: CO = Colorado; E = listed as endangered; SC = listed as species of special concern; T = listed as threatened; UT = U

c States and counties within species range in which species is listed and oil shale or tar sands projects could occur. d Oil shale basins or tar sands areas in which species could occur based on published distributions. e NL = not listed. Sources: Goodrich and Neese (1986); UDWR (1998, 2011, 2012); Colorado Rare Plant Technical Committee (2012); Keinath et al. (2

NatureServe (2012); WYNDD (2012); Flora of North America (2008); Natural Resources Conservation Service (2007); Utah State Un
Final OSTS PEIS E-56 

REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

CDOW (Colorado Division of Wildlife), 2012, Natural Diversity Information Source Wildlife 

Species Page. Available at http://ndis.nrel.colostate.edu/wildlife.asp. Accessed June 11, 2012. 

Colorado Rare Plant Technical Committee, 2012, Colorado Rare Plant Field Guide. Available at 

http://www.cnhp.colostate.edu/rareplants/cover.html. Accessed June 11, 2012. 

Flora of North America Association, 2008, Flora of North America. Available at 

http://www.fna.org/FNA/. Accessed June 11, 2012. 

Goodrich, S., and E. Neese, 1986, Uinta Basin Flora, USDA Forest Service Intermountain 

Region, Ogden, Utah. 

Keinath, D., et al., 2003, Wyoming Plant and Animal Species of Concern, Wyoming Natural 

Diversity Database, University of Wyoming, Laramie, Wyo. Available at http://uwadmnweb. 

uwyo.edu/WYNDD/SOC/2003_WYNDD_SOC.pdf. Accessed June 30, 2006. 

Natural Resources Conservation Service, 2007, Plants Database, U.S. Department of 

Agriculture. Available at http://plants.usda.gov/. Accessed April 17, 2006. 

NatureServe, 2012, NatureServe Explorer: An Online Encyclopedia of Life, Version 7.1, 

Arlington, Va. Available at http://www.natureserve.org/explorer. Accessed June 11, 2012. 

UDWR (Utah Division of Wildlife Resources), 1998, Inventory of Sensitive Species and 

Ecosystems in Utah—Endemic and Rare Plants of Utah: An Overview of their Distribution and 

Status, Salt Lake City, Utah, June. Available at http://dwrcdc.nr.utah.gov/ucdc/ViewReports/ 

plantrpt.pdf. Accessed July 4, 2006. 

UDWR, 2011, Utah’s State-Listed Species by County. Available at http://dwrcdc.nr. 

utah.gov/ucdc/ViewReports/sscounty.pdf. Accessed June 11, 2012. 

UDWR, 2012, Utah Conservation Data Center. Available at http://dwrcdc.nr.utah.gov/ucdc/. 

Accessed June 11, 2012. 

Utah State University, 2007, Digital Atlas of the Vascular Plants of Utah. Available at 

http://earth.gis.usu.edu/plants/. Accessed July 31, 2012. 

WYNDD, 2012, Wyoming Natural Diversity Database. Available at http://uwadmnweb. 

uwyo.edu/wyndd/. Accessed June 11, 2012. 
Final OSTS PEIS F-1 

APPENDIX F: 

PROPOSED CONSERVATION MEASURES 

FOR OIL SHALE AND TAR SANDS LEASING AND DEVELOPMENT 

 
Final OSTS PEIS F-2 

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Final OSTS PEIS F-3 

APPENDIX F: 

PROPOSED CONSERVATION MEASURES 

FOR OIL SHALE AND TAR SANDS LEASING AND DEVELOPMENT 

 The following conservation measures were developed for the oil shale and tar sands 

program in consultations between the Bureau of Land Management (BLM) and U.S. Fish and 

Wildlife Service (USFWS) (both in the U.S. Department of the Interior) to support the 

conservation of species listed under the Endangered Species Act (ESA), BLM-listed sensitive, 

and state-listed species, as well as those species that may be protected under the Bald and Golden 

Eagle Protection Act and the Migratory Bird Treaty Act. For purposes of this programmatic 

environmental impact statement (PEIS), these conservation measures are assumed to be 

generally consistent with existing conservation agreements, recovery plans, and completed 

consultations. It is the intent of the BLM and USFWS to ensure that the conservation measures 

presented here are consistent with those currently applied to other land management actions 

whose associated impacts are similar. However, it is presumed that potential impacts from the 

development alternatives described in this PEIS are likely to vary in scale and intensity when 

compared with the impacts associated with other land management actions (e.g., oil and gas 

exploration and production, surface mining, and underground mining). Hence, final conservation 

measures will be developed to be commensurate with the expected levels of impact on selected 

alternatives and to be consistent with agency policies. Current BLM guidance on similar actions 

(e.g., fluid mineral leasing) requires that the stipulation that is least restrictive yet effectively 

accomplishes the resource objectives or resource uses for a given alternative shall be used, while 

compliance with the ESA is maintained. 

F.1 GENERAL CONSERVATION MEASURES 

1. All post-lease activities will be required to comply with the ESA, Bald and 

Golden Eagle Protection Act, and the Migratory Bird Treaty Act. 

2. Surveys will be required prior to operations, unless information on species 

occupancy and distribution in the area under consideration is complete and 

available. All surveys must be conducted by qualified individual(s) approved 

by the BLM. For bald and golden eagles, Mexican spotted owls, and other 

raptors, surveys shall be conducted up to 1 mi from the proposed disturbance 

to determine nest and roost status and will be conducted in accordance with 

existing guidelines. Surveys for listed plant and animal species will follow 

established protocols approved by the USFWS. 

3. Lease activities, upon the start of their implementation, will require 

monitoring throughout the duration of the project. To ensure that the desired 

results are being achieved, mitigation measures will be evaluated, and, if 

necessary, Section 7 consultation will be reinitiated. 
Final OSTS PEIS F-4 

4. Water production will be managed to ensure the maintenance or enhancement 

of riparian habitat and surface water quality. 

5. Loss of riparian and wetland habitats resulting from mining and in situ 

processing activities will be avoided where possible. Loss of riparian and 

wetland habitats resulting from activities associated with roads, pipelines, and 

other ancillary facilities will be minimized. Wetland and riparian habitats will 

be restored when it has not been possible to avoid impacts from facilities on 

them. Avoidance is particularly important when facilities are within or 

adjacent to designated critical habitat for listed species. 

6. Transportation management plans will be developed in a manner that 

minimizes habitat fragmentation and destruction. 

F.2 SPECIES-SPECIFIC CONSERVATION MEASURES 

F.2.1 Colorado River Endangered Fishes: Bonytail, Colorado Pikeminnow, 

 Humpback Chub, Razorback Sucker 

1. Within 0.5 mi of critical habitat, (a) all mining and drilling activities will be 

avoided and (b) surface disturbance and the removal of vegetation for roads, 

pipelines, water diversion and acquisition facilities, and other ancillary 

facilities will be minimized. When surface disturbance within 0.5 mi of 

critical habitat is needed to address any of the elements in item b, the BLM 

shall confer with the USFWS regarding minimizing potential impacts on 

critical habitat and/or endangered fish. 

2. With regard to tributaries of major rivers that contain listed fish species or 

their designated critical habitat, no building of permanent structures, no 

drilling, and no mining will occur in the 100-year floodplains or riparian 

corridors that are within those rivers’ zones of influence. 

3. To avoid excessive stream sedimentation during the spawning period, 

construction activities (e.g., for roads, pipelines, utilities) will be avoided 

within critical habitat from April 1 through September 30 of any year. 

4. The installation of water diversion structures that might pose a risk to 

Colorado River fishes or their critical habitat will be avoided (e.g., screens 

or baffles will be used to minimize entrainment or impingement). If water 

withdrawal or diversion structures are installed, they will have to incorporate 

3/32-in. fish screens. 

5. Pump intakes are prohibited from backwaters or off channel floodplain 

wetlands to minimize impacts on fish larvae. 
Final OSTS PEIS F-5 

6. The release of selenium into surface waters will be avoided, and, where 

possible, measures will be implemented to reduce selenium concentrations in 

the Upper Colorado River Basin. For example, (a) erosion in areas with 

selenium-rich soils (e.g., shale-derived soils) will be decreased, (b) adequate 

vegetative cover will be maintained on work areas where possible, 

(c) ephemeral stream flow will be controlled with water-spreading structures, 

(d) areas with selenium-rich soils will not be irrigated, and (e) causing impacts 

on selenium-rich soils on steep (>50%) slopes will be avoided. If seleniumrich slag/waste piles are created, they shall be isolated and located so this 

material does not reach critical habitat. 

7. All new pipelines and other controlled surface uses that cross within 0.5 mi of 

critical habitat or areas that drain into critical habitat of the Colorado River 

fishes will adhere to the following stipulations: 

a. Pipelines shall not be constructed in known spawning sites or backwaters. 

b. No work in the active river channel will take place between July 1 and 

September 30 in order to avoid adverse effects from sedimentation during 

spawning and times when larval fishes are drifting in the river channel. 

c. After construction, the streambed will be returned to preconstruction 

contours. 

d. Pipelines transporting substances other than water will have automatic 

shut-off valves. 

e. Pipelines transporting substances other than water will be double-walled 

wherever they cross the 100-year floodplain and river. 

f. A spill/leak contingency plan will be developed prior to pipeline use. 

8. The Utah Oil and Gas Pipeline Crossing Guidance (from the BLM National 

Science and Technology Center) will be implemented. 

9. If water for project-related activities is obtained from any surface water source 

(stream, pond, etc.) or from any groundwater source that has a connection to 

surface water, the BLM will require that all water withdrawals undergo 

appropriate Section 7 consultation in accordance with procedures existing at 

the time of the proposed action. Currently, according to the Colorado River 

Recovery Program’s Section 7 Agreement, new water depletions are handled 

as follows: 

a. For average annual depletions that are more than 100 acre-ft but less than 

or equal to 4,500 acre-ft (i.e., the USFWS’s current “sufficient progress” 

threshold), the applicant pays a one-time depletion fee (which is adjusted 
Final OSTS PEIS F-6 

annually to the consumer price index); the fiscal year (FY) 2012 rate is 

$19.21/acre-ft. 

b. For average annual depletions that are more than 4,500 acre-ft, the 

applicant pays the depletion fee, and the BLM (acting on behalf of the 

applicant) and USFWS select (an) action(s) from the Colorado River 

Recovery Implementation Plan’s Recovery Action Plan that must be 

completed before the impacts of the proposed action occur. 

10. The following best management practices for in-stream work that is upstream 

from or near critical habitat will be carried out: 

a. Flows shall be allowed to bypass the construction activity at all times. 

Earthen dams and dewatering activities that will create fish barriers shall 

be avoided. 

b. Hazardous fish habitats, such as isolated areas (i.e., ponds or puddles), 

shall not be created or shall be cleared by trained professionals with 

adequate permits. 

c. Care shall be taken to minimize sedimentation inputs to the river that 

result from stream bed disturbance by storing excavated material outside 

the stream channel. 

d. Best management practices shall be used to ensure construction-related 

by-products do not enter the riverine ecosystem and have negative effects 

on aquatic organisms. 

e. Equipment shall be cleaned to remove noxious weeds, seeds, and 

petroleum products before it is moved on-site. 

f. Machinery shall be fueled outside the ephemeral channel to prevent 

spillage into waterways. 

g. Fill materials shall be free of waste, pollutants, and noxious weeds and 

seeds. 

h. Excavated soils shall be sorted into mineral soils and topsoils. When a 

disturbed site is being backfilled, topsoils shall be placed on top to provide 

a seed bed for native plants. After construction, disturbed areas (work 

sites, ingress, egress, stockpile sites, pit) shall be revegetated with native 

plants or certified as weed-free native seed. The planting shall be 

monitored for success. If the planting fails, the soil shall be reseeded/ 

planted. 
Final OSTS PEIS F-7 

F.2.2 Colorado River Cutthroat Trout 

1. A buffer that is a minimum of 0.25-mi wide on both sides of occupied 

cutthroat trout streams and upstream tributaries will be maintained. The buffer 

will be extended beyond the 0.25-mi minimum in areas where slopes exceed 

50%; it will extend out to where the land is relatively level. The idea is to 

keep any sediment from reaching occupied cutthroat trout reaches by ensuring 

that mining and drilling take place on flat ground in areas where these fish 

occur. Linear features, such as roads and pipelines, may be allowed within the 

buffer zones. Only a handful of known cutthroat trout populations occur in the 

oil shale and tar sands planning area, and these conservation measures will 

affect only a very small portion of the area proposed for leasing (5% or less). 

2. No water will be withdrawn from waters occupied by Colorado River 

cutthroat trout. 

3. Oil shale and tar sands activities will be consistent with the June 2006 

Conservation Agreement for Colorado River Cutthroat Trout (Oncorhynchus 

clarkia pleuriticus) in the States of Colorado, Utah, and Wyoming (CRCT 

Conservation Team 2006). 

F.2.3 Bald Eagle and Golden Eagle1

1. A buffer of 1 mi from known bald eagle nests and 0.5 mi from golden eagle 

nests will be maintained year-round. This buffer can be reduced if topographic 

and/or vegetative buffers exist between the nest and the potentially disturbing 

activity. This avoidance requirement may be adjusted on the basis of a 

demonstration of nonoccupancy during the last 7 years. Any modification will 

be done in coordination with the USFWS. 

2. A year-round avoidance requirement of 0.5 mi from known winter roost 

sites will be maintained. This buffer can be reduced if topographic and/or 

vegetation buffers exist between the roost and development activity. This 

avoidance requirement may be adjusted on the basis of a demonstration of 

 

1 Nesting and wintering dates can vary by location. Contact local USFWS office for dates specific to a given area. 

The USFWS issued updated regulations for take of bald and golden eagles and their nests under Title 50, Part 22, 

Sections 22.26 and 22.27 of the Code of Federal Regulations (50 CFR Part 22, §§ 22.26 and 22.27) to define 

“take” of an eagle to include actions such as “pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, 

or molest or disturb.” In 2009, the USFWS issued regulations (50 CFR 22.3) that define “disturb” as to “agitate 

or bother a bald or golden eagle to a degree that causes, or is likely to cause, based on the best scientific 

information available, (1) injury to an eagle, (2) a decrease in its productivity, by substantially interfering with 

normal breeding, feeding, or sheltering behavior, or (3) nest abandonment, by substantially interfering with 

normal breeding, feeding, or sheltering behavior.” Take of bald and golden eagles, including any disturbance 

defined above, would require a permit from the USFWS. 
Final OSTS PEIS F-8 

nonoccupancy during the last 7 years. Any modification will be done in 

coordination with the USFWS. 

3. Loss of or disturbance to riparian habitats containing cottonwoods, conifers, 

or other tree species that, when mature, may provide roost or nest trees for 

bald eagles will be avoided. Loss of any other riparian plant species (including 

box elders, willows, and river birch) will be minimized. The alteration or 

removal of cliff habitat in golden eagle nesting habitats will be avoided. 

4. The USFWS recommends that the BLM and contractors be informed of the 

risk or potential for vehicle collisions with wildlife (particularly eagles) in the 

project area and be requested to limit vehicle speed to reduce this potential. In 

addition, contractors shall move any big game carcasses found along project 

area roads away from the roadway by 30 ft (generally 60-ft-wide rights-ofway [ROWs]) to minimize potential vehicle collisions with eagles while they 

feed on roadside carrion. Moreover, in an additional effort to protect eagles, 

the BLM and contractors will coordinate with appropriate officials regarding 

any required removal of big game carcasses along county or state roads. 

5. To preclude eagles or other raptors from nesting on human-made structures, 

such as cell phone towers and condensate tanks, and to avoid impeding 

operation or maintenance activities, anti-perching devices will be installed on 

structures to discourage their use by eagles and other raptors. 

6. Electric lines will be buried wherever practicable, especially in areas heavily 

used by eagles. If power lines cannot be buried, they will be built so that they, 

at a minimum, meet the standards identified by the Avian Power Line 

Interaction Committee (2006) to decrease the potential for electrocution (see 

Suggested Practices for Raptor Protection on Power Lines: The State of the 

Art in 2006, http://www.eei.org/products_and_services/descriptions_and_ 

access/suggested_pract.htm). Moreover, power lines will be built according to 

the additional specifications listed below. The project proponent shall ensure 

that these additional standards to minimize eagle deaths associated with 

electric utility distribution lines will be incorporated into the stipulations for 

all project actions. Note that the effectiveness of these measures in minimizing 

mortality varies; thus, the measures may be modified as they are tested in the 

field and laboratory. Local habitat conditions shall be considered in 

determining their use. The USFWS does not endorse any specific product that 

can be used to prevent and/or minimize mortality. The following 

recommendations shall be incorporated into the design plans for new 

distribution lines or when existing facilities are being modified. 

 For new distribution lines and facilities: 
Final OSTS PEIS F-9 

a. Raptor-safe structures (e.g., with increased conductor-conductor spacing) 

that address adequate spacing for eagles (i.e., minimum of 60 in. for bald 

eagles) are to be used. 

b. Equipment installations (e.g., overhead service transformers, capacitors, 

reclosers) shall be made eagle-safe (e.g., by insulating the bushing 

conductor terminations and using covered jumper conductors). 

c. Jumper conductor installations (e.g., corner and tap structures) shall be 

made eagle-safe by using covered jumpers or providing adequate 

separation. 

d. Arrestor and cutout covers shall be employed when necessary. 

e. Lines shall avoid high-avian-use areas, such as wetlands, prairie dog 

towns, and grouse leks. 

For modification of existing facilities: 

a. Problem structures that include dead ends, tap or junction poles, 

transformers, reclosers and capacitor banks, or other structures with less 

than 60 in. between conductors or a conductor and ground shall be 

identified and rectified. 

b. Exposed jumpers will be covered. 

c. Any pole-top ground wires will be capped. 

d. Grounded guy wires shall be isolated by installing an insulating link. 

e. On transformers, insulated bushing covers, covered jumpers, and cutout 

covers and arrestor covers shall be installed, if necessary. 

f. When bald eagle mortalities occur on existing lines and structures, bald 

eagle protection measures shall be applied (e.g., modify for raptor-safe 

construction, install safe perches or perching deterrents, install nesting 

platforms or nest-deterrent devices). 

g. In areas where mid-span collisions are a problem, install line-marking 

devices that have been proven effective. All transmission lines that span 

streams and rivers shall maintain proper spacing and have markers 

installed. 

h. If topographic issues or impacts on vegetative or wildlife resources have 

been identified at the construction site, poles will be moved 
Final OSTS PEIS F-10 

7. When communication towers are being constructed, refer to the USFWS 

Guidance on the Siting, Construction, Operation, and Decommissioning of 

Communication Towers, found at http://www.fws.gov/migratorybirds/ 

currentbirdissues/hazards/towers/comtow.html. 

F.2.4 Mexican Spotted Owl2

1. Within the range of the Mexican spotted owl, surface disturbance will be 

avoided wherever suitable nesting habitat for the species occurs (steep-walled, 

rocky canyons, typically with a closed canopy of mature, mixed coniferous 

forest) (USFWS 1995, Recovery Plan for the Mexican Spotted Owl,

particularly Table III.B.1). (The range of the Mexican spotted owl that was 

published in the recovery plan shall be extended to include the individuals 

observed within Dinosaur National Monument.) 

2. In areas in which Mexican spotted owl habitat has not been analyzed, the 

BLM will assess and map the potential habitat for this species by using 

established protocols prior to leasing of mineral rights for oil shale and tar 

sands. This mapping effort will be a broad-based approach, from which more 

specific and intensified habitat analyses could be initiated. The BLM will 

notify prospective bidders of the presence of Mexican spotted owl habitat and 

the need for special considerations for managing this species. 

3. Where possible, field surveys for the Mexican spotted owl will be conducted 

in areas of suitable habitat. The surveys shall follow established USFWS 

protocols. This information will increase the knowledge base on the 

distribution and status of Mexican spotted owls throughout areas with oil 

shale and tar sands potential in Utah and Colorado. Field surveys will 

emphasize areas that have not been previously or recently surveyed. Areas of 

particular interest include the southern Book Cliffs and areas surrounding 

Dinosaur National Monument. 

4. Once leases are issued, a more in-depth analysis of Mexican spotted owl 

habitat will be required in areas where leases overlap with potential habitat for 

the species. The habitat needs to be assessed for both nesting and foraging by 

using accepted habitat models in conjunction with field reviews. If the habitat 

is determined to be suitable, management considerations shall include the 

avoidance of suitable habitat by at least 0.5 mi. If avoidance is not possible, 

then, unless species occupancy and distribution information is complete and 

available, site-specific surveys will be needed to determine occupancy. 

5. Apply the conservation measures below if project activities occur within 

0.5 mi of suitable owl habitat: 

 

2 Contact local USFWS office for breeding season dates specific to a given area. 
Final OSTS PEIS F-11 

a. Determine the potential effects of actions on owls and their habitat. 

b. Document the type of activity, the acreage and locations of direct habitat 

impacts, and the type and extent of indirect impacts relative to the location 

of suitable owl habitat. 

c. Document if the action is temporary or permanent. A temporary action is 

one that is completed prior to the following breeding season, leaves no 

permanent structures, and results in no permanent habitat loss. A 

permanent action is one that continues for more than one breeding season 

and/or causes a loss of owl habitat or displaces owls through disturbances 

(such as the creation of a permanent structure). 

6. For all temporary actions that may impact owls or suitable habitat: 

a. If the action will occur entirely outside the owl breeding season 

(e.g., March 1 to August 31 in Utah) and leaves no permanent structure 

or permanent habitat disturbance, the action can proceed without the need 

for an occupancy survey. 

b. If the action will occur during a breeding season, a survey for owls shall 

be performed before the activity commences. If owls are found, the action 

must be delayed until it occurs outside the breeding season. 

c. Access routes created by the project shall be rehabilitated through 

measures such as raking out scars, revegetation, and gating access points. 

7. For all permanent actions that may impact owls or suitable habitat: 

a. For 2 consecutive years before activities commence, a survey for owls will 

be conducted according to an accepted protocol. 

b. If owls are found, no actions will occur within 0.5 mi of any identified 

nest site. If the nest site is unknown, no activity will occur within the 

designated protected activity center. 

c. Drilling and the establishment of permanent structures within 0.5 mi of a 

location with suitable habitat will be avoided, unless the location has been 

surveyed and found to not be occupied. 

d. Noise will be reduced (e.g., by using hospital-grade mufflers) to 45 dBA 

at 0.5 mi from suitable habitat, including canyon rims. The placement of 

permanent noise-generating facilities shall be determined by a noise 

analysis to ensure that noise does not encroach upon a 0.5-mi buffer for 

suitable habitat, including canyon rims. 
Final OSTS PEIS F-12 

e. Disturbances to and within suitable habitat will be limited by staying on 

approved routes. 

f. The number of new access routes created by the project will be limited. 

8. Surface disturbance (e.g., facilities, roads, pipelines) and vegetation removal 

will be avoided within designated critical habitat and locations where any of 

the primary constituent elements are present at the project scale. 

F.2.5 Southwestern Willow Flycatcher 

1. All potential habitats for southwestern willow flycatcher within prospective 

lease areas will be identified prior to leasing for oil shale and tar sands 

exploration and development. The BLM will notify prospective bidders of the 

presence of flycatcher habitat and the need for special considerations for 

managing this species. 

2. Surveys for the southwestern willow flycatcher shall be conducted in project 

areas near suitable habitat for the species and in project areas potentially 

occupied by the species. 

3. Project activities will maintain a 300-ft buffer from suitable riparian habitat all 

year long. 

4. Project activities within 0.25 mi of occupied breeding habitat will not occur 

during the breeding season of May 1 to August 15. 

5. The USFWS recommends that post-activity surveys for southwestern willow 

flycatchers be conducted for any project or mitigation areas authorized by the 

BLM. Surveys must be conducted by individuals who have been properly 

trained in the approved survey protocol. Surveyors must be familiar with 

and adhere to the general survey techniques and guidelines found in 

Sogge et al. (2010). Surveyors must complete flycatcher survey training prior 

to being permitted to conduct surveys. All reporting requirements must be 

followed. 

6. For projects that may alter or destroy habitat and are located in or near 

occupied, suitable, potentially suitable, or potential habitat, the USFWS 

recommends using fences instead of flags to delineate the project area. 

Fencing is more visible to construction workers and more clearly demarcates 

the construction zone. 

7. If nest parasitism is monitored, when flycatcher nest parasitism exceeds 10% 

of surveyed nests, the USFWS will be consulted with regard to implementing 

any measures to reduce parasitism rates. 
Final OSTS PEIS F-13 

F.2.6 Black-Footed Ferret 

1. Prior to leasing for oil shale or tar sands exploration or development, prairie 

dog towns that could potentially be occupied by black-footed ferrets or are 

within 1 mi of prairie dog towns that are occupied by black-footed ferrets 

shall be surveyed and mapped by qualified individuals approved by the 

BLM before surface-disturbing activities are conducted. Surveys shall be 

in accordance with the 1989 Black-Footed Ferret Survey Guidelines

(USFWS 1989) or with other methods that the USFWS has reviewed and 

approved. The BLM will notify prospective bidders of the presence of blackfooted ferrets and the need for special considerations managing this species. 

Mapping shall be conducted in accordance with Biggins et al. (1993). If blackfooted ferrets or signs of them are observed within a prairie dog town or 

complex where project-related activities are proposed, the BLM shall 

coordinate Section 7 consultation or conferencing with the USFWS on the 

proposed action. This measure applies to (1) all habitats occupied by ferrets 

and (2) all suitable habitats within the oil shale and tar sands area. The BLM 

will confer with the appropriate USFWS field office for definitions of suitable 

habitat within each state. 

In Wyoming, if no ferrets or signs of them are observed during the survey, 

ground-disturbing activities may occur within 1 year of the date of survey 

completion within the town surveyed. However, surveys shall be completed as 

close to the date of project initiation as possible to avoid the possibility of a 

ferret moving into the area after surveys have cleared the area. Alternatively, 

all suitable habitat within the entire complex in which the town is located may 

be surveyed. If no ferrets or sign are found, the complex will be designated 

“ferret-free,” and no further Section 7 review for the black-footed ferret will 

be required for activities occurring within any prairie dog town within the 

complex. Future observations of ferrets or their sign shall, however, require 

re-initiation of Section 7 consultation. The BLM and the project proponent are 

encouraged to work with the USFWS to “block clear” all prairie dog towns 

within or contiguous to the analysis area. Future actions (including 

maintenance, work over, and reclamation within towns previously cleared of 

ferrets) may require additional survey work unless the entire complex 

containing the town has been block cleared. 

Results of all surveys shall be reported to the appropriate USFWS field office. 

Results can include maps of the areas surveyed; information on surveyor 

qualifications and the survey method, length, dates, weather, snow cover, and 

results; and copies of field data sheets. 

2. The placement of structures that provide suitable nest or perch sites for avian 

predators will be avoided within large prairie dog towns. Garbage will be 

contained so it does not attract coyotes, skunks, and other predators. This 

measure will apply to (1) all habitats occupied by ferrets and (2) all suitable 
Final OSTS PEIS F-14 

habitat within the oil shale and tar sands area. The BLM will confer with the 

appropriate USFWS field office regarding definitions of suitable habitat 

within each state. 

3. Reduced vehicle speeds at night will be posted and encouraged on roads in or 

near occupied habitat to reduce the chance of vehicles causing mortalities. 

4. Reclamation will be conducted so that impacts to active prairie dog colonies 

are minimized. This measure applies to all suitable habitats within the oil 

shale and tar sands area. The BLM will confer with the appropriate USFWS 

field office regarding definitions of suitable habitat within each state. 

5. In areas where black-footed ferrets could be encountered, employees, 

operators, and contractors shall be educated on the natural history of the 

black-footed ferret, the identification of ferrets and their sign, the potential 

impacts associated with the transmission of diseases from dogs to ferrets, 

activities that may affect ferret behavior, and ways to minimize these effects. 

This measure applies to all suitable habitats within the oil shale and tar sands 

area. The BLM will confer with the appropriate USFWS field office regarding 

definitions of suitable habitat within each state. 

6. Observations of black-footed ferrets, their sign, or carcasses shall be reported 

to the nearest BLM and USFWS office within 24 hours. This measure applies 

throughout the oil shale and tar sands area. 

7. The use of “White-Tailed Prairie Dog Conservation Measures” (as revised) 

will be encouraged in white-tailed prairie dog habitat. 

8. Whenever possible, project activities will be designed to avoid any adverse 

influence on prairie dog habitat occupied by black-footed ferrets. If adverse 

impacts to occupied prairie dog habitat are unavoidable, activities will be 

designed in coordination with the USFWS to (1) impact the smallest area 

practicable, (2) impact those areas with the lowest prairie dog densities, and 

(3) minimize habitat fragmentation in prairie dog towns occupied by blackfooted ferrets or towns suitable for their reintroduction. Off-site mitigation 

may also be recommended. Impacts on black-footed ferret habitat will be 

monitored to evaluate cumulative effects. 

9. Whenever possible, project activities will be designed to not adversely impact 

black-footed ferret populations. A monitoring program will be developed, 

when necessary, to evaluate impacts. This measure applies to all habitats 

occupied by ferrets within the oil shale and tar sands area. 

10. Project activities in Uintah and Duchesne Counties, Utah, will be conducted 

in a manner consistent with the Utah Division of Wildlife Resources 2007 

publication, Northeastern Region Black-Footed Ferret Management Plan, and 
Final OSTS PEIS F-15 

the BLM 1999 publication, Book Cliffs Resource Area Management Plan 

Amendment for Black-Footed Ferret Reintroduction, Coyote Basin Area, 

Utah. 

11. This measure applies specifically to the black-footed ferret management area 

and subcomplexes described by the Utah Division of Wildlife Resources’ 

2007 publication, Northeastern Region Black-Footed Ferret Management 

Plan. Within the boundaries of the three subcomplexes (Coyote Basin, Snake 

John Reef, Bohemian Bottom), activities involving the development or 

construction of features that could cause permanent surface disturbances will 

be prohibited within 0.125 mi of the home range of any black-footed ferret. 

Within the boundaries of the management area, if the observation of a ferret 

has been recorded within the last 5 years, no surface disturbance will be 

allowed within 0.44 mi of the observation location if the following two 

criteria are met: (1) if the ferret observed in suitable habitat (the BLM will 

confer with the appropriate USFWS field office regarding definitions of 

suitable habitat within the management area) and (2) if the ferret has 

established residency in the immediate locale (i.e., if a documented home 

range has been established). The appropriate size of the protected area 

surrounding a ferret’s home range may be adjusted in coordination with the 

USFWS to coincide with future research and new information and pursuant to 

the relevant local, site-specific species management plan, if available. 

F.2.7 Canada Lynx3

1. Within a Lynx Analysis Unit (LAU), ensure that mapping of lynx habitat, 

nonhabitat, and denning habitat occurs. Foraging habitat and topographic 

features important for lynx movement shall also be mapped. All lynx habitat 

within an LAU shall be identified as being in suitable or unsuitable condition. 

This effort involves interagency coordination where LAUs cross 

administrative boundaries. 

2. Disturbance within each LAU shall be limited to 30% of the suitable habitat 

within the LAU. If 30% of the habitat within an LAU is currently in 

unsuitable condition, no further reduction in the amount of suitable conditions 

shall be allowed to occur as a result of management activities. To assess 

cumulative effects, oil and gas production and transmission facilities, mining 

activities and facilities, dams, timber harvests, and agricultural lands shall be 

mapped on public lands, and projects on adjacent private lands shall be 

evaluated. This effort will involve interagency coordination where LAUs 

cross administrative boundaries, primarily with the U.S. Forest Service. 

 

3 Landscape linkages may be the only issues. 
Final OSTS PEIS F-16 

3. Management actions shall not change more than 15% of lynx habitat within an 

LAU to an unsuitable condition within a 10-year period. This effort will 

involve interagency coordination where LAUs cross administrative 

boundaries. 

4. Denning habitat shall be maintained in patches that are generally larger than 

5 acres and compose at least 10% of lynx habitat. Where less than 10% is 

currently present within an LAU, any management actions that will delay 

development of denning habitat structures will be deferred. This effort will 

involve interagency coordination where LAUs cross administrative 

boundaries. 

5. Key linkage areas that may be important in providing landscape connectivity 

within and between geographic areas across all ownerships will be identified 

by using the best available science. 

6. Habitat connectivity within and between LAUs will be maintained. 

7. Observations of lynx (tracks or sightings, along with date, location, and 

habitat) will be documented and provided to the state natural heritage 

database. An annual update on all sightings will be requested from the 

database for review. 

8. If there has been a large wildfire, a post-disturbance assessment will be 

conducted prior to salvage harvest, particularly in stands that were formerly 

in late successional stages, to evaluate their potential for lynx denning and 

foraging habitat. 

9. On projects that require over-snow access, such access will be restricted to 

designated routes. 

10. Within lynx habitat, the BLM shall ensure that key linkage areas and potential 

highway crossing areas are identified by using the best available science. 

11. The BLM shall ensure that proposed land exchanges, land sales, and special 

use permits are evaluated for their effects on key linkage areas. 

12. If activities in lynx habitat are proposed, the BLM shall ensure that 

stipulations and conditions of approval for limitations on the timing of 

activities and surface use and occupancy are developed for leasing, and that 

more site-specific conditions of approval are developed at the permitting 

stage. Examples include requiring that activities not be conducted at night 

(when lynx are active) and avoiding activity near denning habitat during the 

breeding season (April or May to July) to protect vulnerable kittens. 
Final OSTS PEIS F-17 

13. The continuation of foraging habitat in proximity to denning habitat shall be 

provided for. 

14. Habitat conditions that support dense, horizontal, understory cover and high 

densities of snowshoe hares shall be provided through time. An example 

of such a habitat is mature, multistoried, conifer vegetation. Vegetation 

management, including timber harvests and the use of prescribed fires, will 

focus on areas that have the potential to improve snowshoe hare habitat 

(dense, horizontal cover) but presently have poorly developed understories 

of little value to snowshoe hares. 

15. Areas where high total road densities (more than 2 mi of roads per mi2) 

coincide with lynx habitat shall be determined, and roads in those areas will 

be priorities for seasonal restrictions or reclamation. 

16. Public use of temporary roads constructed for project activities will be limited. 

New roads, especially at the entrance, will be designed so they can be 

effectively closed upon completion of project activities. Upon project 

completion, these roads will be reclaimed or obliterated. 

17. The building of roads directly on ridge tops or areas identified as important 

for lynx habitat connectivity will be minimized. 

18. Where needed, measures to reduce mortality risk, such as wildlife fencing and 

associated underpasses or overpasses, will be developed. 

19. Existing snowshoe hare and red squirrel habitats will be protected. 

20. Remote sensing equipment will be used and bunch maintenance activities will 

be implemented to reduce activity in the area and to reduce the compaction of 

snow. 

F.2.8 Threatened, Endangered, and Proposed Plants4 

1. All potential habitat for proposed, candidate, and listed species shall be 

identified prior to leasing for oil shale or tar sands exploration and 

development. The BLM will notify prospective bidders of the presence of 

these sensitive plant species and the need for special considerations for 

managing these species. Within these potential habitat areas, surveys that 

follow established protocols shall be conducted to better understand these 

populations and where conservation efforts shall be focused. 

 

4 Refer to the PEIS for a list of all threatened, endangered, and proposed plants. 
Final OSTS PEIS F-18 

 On leased parcels with the potential to impact sensitive plant species, surveys 

that follow established protocols will be conducted prior to any development 

activities. Surveys shall be conducted when the plant can be detected and 

during appropriate flowering periods. Surveys shall extend at least 600 ft 

beyond the perimeter of work areas. Surveys are generally valid for 1 year. 

2. Consistent with existing or current recovery plans, the proposed action will be 

designed to support recovery objectives. For example: 

a. Designs will prevent surface runoff from work areas from entering plantoccupied habitat. 

b. Construction will occur below and away from the slope of occupied 

habitat, where feasible, to avoid slope failure or accelerated erosion. 

c. No surface disturbance will occur within 300 ft of a listed plant. If an area 

that is less than 600 ft from a listed plant must be disturbed (e.g., for 

mining, drilling, roads, pipelines), the edge shall be temporarily fenced to 

keep disturbance from further approaching the listed plant’s habitat. To 

avoid working in listed plant habitats and to avoid drawing attention to 

listed plants, the edge of disturbance, not the nearby plant population, shall 

be fenced. This measure could be modified with the approval of the BLM 

and USFWS. 

d. If a surface disturbance must be located less than 600 ft from a listed 

plant, appropriate dust-abatement actions, commensurate with the level of 

use, must be conducted, in consultation with the USFWS and BLM. 

3. If ground-disturbing activities occur within 600 ft of listed plants, the plants 

shall be monitored in accordance with the 1998 publication, Measuring and 

Monitoring of Plant Populations, BLM Technical Reference 1730-1, during 

the blooming period to track the plants’ health and vigor and the occurrence 

of dust transported from project activities. Data shall also include a site 

description with global positioning system (GPS) coordinates, the size of 

the area occupied, the estimated number and range in age of the plants, 

and evidence of habitat disturbance and plant damage or mortality. Postconstruction monitoring for invasive species must also be conducted. Annual 

reports shall be provided to the BLM and USFWS. 

4. “Translocation” (transplanting) will not be considered as a conservation 

measure. 

5. Vehicle travel will avoid suitable and occupied habitat. 

6. In consultation with USFWS, projects that remove topsoil in areas of suitable 

habitat for listed species shall be evaluated. The topsoil shall be set aside and 
Final OSTS PEIS F-19 

replaced when ground work is completed to preserve the seed bank and 

associated mycorrhizal species and to discourage invasive species. 

7. When possible, revegetation shall be limited to native species that will not 

compete with the rare species at the site. Revegetation projects shall require 

a site-specific plan for areas with listed plant species, to be developed in 

consultation with the BLM and USFWS. 

8. Protective stipulations for endangered or threatened species shall include 

appropriate measures to protect pollinator species that have been identified. 

9. When listed plant species are near project areas, dust control measures will be 

determined in consultation with the BLM and USFWS. These measures shall 

be employed to minimize the deposition of fugitive dust on plant surfaces. 

10. For riparian and wetland-associated species (e.g., Ute ladies’-tresses), any 

water extraction or disposal practices shall not result in a change in the 

hydrologic regime outside the range of natural variability. 

11. Produced oil, water, or condensate tanks will be placed in centralized 

locations away from occupied habitat. Evaporation ponds shall be located so 

their overspray falls at least 600 ft away from listed plant locations, if such 

ponds are necessary. 

F.2.9 Species Determined Not To Be within the Action Area 

F.2.9.1 Gray Wolf 

 (Per discussion with USFWS, wolves are not within the action area, so they will not be 

addressed in the PEIS or biological assessment [BA].)

F.3 CANDIDATE ANIMAL SPECIES DETERMINED TO BE WITHIN THE 

 ACTION AREA 

F.3.1 Greater Sage-Grouse 

 The greater sage-grouse may occur in lease areas in all three states. Suggested measures 

for the management of greater sage-grouse populations and their habitat are provided in 

Section 4.8.1.4. These measures include the following: 

1. Identify and avoid both local (daily) and seasonal migration routes. 
Final OSTS PEIS F-20 

2. Consider greater sage-grouse and sagebrush habitats when designing, 

constructing, and utilizing project access roads and trails. 

3. When possible, avoid siting energy developments in breeding habitats. 

4. Adjust the timing of activities to minimize disturbance to greater sage-grouse 

during critical periods. 

5. When possible, locate energy-related facilities away from active leks or other 

greater sage-grouse habitat. 

6. When possible, restrict noise levels to 10 dB above background noise levels at 

lek sites. 

7. Minimize nearby human activities when birds are near or on leks. 

8. As practicable, do not conduct surface-use activities within crucial greater 

sage-grouse wintering areas from December 1 through March 15. 

9. Maintain sagebrush communities on a landscape scale. 

10. Provide compensatory habitat restoration for impacted sagebrush habitat. 

11. Avoid the use of pesticides at greater sage-grouse breeding habitats during the 

brood-rearing season. 

12. Develop and implement appropriate measures to prevent the introduction or 

dispersal of noxious weeds. 

13. Avoid creating attractions for raptors and mammalian predators in greater 

sage-grouse habitat. 

14. Consider measures to mitigate impacts at off-site locations to offset the 

unavoidable alteration and reduction of greater sage-grouse habitat at the 

project site. 

15. When possible, avoid establishing artificial water bodies (e.g., stormwater and 

liquid industrial wastewater ponds) that could serve as breeding habitat for 

mosquitoes. 

F.3.2 Yellow-Billed Cuckoo 

 (This species is within the action area only in Utah, and because it is a candidate species, 

it will not be addressed in the BA, but these conservation measures will be in the PEIS.)
Final OSTS PEIS F-21 

1. All riparian areas shall be surveyed to identify suitable habitat for this species 

prior to leasing for oil shale or tar sands exploration and development. The 

BLM will notify prospective bidders of the presence of these sensitive plant 

species and the need for special considerations for managing these species. 

2. Potential habitat for this species shall be avoided by maintaining a 0.25-mi 

buffer. If suitable habitat for this species is present within a proposed 

development area, surveys shall be conducted to determine species 

occupancy. 

3. If mining activities cannot be avoided in riparian habitat, the project shall be 

designed to avoid the removal of large cottonwood trees and shall not occur 

from June 1 through August 1. 

4. To avoid direct impacts on or changes in riparian habitat, stream channel 

morphology or annual streamflow regimes in suitable habitat shall not be 

adversely modified. 

5. Non-surface-disturbing activities within yellow-billed cuckoo habitat that will 

have adverse effects on the bird or its habitat (e.g., boat and raft landings, 

outfitting camps, firewood collection) shall be prohibited within 0.25 mi of 

occupied habitat. 

6. Pesticides shall not be applied within 0.25 mi of habitat occupied by the 

yellow-billed cuckoo. 

7. If technically feasible, biological control shall be used in place of chemical 

pest control. 

F.4 MIGRATORY BIRDS 

 During site-specific post-leasing activities, impacts on migratory birds and their habitats 

will be evaluated and minimized, with emphasis on species that are on Birds of Conservation 

Concern 2008 (USFWS 2008) and species that are listed among the “Partners in Flight” Priority 

Species. To help meet the responsibilities identified in Executive Order 13186 (“Responsibilities 

of Federal Agencies to Protect Migratory Birds”), BLM recommends that (a) exploration and 

mining activities be conducted outside critical breeding seasons for migratory birds, 

(b) temporary and long-term habitat losses be minimized, and (c) unavoidable habitat losses be 

compensated for. 
Final OSTS PEIS F-22 

F.5 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

Biggins, D.E., et al., 1993, “A Technique for Evaluating Black-Footed Ferret Habitat,” pp. 73–87 

in Management of Prairie Dog Complexes for Reintroduction of the Black-Footed Ferret,

Biological Report 1993-13, J.L. Oldemeyer et al. (editors), U.S. Fish and Wildlife Service. 

CRCT Conservation Team, 2006, Conservation Agreement for Colorado River Cutthroat Trout 

(Oncorhynchus clarkii pleuriticus) in the States of Colorado, Utah, and Wyoming, Colorado 

Division of Wildlife, Fort Collins, Colo. 

Sogge, M.K., et al., 2010, A Natural History Summary and Survey Protocol for the Southwestern 

Willow Flycatcher (Chapter 10 of Section A, Biological Science, of Book 2, Collection of 

Environmental Data), Techniques and Methods 2A-10, U.S. Geological Survey in cooperation 

with Bureau of Reclamation and U.S. Fish and Wildlife Service. 

USFWS (U.S. Fish and Wildlife Service), 1989, Black-Footed Ferret Survey Guidelines for 

Compliance with the Endangered Species Act, Denver, Colo., and Albuquerque, N.M., April. 

Available at http://www.fws.gov/mountain-prairie/endspp/protocols/BFFSurveyGuideline 

1989.pdf. Accessed Nov. 17, 2011. 

USFWS, 1995, Recovery Plan for the Mexican Spotted Owl: Vol. I, Albuquerque, N.M. 

USFWS, 2008, Birds of Conservation Concern 2008, Division of Migratory Bird Management, 

Arlington, Va., Dec. Available at http://library.fws.gov/bird_publications/bcc2008.pdf. Accessed 

Nov. 17, 2011. 
Final OSTS PEIS G-1 

APPENDIX G: 

SOCIOECONOMIC AND ENVIRONMENTAL JUSTICE 

ANALYSIS METHODOLOGIES 
Final OSTS PEIS G-2 

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Final OSTS PEIS G-3 

APPENDIX G: 

SOCIOECONOMIC AND ENVIRONMENTAL JUSTICE 

ANALYSIS METHODOLOGIES 

The analysis of the socioeconomic impacts of oil shale and tar sands development in 

Colorado, Utah, and Wyoming consists of two interdependent parts. The analysis of economic 

impacts estimates the impacts of construction and operation of oil shale and tar sands facilities 

and associated power plants, coal mines, and temporary housing on local employment and 

income. Because of the relative economic importance of oil shale and tar sands development in 

small rural economies and the consequent incapacity of local labor markets to provide sufficient 

workers in the appropriate occupations required for development, construction, and operation in 

sufficient numbers, oil shale and tar sands development is likely to result in a large influx of 

temporary population. Given these considerations, the analysis of social impacts assesses the 

potential impacts of oil shale and tar sands development on population, housing, local public 

service employment and expenditures, crime, alcoholism, illicit drug use, divorce rates, and 

mental illness. Also covered is social disruption; since it may occur with rapid population growth 

and the “boom and bust” economic development associated with oil shale and tar sands facilities, 

a review of the literature on social disruption is included. Finally, under social impacts, the 

analysis covers environmental justice impacts on minority and low-income populations. 

The analysis assesses the impacts of oil shale and tar sands development and the 

associated power plants, coal mines, and temporary housing in a region of influence (ROI) in 

each state. The ROIs consists of the counties and communities most likely to be impacted by oil 

shale and tar sands development (see Section 3.11.2 of this programmatic environmental impact 

statement [PEIS]). Selection of these counties was based on counties used in the Final 

Environmental Statement for the Prototype Oil Shale Leasing Program (DOI 1973). 

G.1 ECONOMIC IMPACTS ON LOCAL EMPLOYMENT AND INCOME 

The analysis of socioeconomic impacts of oil shale and tar sands development, power 

plants, coal mines, and temporary housing on regional employment and income was conducted 

for the PEIS by using direct employment data in association with regional economic multipliers. 

G.1.1 Direct Employment Data 

To provide appropriate direct employment estimates for the analysis, a review of a 

number of relevant documents was undertaken, including Final Environmental Statement for the 

Prototype Oil Shale Leasing Program (DOI 1973); Final Environmental Impact Statement, 

Proposed Development of Oil Shale Resources by The Colony Development Operation in 

Colorado (BLM 1977); Final Programmatic Environmental Impact Statement, Development 

Policy Options for the Naval Oil Shale Reserves in Colorado (DOE 1982); Final Supplemental 

Environmental Impact Statement for the Prototype Oil Shale Leasing Program (BLM 1983a); 
Final OSTS PEIS G-4 

Final Environmental Impact Statement, Uintah Basin Synfuels Development (BLM 1983b); and 

Utah Combined Hydrocarbon Leasing Regional Final Environmental Impact Statement

(BLM 1984). Following this review, direct employment data were taken from a number of 

different sources. 

G.1.1.1 Oil Shale Facilities 

Direct employment data for the construction and operation of surface and underground 

mine facilities with surface retorting for the development of oil shale resources were based on 

data taken from the Final Environmental Statement for the Prototype Oil Shale Leasing Program

(DOI 1973). Data on oil shale developments using in situ processing under Alternatives B and C 

were available from Thompson (2006a). For Alternative A (No Action Alternative), data were 

based upon numbers presented in the four environmental assessments prepared by the companies 

conducting oil shale research, development, and demonstration projects (BLM 2006ac; 2007). 

Employment numbers for oil shale facilities are presented in Section 4.12.1. 

G.1.1.2 Tar Sands Facilities 

 Construction and operations direct employment data for tar sands facilities were available 

in the Utah Combined Hydrocarbon Leasing Regional Final Environmental Impact Statement

(BLM 1984), but only for two technologies (surface mining and in situ processing) and only for 

two production levels (190,000 bbl/day and 175,000 bbl/day, respectively). These values were 

converted to direct employment values per 1,000 bbl/day, as shown in Table G-1. 

For the socioeconomic assessment, direct employment was estimated as an average of all 

the assessed tar sands development technologies on the basis of a 20,000-bbl/day production 

level. To estimate per facility direct employment values, a general assumption of 40,000 bbl/day 

per facility was used as representative of a typical commercial tar sands project. The per facility 

values were then estimated as direct or total 

values times the ratio of the per facility 

production to the total production. 

G.1.1.3 Power Plants and Coal Mines 

Power plant construction and operations 

direct employment data were taken from 

Thompson (2006b,c), which described a 

1,500-MW plant proposed for Ely, Nevada. 

Employment data for coal mines were from 

U.S. Department of Energy (DOE) (2007a,b,c) 

and industry sources (Hill and Associates 2007). 

TABLE G-1 Input Data for Tar Sands Direct 

Employment Estimates 

Action 

Direct Employment 

(FTE/1,000 bbl/day)a

 

Surface mining, construction 50.5 

Surface mining, operations 34.6 

In situ, construction 68.9 

In situ, operations 12.8 

a FTE = full-time equivalent. 

Source: BLM (1984). 
Final OSTS PEIS G-5 

G.1.2 Temporary Housing Construction Data 

The impacts of the construction of temporary housing were assessed by using estimates 

of the number of in-migrating direct and indirect workers and accompanying family members, 

with updated construction labor cost factors taken from the Final Environmental Statement for 

the Prototype Oil Shale Leasing Program (DOI 1973). 

G.1.3 Economic Multipliers 

Economic multipliers captured the indirect (off-site) effects of construction and operation 

of oil shale and tar sands facilities and associated power plants and housing developments. 

Multipliers for each ROI were derived from IMPLAN input-output economic accounts for each 

ROI (MIG, Inc. 2007). These accounts show the flow of commodities to industries from 

producers and institutional consumers, consumption activities carried out by workers and owners 

of capital, and imports from outside the region. Each IMPLAN model contains 528 sectors 

representing industries in agriculture, mining, construction, manufacturing, wholesale and retail 

trade, utilities, finance, insurance and real estate, and consumer and business services. Each 

model also includes information for each sector on employee compensation; proprietary and 

property income; personal consumption expenditures; federal, state, and local expenditures; 

inventory and capital formation; imports; and exports. 

IMPLAN multipliers for 2004 for oil and gas extraction, coal mining, new residential 

construction, power generation and supply, manufacturing and industrial buildings, and personal 

consumption expenditure were used to estimate the indirect impacts of oil shale and tar sands 

and ancillary project development and temporary housing in each state ROI. 

Assumptions that were made in the analysis about the expected pattern of procurement 

within the ROI for the various materials and equipment and the extent of local wage and salary 

spending by oil shale and tar sands facility and power plant workers and temporary housing 

construction workers are described in Section 4.12 of this PEIS. 

Impacts on ROI employment are described in terms of the total number of jobs (direct 

plus indirect) created in the region in the peak year of construction and in the first year of 

operation of oil shale and tar sands facilities and the associated power plants and temporary 

housing construction. Impacts on ROI income are described in terms of total income generated 

by direct and indirect construction and operations activities. The relative impact of the increase 

in employment in the ROI was calculated by comparing total oil shale and tar sands development 

construction employment over the period in which construction is expected to occur with 

baseline ROI employment forecasts over the same period. Forecasts were based on data provided 

by the U.S. Department of Commerce (2007). 
Final OSTS PEIS G-6 

G.2 SOCIAL IMPACTS 

G.2.1 Population 

An important consideration in the assessment of impacts of oil shale and tar sands 

development is the number of workers, families, and children that would migrate into the ROI, 

either temporarily or permanently, with the construction and operation of oil shale and tar sands 

facilities, power plants, and temporary housing. The capacity of regional labor markets to 

provide workers in the appropriate occupations required for oil shale and tar sands development 

construction and operation in sufficient numbers is closely related to the occupational profile of 

the ROI and occupational unemployment rates. Assumptions made about the number of 

in-migrating oil shale and tar sands facility, power plant, temporary housing construction, and 

indirect workers required to produce goods and services resulting from increased local demand 

associated with oil shale and tar sands facility, power plant, and temporary housing worker wage 

and salary spending are described in Section 4.12, together with the number of workers bringing 

family members into each ROI. The residential location of in-migrating workers was estimated 

by using a gravity model to assign workers to communities based on population size and distance 

from potential oil shale and tar sands projects (see Section 4.12). The national average household 

size was used to calculate the number of additional family members accompanying direct and 

indirect in-migrating workers. 

 Impacts on population are described in terms of the total number of in-migrants arriving 

in the region in the peak year of construction. The relative impact of the increase in population in 

the ROI was calculated by comparing total oil shale and tar sands development construction 

in-migration over the period in which construction is projected with baseline ROI population 

forecasts over the same period. Forecasts were based on data provided by the three states 

(Colorado State Demography Office 2007; Utah Governor’s Office of Planning and 

Budget 2007; Wyoming Department of Administration and Information 2006). 

G.2.2 Housing 

The in-migration of workers occurring during construction and operation associated with 

oil shale and tar sands facility and power plant development would substantially affect the 

housing market in the ROI in the absence of temporary housing developments. The analysis 

considered these impacts by estimating the increase in demand for vacant housing units in the 

peak year of construction resulting from the in-migration of direct oil shale and tar sands facility, 

power plant, and indirect workers into each ROI. The relative impact on existing housing in the 

ROI was estimated by calculating the impact of oil shale and tar sands–related housing demand 

on the forecasted number of vacant housing units in the peak year of construction. Forecasts 

were based on data provided by the three states (Colorado State Demography Office 2007; Utah 

Governor’s Office of Planning and Budget 2006; Wyoming Department of Administration and 

Information 2006). 
Final OSTS PEIS G-7 

G.2.3 Public Services 

Population in-migration associated with construction and operation of oil shale and tar 

sands facilities and the associated power plants and temporary housing construction workers 

would translate into increased demand for educational services and for public services (police, 

fire protection, health services, etc.) in each ROI. The impacts of in-migration associated with oil 

shale and tar sands and power generation facilities on county, city, and school district revenues 

and expenditures were based on per capita expenditure data provided in the jurisdictions’ annual 

comprehensive financial reports (see Section 3.11). Impacts on public service employment were 

calculated by using the existing levels of service (the number of employees per 1,000 people 

required to provide each community service) to estimate the number of new police officers, 

firefighters, and general government employees required in the peak year of construction and 

first year of operations. Similarly, the number of teachers in each school district required to 

maintain existing teacher-student ratios across all student age groups was estimated. Impacts on 

health care employment were estimated by calculating the number of physicians in each county 

required to maintain the existing level of service, based on the existing number of physicians per 

1,000 population, and the number of required additional staffed hospital beds to maintain the 

existing level of service, based on the existing number of staffed beds per 1,000 population. 

Information on existing employment and levels of service was collected from the individual 

jurisdictions providing each service (see Section 3.11). 

G.2.4 Social Disruption 

The relative economic importance of oil shale and tar sands facilities and associated 

power plant and temporary housing developments is likely to create a large influx of temporary 

population both during construction and at the start of the operation phases of each project. 

Because population increases are likely to be rapid, and in the absence of adequate planning 

measures, local communities may be unable to quickly cope with the large number of new 

residents; social disruption and changes in social organization are likely to occur. Community 

disruption can also lead to increases in social distress; in particular, increases in drug use, 

alcoholism, divorce, juvenile delinquency, and deterioration in mental health and perceived 

quality of life. Changes in cultural values may also occur as the resident population is exposed 

to, and may be required to at least partially adapt to, the cultural values of the in-migrant 

population. 

 The assessment of the impacts of oil shale and tar sands development on social disruption 

was based on a literature review drawing on past experience of social change associated with 

resource development projects in rural areas, particularly developments that have led to “boom 

and bust” economic development in communities in the western United States, where rapid 

in- and out-migration and the associated community upheaval occurred both during and after 

resource extraction. Extensive literature in sociology (in the journals Rural Sociology, Pacific 

Sociological Review, and Sociological Perspectives, among others) is available on the problems 

of community adjustment. The review included the social impacts of a wide range of energy 

developments, including coal mining, oil and gas development, and power generation in the 

western states, in addition to the social impacts that have occurred with past oil shale and tar 
Final OSTS PEIS G-8 

sands development. The review also included studies of the social impacts of oil shale and tar 

sands development in Colorado, Utah, and Wyoming identified in the Final Environmental 

Statement for the Prototype Oil Shale Leasing Program (DOI 1973) and in five EISsColony 

Oil Shale Final EIS (BLM 1977), Naval Oil Shale Reserves Final Programmatic EIS 

(DOE 1982), Prototype Oil Shale Leasing Program Final Supplemental EIS (BLM 1983a), 

Uintah Basin Synfuels Development Final EIS (BLM 1983b), and Utah Combined Hydrocarbon 

Leasing Regional Final EIS (BLM 1984). 

Social disruption and the resulting community adjustment that may occur in small, 

relatively self-contained communities arising from “boom and bust” surges in population size 

may have a number of components (Figure G-1). A “boom” stimulus provides new jobs that 

bring growth in population size and change the demographic composition of the community. 

Social change resulting from the need to accommodate new residents changes the perceived 

quality of life and leads to changes in social relations. Social problems, such as divorce, 

substance abuse, and crime, can occur. Social problems may be mitigated by community 

planning and management of growth, allowing the community to more easily adjust to new 

residents. After some period of time, employment associated with the boom may decrease, 

whereby the community may replace the jobs afforded by the initial economic stimulus or, as is 

more likely, employment is reduced in size by a “bust,” whereby the cycle of adjustment is 

repeated, mitigated to a greater or lesser degree by community planning efforts. 

G.2.5 Environmental Justice 

Executive Order 12898 (U.S. President 1994) formally requires federal agencies to 

incorporate environmental justice as part of their missions. Specifically, it directs agencies to 

address, as appropriate, any disproportionately high and adverse human health or environmental 

Time

Small 

stable 

community

Energy/

Economic

“Boom”

Stimulus

Demographic

Change

•Population Size

•Composition

Social Change

•Accommodation of “Newcomers”

•Perceived QOL Change

•Rearrangement of social positions

•Social problems

Community Planning and Management

•Infrastructure upgrades

•Expansion of social services

•Health & Medical expansion

•Law enforcement expansion

Reduced

Energy/Economic

Boom 

Stimulus

Community 

“Readjustment”

To modified

Social Reality

Community

Bust

New Jobs

Replace Boom

Stimulus

Time

Small 

stable 

community

Energy/

Economic

“Boom”

Stimulus

Demographic

Change

•Population Size

•Composition

Social Change

•Accommodation of “Newcomers”

•Perceived QOL Change

•Rearrangement of social positions

•Social problems

Community Planning and Management

•Infrastructure upgrades

•Expansion of social services

•Health & Medical expansion

•Law enforcement expansion

Reduced

Energy/Economic

Boom 

Stimulus

Community 

“Readjustment”

To modified

Social Reality

Community

Bust

New Jobs

Replace Boom

Stimulus

FIGURE G-1 The Cycle of Social Adjustment to “Boom” and “Bust” 
Final OSTS PEIS G-9 

effects of their actions, programs, or policies on minority and low-income populations. The 

analysis of the impacts of oil shale and tar sands development on environmental justice issues 

follows guidelines described in the Council on Environmental Quality’s Environmental Justice 

Guidance under the National Environmental Policy Act (CEQ 1997). 

 The analysis method has three parts: (1) a description of the geographic distribution of 

low-income and minority populations in the affected area; (2) an assessment of whether the 

impacts of construction and operation would produce impacts that are high and adverse; and 

(3) a determination about whether these impacts disproportionately impact minority and 

low-income populations. The description of the geographic distribution of minority and 

low-income groups is based on demographic data from the 2000 Census. To fully evaluate the 

potential environmental justice impacts of the oil shale and tar sands development, the 

distribution of minority and low-income populations is described at the census block level. On 

the basis of data at the individual block level, the minority and low-income population within a 

50-mi buffer zone around each oil shale and tar sands resource location was analyzed. 

G.3 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

BLM (Bureau of Land Management), 1977, Final Environmental Impact Statement, Proposed 

Development of Oil Shale Resources by The Colony Development Operation in Colorado, Vols. I 

and II, U.S. Department of the Interior. 

BLM, 1983a, Final Supplemental Environmental Impact Statement for the Prototype Oil Shale 

Leasing Program, Colorado State Office, Denver, Colo., Jan. 

BLM, 1983b, Final Environmental Impact Statement, Uintah Basin Synfuels Development, 

Vol. 1, U.S. Department of the Interior, Feb. 

BLM, 1984, Utah Combined Hydrocarbon Leasing Regional Final EIS, Volume I: Regional 

Analyses, Utah State Office, Salt Lake City, Utah, June. 

BLM, 2006a, Environmental Assessment, Chevron Oil Shale Research, Development & 

Demonstration, CO-110-2006-120-EA, White River Field Office, Meeker, Colo., Nov. 

BLM, 2006b, Environmental Assessment, EGL Resources, Inc., Oil Shale Research, 

Development & Demonstration Tract, CO-110-2006-118-EA, White River Field Office, Meeker, 

Colo., Oct. 

BLM, 2006c, Environmental Assessment, Shell Oil Shale Research, Development and 

Demonstration Projects, Rio Blanco, Colorado, CO-110-2006-117-EA, White River Field 

Office, Meeker, Colo., Nov. 
Final OSTS PEIS G-10 

BLM, 2007, Environmental Assessment, Oil Shale Research Development and Demonstration 

Project, White River Mine, Uintah County, Utah, UT-080-06-280, Vernal Field Office, Vernal, 

Utah, April. 

CEQ (Council on Environmental Quality), 1997, Environmental Justice Guidance under the 

National Environmental Policy Act, Executive Office of the President, Washington, D.C. 

Available at http://www.whitehouse.gov/CEQ/. Accessed July 2006. 

Colorado State Demography Office, 2007, State Demography Office. Available at 

http://www.dola.state.co.us/demog/. Accessed March 2007. 

DOE (U.S. Department of Energy), 1982, Final Programmatic Environmental Impact Statement, 

Development Policy Options for the Naval Oil Shale Reserves in Colorado, Assistant Secretary, 

Environmental Protection, Safety and Emergency Preparedness, Office of Naval Petroleum and 

Oil Shale Reserves, Aug. 

DOE, 2007a, Energy Information Administration, Coal Production and Number of Mines by 

State and Mine Type. Available at http://www.eia.doe.gov/cneaf/coal/page/acr/table1.html. 

Accessed Oct. 5, 2007. 

DOE, 2007b, Energy Information Administration, Average Number of Employees by State and 

Mine Type. Available at http://www.eia.doe.gov/cneaf/coal/page/acr/table18.html. Accessed 

Oct. 5, 2007. 

DOE, 2007c, Energy Information Administration, Electric Power Annual 2005 State Data 

Tables. Available at http://www.eia.doe.gov/cneaf/electricity/epa/epa_sprdshts.html. Accessed 

Oct. 5, 2007. 

DOI (U.S. Department of the Interior), 1973, Final Environmental Statement for the Prototype 

Oil Shale Leasing Program, Volume IV of VI, Consultation and Coordination with Others, 

Washington, D.C. 

Hill and Associates, Inc., 2007, Economic Benefits of a Coal-Fueled Power Plant Compared 

to Natural Gas, prepared for Peabody Energy. Available at http://coalcandothat.com/pdfs/ 

EconBeneCoalFuel.pdf. Accessed Oct. 8, 2007. 

MIG (Minnesota IMPLAN Group, Inc.), 2012, IMPLAN Data Files, Stillwater, Minn. 

Thompson, S., 2006a, personal communication from Thompson (U.S. Bureau of Land 

Management, Washington, D.C., Office) to K. Smith (Argonne National Laboratory, Lakewood, 

Colo.), Nov. 30. 

Thompson, S., 2006b, personal communication from Thompson (U.S. Bureau of Land 

Management, Washington, D.C., Office) to K. Smith (Argonne National Laboratory, Lakewood, 

Colo.), Dec. 6. 
Final OSTS PEIS G-11 

Thompson, S., 2006c, personal communication from Thompson (U.S. Bureau of Land 

Management, Washington, D.C., Office) to K. Smith (Argonne National Laboratory, Lakewood, 

Colo.), Dec. 13. 

U.S. Department of Commerce, 2007, Regional Economic Accounts. Available at 

http://www.bea.gov/bea/regional/reis/default.cfm?catable=CA04. Accessed Jan. 2007. 

U.S. President, 1994, “Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations,” Executive Order 12898, Federal Register 59:7629, 

Feb. 6. 

Utah Governor’s Office of Planning and Budget, 2006, Population Projections by County and 

District. Available at http://www.governor.utah.gov/DEA/Projections/06ProjCountyand 

District.pdf. Accessed July 2006. 

Utah Governor’s Office of Planning and Budget, 2007, 2002 Baseline Projections UPED Model 

System. Available at http://www.governor.utah.gov/dea/LongTermProjections.html. Accessed 

March 2007. 

Wyoming Department of Administration and Information, 2006, Population for Wyoming, 

Counties, Cities, and Towns: 2000 to 2020. Available at http://eadiv.state.wy.us/pop/ 

wyc&sc20.htm. Accessed March 2007. 
Final OSTS PEIS G-12 

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Final OSTS PEIS H-1

APPENDIX H:

APPROACH USED FOR INTERVIEWS OF

SELECTED RESIDENTS IN THE OIL SHALE AND

TAR SANDS STUDY AREA CONSIDERED IN THE 2008 OIL SHALE AND TAR

SANDS PROGRAMMATIC ENVIRONMENTAL IMPACT STATEMENT
Final OSTS PEIS H-2

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Final OSTS PEIS H-3

APPENDIX H:

APPROACH USED FOR INTERVIEWS OF

SELECTED RESIDENTS IN THE OIL SHALE AND

TAR SANDS STUDY AREA CONSIDERED IN THE 2008 OIL SHALE AND TAR

SANDS PROGRAMMTIC ENVIRONMENTAL IMPACT STATEMENT

H.1 PURPOSE

Land use plan amendments to allow for application for leasing and future development of 

oil shale and tar sands resources are being proposed in parts of Colorado, Utah, and Wyoming,

where there has been considerable experience with large-scale energy development, including oil 

and gas, coal mining, electric power generation, and attempts to develop oil shale resources. 

Development of oil shale and tar sands resources is not only likely to produce significant 

impacts on the economies and communities in the regions of influence (ROIs) in each state, but 

would produce impacts occurring alongside rapid development of oil and gas resources. Among 

energy developments, oil shale and tar sands projects, in particular, are often associated with 

“boom-and-bust” type development, requiring local communities to make considerable 

adjustment to rapid economic and social change. In order for this programmatic environmental 

impact statement (PEIS) to provide a comprehensive and understandable presentation of the 

potential scale of the economic and social impacts of oil shale and tar sands development, a 

series of interviews was conducted with residents in the ROIs in each state. These interviews 

provided information that adds anecdotal flavor to the social and economic baseline and impact 

data presented in the PEIS, adding text and verbatim quotations that summarize viewpoints, 

perceptions, and attitudes toward large-scale energy development.

H.2 SAMPLING STRATEGIES

A number of sampling strategies were used to identify a small list of possible respondents 

that could adequately capture some sense of the level of variation in views of the project. 

Specifically, a list of potential interviewees included:

• Individuals who provided comments as part of the oil shale and tar sands 

project scoping process, documented in the Scoping Summary Report;

• Individuals who have witnessed various stages of development associated 

with energy projects, such as impacts on ranching and the associated 

traditional quality of life, including local and county planning officials, 

community leaders, community service providers, environmental groups, 

newspaper reporters, realtors, local citizens groups, and motivated local 

individuals with specific concerns; and
Final OSTS PEIS H-4

• Individuals located in proximity to locations at which energy project 

developments are likely to occur (e.g., Piceance Basin) and who are likely to 

be impacted by specific aspects of project development, such as water 

restrictions, air quality, road congestion, property values, quality of life, etc.

During the interview process, some respondents provided contact information for 

additional individuals that were subsequently interviewed, if it was apparent that these 

individuals would allow the process to provide more complete and balanced coverage of a 

particular topic or topics.

H.3 INTERVIEW FORMAT AND STRUCTURE

Informal interviews were conducted with individuals by telephone, without

questionnaires. After a brief introduction to the project, each interview was structured around a 

series of preselected issues that addressed the perceived concerns and historical experience of 

each interviewee, in order to focus the interview and limit responses to information relevant to 

the presentation in the PEIS. Interviews elicited viewpoints on three general aspects of 

large-scale energy development:

• Past developments, particularly those that have produced “boom-and-bust” 

economic and social conditions deemed relevant;

• The current situation, including the ongoing impact of oil and gas 

development and increased recreational land use; and

• The likely impact of new developments, particularly oil shale and tar sands, 

alongside the projected impact of oil and gas development and recreational 

land use.

Each interview included open-ended questions on the progress of key variables 

throughout the past, present, and future experience with energy development, including housing 

cost and availability, congestion, community service quality and availability, employment, 

quality of life, environmental quality, and other variables identified by respondents, where 

applicable. Respondents were asked to identify and describe their perception of mitigation 

strategies that have been, are being, and might be used in the future.

As it was the intention of each interview to fully capture the viewpoints, perceptions, and 

attitudes toward large-scale energy development in a semistructured format, each interview 

session allowed for some improvisation toward the goal of providing useful anecdotal 

information, including different ways to frame questions and elicit responses, recognizing 

different levels of respondents’ perceived viewpoint, personal and professional participation, and 

residential location. 
Final OSTS PEIS I-1

APPENDIX I:

INSTREAM FLOW WATER RIGHTS

IN THE PICEANCE BASIN, COLORADO
Final OSTS PEIS I-2

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Final OSTS PEIS I-3

TABLE I-1 Colorado Water Conservation Board Instream Flow Tabulation—Water Division 6, White River Basin, Streams in the Oil 

Shale Study Area Protected by Instream Flow Water Rights, April 5, 2012

Case Number Stream Watershed County Upper Terminus Lower Terminus

Length

(mi) USGS Quads Amount (cfs) (dates) 

Approximate

Date

5-08CW094 Black Sulphur 

Creek

Piceance 

Creek-Yellow 

Creek

Rio 

Blanco

Confl Canyon Creek at lat 39 45 

41N long 108 28 11W

Hdgt Duckett Ditch at lat 39 48 

53N long 108 25 45W

5.12 Yankee Gulch 1 (12/1–4/30)

1.6 (5/1–8/31)

1.2 (9/1–11/30)

1/23/2008

5-80CW378 East Fork 

Fawn Creek

Upper White Rio 

Blanco

Headwaters in vicinity of lat 40 

06 07N long 107 31 17W

Confl WF Fawn Creek in NE SW 

S7 T1N R90W 6PM

2.80 Fawn Creek

Lost Park

Oyster Lake

2 (1/1–12/31) 5/7/1980

5-08CW106 East Willow 

Creek

Piceance 

Creek-Yellow 

Creek

Rio 

Blanco,

Garfield

Confl Bull Fork East Willow 

Creek at lat 39 41 33N long 108 

16 55 W

Conf West Willow Creek at lat 

39 43 42N long 108 16 55W

2.69 Bull Fork 0.6 (11/1–4/30)

0.8 (5/1–10/31)

1/23/2008

5-80CW377 West Fork 

Fawn Creek

Upper White Rio 

Blanco

Headwaters in vicinity of lat 40 

06 03N long 107 33 47W

Confl EF Fawn Creek in NE SW 

S7 T1N R90W 6PM

3.00 Fawn Creek 2 (1/1–12/31) 5/7/1980

Totals for Water Division 6 in the Study Area

Total No. of Stream Miles = 13.6

Total No. of Appropriations = 4

Source: http://cwcbweblink.state.co.us/weblink/0/doc/158996/Electronic.aspx?searchid=b7563de2-c9b5-4431-859f-e4064c41687f.
Final OSTS PEIS I-4

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Final OSTS PEIS J-i 

APPENDIX J: 

SUMMARY OF PUBLIC SCOPING COMMENTS FOR THE 

PROGRAMMATIC ENVIRONMENTAL IMPACT STATEMENT AND POSSIBLE 

LAND USE PLAN AMENDMENTS FOR ALLOCATION OF OIL SHALE AND TAR 

SANDS RESOURCES ON LANDS ADMINISTERED BY THE BUREAU OF LAND 

MANAGEMENT IN COLORADO, UTAH, AND WYOMING 

 
Final OSTS PEIS J-ii 

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Final OSTS PEIS J-iii 

CONTENTS 

NOTATION .............................................................................................................................. J-v 

 J.1 INTRODUCTION .................................................................................................. J-1 

 J.2 SCOPING PROCESS ............................................................................................. J-4 

 J.2.1 Approach ..................................................................................................... J-4 

 J.2.2 Scoping Statistics ........................................................................................ J-5 

 J.3 SUMMARY OF SCOPING COMMENTS ............................................................ J-5 

 J.3.1 Environmental Issues .................................................................................. J-6 

 J.3.1.1 Issues within the Scope of the PEIS ............................................ J-6 

 J.3.1.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-18 

 J.3.1.3 Issues outside the Scope of the PEIS ........................................... J-19 

 J.3.2 Socioeconomics .......................................................................................... J-22 

 J.3.2.1 Issues within the Scope of the PEIS ............................................ J-22 

 J.3.2.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-23 

 J.3.2.3 Issues outside the Scope of the PEIS ........................................... J-24 

 J.3.3 Resource and Technology Concerns ........................................................... J-24 

 J.3.3.1 Issues within the Scope of the PEIS ............................................ J-24 

 J.3.3.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-25 

 J.3.3.3 Issues outside the Scope of the PEIS ........................................... J-28 

 J.3.4 Stakeholder Involvement ............................................................................ J-28 

 J.3.4.1 Issues within the Scope of the PEIS ............................................ J-28 

 J.3.4.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-28 

 J.3.4.3 Issues outside the Scope of the PEIS ........................................... J-28 

 J.3.5 Cumulative Impacts .................................................................................... J-29 

 J.3.5.1 Issues within the Scope of the PEIS ............................................ J-29 

 J.3.5.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-29 

 J.3.5.3 Issues outside the Scope of the PEIS ........................................... J-29 

 J.3.6 Mitigation and Reclamation ........................................................................ J-30 

 J.3.6.1 Issues within the Scope of the PEIS ............................................ J-30 

 J.3.6.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-30 

 J.3.6.3 Issues outside the Scope of the PEIS ........................................... J-30 

 J.3.7 Land Use Planning and Leasing ................................................................. J-31 

 J.3.7.1 Issues within the Scope of the PEIS ............................................ J-31 

 J.3.7.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-31 

 J.3.7.3 Issues outside the Scope of the PEIS ........................................... J-32 

 J.3.8 Policy .......................................................................................................... J-32
Final OSTS PEIS J-iv 

 J.3.8.1 Issues within the Scope of the PEIS ............................................ J-32 

 J.3.8.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-33 

 J.3.8.3 Issues outside the Scope of the PEIS ........................................... J-35 

 J.3.9 Alternatives ................................................................................................. J-36 

 J.3.9.1 Issues within the Scope of the PEIS ............................................ J-36 

 J.3.9.2 Issues outside the Scope of the PEIS, but Which May Present 

 Related Policy Considerations ..................................................... J-38 

 J.3.9.3 Issues outside the Scope of the PEIS ........................................... J-38 

 J.3.10 Other Issues ................................................................................................. J-40 

 J.4 INTERAGENCY COOPERATION AND GOVERNMENT-TO- 

 GOVERNMENT CONSULTATION ..................................................................... J-40 

 J.5 FUTURE OPPORTUNITIES FOR PUBLIC INVOLVEMENT ........................... J-41 

 J.6 REFERENCES ....................................................................................................... J-41 

FIGURES 

J-1 Most Geologically Prospective Oil Shale Resources within the Green River 

 Formation Basins in Colorado, Utah, and Wyoming .................................................... J-2 

J-2 Special Tar Sand Areas in Utah .................................................................................... J-3 

 
Final OSTS PEIS J-v 

NOTATION 

 The following is a list of the acronyms and abbreviations, including units of measure, 

used in this report. 

GENERAL ACRONYMS AND ABBREVIATIONS 

ACEC Area of Critical Environmental Concern 

AQRV air-quality-related value 

BLM Bureau of Land Management 

BOR Bureau of Reclamation 

CAA Clean Air Act 

CEQ Council on Environmental Quality 

CFR Code of Federal Regulations

CO Colorado 

CO2 carbon dioxide 

CPW Citizen Proposed Wilderness 

CWA Clean Water Act 

EPA U.S. Environmental Protection Agency 

ESA Endangered Species Act of 1973 

FLPMA Federal Land Policy and Management Act of 1976 

GAO Government Accountability Office 

GHG greenhouse gas 

HIA Health Impact Assessment 

ICP in-situ conversion process 

NAAQS National Ambient Air Quality Standards 

NEPA National Environmental Policy Act of 1969 

NHPA National Historic Preservation Act of 1966 

NLCS National Landscape Conservation System 

NOI Notice of Intent 

NPS National Park Service 

NSO no surface occupancy 

NSS Native Species Status 

NWR National Wildlife Refuge 

ONA Outstanding Natural Area 

OSTS oil shale and tar sands 
Final OSTS PEIS J-vi 

PEIS programmatic environmental impact statement 

PSD Prevention of Significant Deterioration 

R&D research and development 

RD&D research, development, and demonstration 

RFDS reasonably foreseeable development scenario 

RMP Resource Management Plan 

RNA Research Natural Area 

ROD Record of Decision 

ROI return on investment 

SGCN Species of Greatest Conservation Need 

SMA Special Management Area 

STSA Special Tar Sand Area 

SWA State Wildlife Area 

UNCCC United Nations Framework Convention on Climate Change 

USFS U.S. Forest Service 

USFWS U.S. Fish and Wildlife Service 

USGS U.S. Geological Survey 

WA Wilderness Area 

WSA Wilderness Study Area 

UNITS OF MEASURE 

ft foot (feet) 

gal gallon(s) 

mi mile(s) 
Final OSTS PEIS J-1 

APPENDIX J: 

SUMMARY OF PUBLIC SCOPING COMMENTS FOR THE 

PROGRAMMATIC ENVIRONMENTAL IMPACT STATEMENT AND POSSIBLE 

LAND USE PLAN AMENDMENTS FOR ALLOCATION OF OIL SHALE AND TAR 

SANDS RESOURCES ON LANDS ADMINISTERED BY THE BUREAU OF LAND 

MANAGEMENT IN COLORADO, UTAH, AND WYOMING 

J.1 INTRODUCTION 

 In 2008, the U.S. Department of the Interior, Bureau of Land Management (BLM), 

amended eight Resource Management Plans (RMPs) in Colorado, Utah, and Wyoming to make 

public lands available for the potential leasing and development of oil shale resources and also 

two land use plans to expand the acreage available for potential tar sands leasing in Utah, where 

these resources are located. Figures J-1 and J-2 show the locations of oil shale and tar sands 

resources. The amendments, supported by the preparation of a programmatic environmental 

impact statement (PEIS) required under Section 369(d)(1) of the Energy Policy Act of 2005, 

Public Law 109-58 (H.R. 6), made approximately 2 million acres available for potential leasing 

and development of oil shale and approximately 431,000 acres available for potential tar sands 

leasing and development. The Proposed Oil Shale and Tar Sands Resources Management Plan 

Amendments to Address Land Use Allocations in Colorado, Utah, and Wyoming and Final 

Programmatic Environmental Impact Statement (BLM 2008a) and resulting Record of Decision 

(ROD) (BLM 2008b) provide detailed maps and more specific information about the geographic 

area studied in 2008. 

 In April 2011, the BLM initiated new efforts to prepare a PEIS that will reexamine the 

allocation of land best suited for oil shale and tar sands leasing and development. These new 

efforts, which may lead the BLM to consider amending the 10 RMPs previously amended, will 

take into consideration the nascent character of technology for developing oil shale and tar sands 

resources and new information made available since the 2008 ROD, including, but not limited to, 

the U.S. Geological Survey (USGS) reassessment (USGS 2010a,b, 2011) of oil shale resource 

estimates and the U.S. Fish and Wildlife Service’s (USFWS’s) announcement that the greater 

sage-grouse, Centrocercus urophasianus, was warranted for listing as a threatened or endangered 

species under the Endangered Species Act of 1973 (ESA), although the listing was precluded by 

higher-priority listing actions. The new PEIS will analyze and document the environmental, 

social-cultural, and economic considerations associated with alternative approaches for 

allocation of oil shale and tar sands resources, in order to consider whether it is appropriate for 

approximately 2,000,000 acres of public lands to remain available for potential leasing and 

development of oil shale and approximately 431,000 acres of public lands to remain available for 

potential leasing and development of tar sands resources. 

 A Notice of Intent (NOI) to prepare a PEIS and possible land use plan amendments for 

allocation of oil shale and tar sands resources on lands administered by the BLM in Colorado, 

Utah, and Wyoming was published in the Federal Register on April 14, 2011 (BLM 2011). The 

NOI articulated a preliminary purpose and need for the proposed action of amending land use 
Final OSTS PEIS J-2 

FIGURE J-1 Most Geologically Prospective Oil Shale Resources within the Green River 

Formation Basins in Colorado, Utah, and Wyoming (Source: BLM 2008a) 
Final OSTS PEIS J-3 

FIGURE J-2 Special Tar Sand Areas in Utah (Source: BLM 2008a) 

 
Final OSTS PEIS J-4 

plans, identified planning criteria, initiated the public scoping process, and invited interested 

members of the public to provide comments on the scope and objectives of the PEIS, including 

identification of issues and alternatives that should be considered in the PEIS analyses. The NOI 

also sought information about historic and cultural resources within the areas potentially affected 

by the proposed land use plan amendments to assist in analyzing the potential impacts of the 

planning decisionmaking under consideration in the context of both the National Environmental 

Policy Act of 1969 (NEPA) and Section 106 of the National Historic Preservation Act (NHPA). 

 The BLM conducted 14 public scoping meetings for the PEIS within the three-state 

region covered by the PEIS from April 26, 2011, through May 5, 2011. 

 This report presents a summary of the issues raised during the scoping process and 

discusses which issues will be addressed in the PEIS. The report also includes summary statistics 

on participants in the process. Specific comments and their context are not presented; instead, the 

relevant issues raised in the comments as they apply to preparation of the PEIS are presented. All 

comments, regardless of how they were submitted, will receive equal consideration in the 

development and conduct of the PEIS. This report is available on the oil shale and tar sands 

(OSTS) PEIS Web site (http://ostseis.anl.gov). 

J.2 SCOPING PROCESS 

J.2.1 Approach 

 The public was provided with three methods for submitting scoping comments or 

suggestions on potential resource issues that should be discussed in the OSTS PEIS and used to 

inform consultation activities: 

• Via a public Web site, 

• By mail, and 

• In person at public scoping meetings. 

 Public scoping meetings were held at seven locations in April and May of 2011: Salt 

Lake City, Utah (April 26); Price, Utah (April 27); Vernal, Utah (April 28); Rock Springs, 

Wyoming (April 29); Rifle, Colorado (May 3); Denver, Colorado (May 4); and Cheyenne, 

Wyoming (May 5). Meetings were held at 1:00 p.m. and 7:00 p.m. at each location, and a court 

reporter recorded a transcript for each meeting. At each meeting, the BLM presented background 

information about the OSTS PEIS and related activities. Presentation materials from these 

meetings, including slides, are available on the project Web site (http://ostseis.anl.gov). 

 
Final OSTS PEIS J-5 

J.2.2 Scoping Statistics 

 Approximately 4,663 individuals, organizations, and governmental agencies provided 

comments or suggestions on the scope of the PEIS. Three of these comments were part of 

major campaigns, each campaign involving an e-mail attachment containing essentially the 

same letter for each individual submittal. In total, these campaigns represented an additional 

23,860 commentors. Approximately 3,061 comment letters were submitted online; 133 were 

submitted orally and/or in writing at scoping meetings; and 37 comment letters were submitted 

by mail. Comments were received from 5 state agency divisions (1 from Utah, 2 from Colorado, 

and 2 from Wyoming), 4 federal agency offices (1 from the National Park Service [NPS], 

1 from the USFWS, 1 from the U.S. Environmental Protection Agency [EPA], and 1 from the 

U.S. Congressional Task Force on Unconventional Fuels), 14 local government organizations 

(Colorado: Garfield, Mesa, Pitkin, and Rio Blanco Counties; City of Rifle; Towns of New 

Castle, Rangely, and Silt; Utah: Carbon and Uintah Counties; Wyoming: Board of Lincoln 

County Commissioners; Coalition of Local Governments; Rock Springs City Council; and 

Sweetwater County Board of Commissioners), and more than 80 other organizations (including 

environmental groups, interest groups, consulting firms, and industry). 

 More than 392 people registered their attendance at the public meetings in April and 

May 2011; 133 individuals in attendance provided oral or written comments, or both, during the 

meetings. Of the remaining scoping comments that were submitted, about 0.1% were submitted 

by mail and 99% were submitted online. 

 Comments received by mail originated from five states and the District of Columbia. 

Approximately 4% of the comments originated from states outside the three-state study area. The 

comments that originated within the study area were distributed as follows: 81 comments from 

Colorado, 80 comments from Utah, and 14 comments from Wyoming. 

J.3 SUMMARY OF SCOPING COMMENTS 

 Comments received during public scoping covered a wide range of topics and issues and 

represented a variety of points of view. Comments addressed various aspects of the proposed 

action, from environmental and socioeconomic impacts, to technologies, to mitigation and 

reclamation, to land use conflicts, planning, and leasing. Many of the comments did not directly 

address the scope of the PEIS to be prepared but fell into general categories that will influence 

the scope of issues covered in the PEIS. 

 Issues discussed in comments received during the public scoping period for the OSTS 

PEIS are divided into three major categories in the preparation of the PEIS: (1) issues within the 

scope of the PEIS; (2) issues outside the scope of the PEIS, but which may present related policy 

considerations; and (3) issues considered to be outside the scope of the PEIS as defined in the 

April 14, 2011, NOI (BLM 2011). A disposition of these issues is presented below. The scope of 

the Draft PEIS is accordingly shaped by this disposition of issues. 
Final OSTS PEIS J-6 

 Issues within the scope of the PEIS include questions and concerns regarding the 

environmental and socioeconomic impacts of oil shale and tar sands development; resource 

assessments; sources and impacts of power production required for development; technologies to 

be used; stakeholder participation in the NEPA process; cumulative impacts; mitigation and 

reclamation; leasing; multiple use conflicts; consistency of the PEIS with state and local plans; 

land use planning; access to public lands for additional research and development (R&D) outside 

the ongoing oil shale research, development, and demonstration (RD&D) program; and 

development of alternatives to be analyzed. 

 Issues that are outside the scope of the PEIS but that may present related policy 

considerations include those related to reasons for revisiting the PEIS; deferment of decisions 

until RD&D results are available; oil shale regulations and national policy; deferment of analysis 

on environmental consequences to project-level NEPA evaluations; bonding requirements for 

leasing companies to ensure availability of funds for future reclamation; and determining 

commercial royalty rates; and establishment of federal subsidies, incentives, or taxes. 

 Issues that fall outside the scope of the PEIS are those issues that are not pertinent to the 

purpose and need for the proposed land use planning decision as described in the April 14, 2011, 

NOI. These include issues relating to evaluations and support of other energy sources 

(e.g., renewable energy resources, clean technologies, biofuels, geothermal, nuclear power, and 

conventional oil and gas resources); energy conservation measures; price of fossil fuels; sale of 

resulting oil on the international market; support for development on private lands; development 

and use of all fossil fuels and climate change; foreign oil as a national security issue; political 

motivation behind governmental policy; political unrest and instability in oil-producing 

countries; denial/approval of mining permits; and oil shale and tar sands development impacts on 

oil and gas prices. 

 A summary of issues raised in comments is presented in the following sections under the 

following main topics: environmental issues, socioeconomics, resource and technology concerns, 

stakeholder involvement, cumulative impacts, mitigation and reclamation, land use planning and 

leasing, policy, alternatives, and other issues. All of the scoping comments, both oral and written, 

are represented in Sections J.3.1 through J.3.10, although individual comments are not identified 

explicitly. 

J.3.1 Environmental Issues 

J.3.1.1 Issues within the Scope of the PEIS 

 The following text describes the main environmental concerns identified by commentors 

that are within the scope of the PEIS analyses. Several comments expressed concerns over the 

amount of significant disturbance to the surface and subsurface environment possibly resulting 

from the development of oil shale and tar sands resources. Specifically mentioned were 

permanent changes to water quantity and quality, air quality, topography, natural landscapes, 

wildlife habitat and populations, aquatic habitats, vegetation and habitat dynamics, cultural and 
Final OSTS PEIS J-7 

historical resources, human health, and climate, many of which have been observed as a result of 

a similar type of energy development elsewhere (e.g., Canada). The following sections 

summarize the specific comments related to the various environmental resource areas. 

Water Quantity and Quality. Many commentors recommended that perennial waters, 

headwaters, and aquifers should be conserved and receive protection from oil shale and tar sands 

development. Concerns were expressed over the potential declines in overall water quality within 

the study area, specifically noting sources of drinking water, areas with cold water fish resources, 

Wilderness Areas (WAs), and locations of intensive recreational use. It was suggested that the 

PEIS assess the impacts on the health and livelihood of those downstream, including effects on 

fisheries, wildlife, riparian zones, and wetland areas. It was also suggested that there be a buffer 

beneath and on either side of all perennial water courses in which no development can occur to 

safeguard these water ways, ensure the safety of wildlife, and protect underlying geologic 

groundwater formations. 

 In addition, a few commentors stated the importance of addressing and evaluating the 

beneficial and deleterious impacts of water transfers, such as shifting from current agricultural 

uses to industrial uses (i.e., activities related to oil shale and tar sands), since they can lead to 

dislocations and environmental alterations (e.g., soil erosion or sediment loading) in the affected 

regions. 

 Concerns were raised regarding regional and state water demand and use for the 

development and production of oil shale and tar sands resources, along with related impacts on 

availability, existing water uses, reliability of supply, and consequences for users in the affected 

region. Specifically, commentors observed that the processes would consume large amounts of 

water in a region where water resources are very limited. Many commentors questioned where 

the water would be obtained from, who would lose water in order to provide needed water to oil 

shale and tar sands development, and what the resulting effects would be (e.g., ranchers’ water 

rights and their ability to sustain crops and livestock). They also noted that the holding of water 

rights by oil shale and tar sands developers introduces enormous uncertainty on the system and 

regional water planning. Some commentors noted that less water than most estimates predicted 

will be needed for oil shale and tar sands development based on technologies currently being 

pursued and the fact that existing groundwater resources contained within the oil shale strata may 

be sufficient to produce nearly all of the oil shale in the basin without directly drawing from the 

Colorado River. In addition, some technologies do not use tailing ponds (e.g., bitumen extraction 

from oil sands), and 95% of the water used in the process can be recycled. It was also suggested 

that the BLM take into account the potential changes in water demand from other social, 

commercial, and economic developments in the region, as well as the impacts of climate change. 

In addition, it was mentioned that the PEIS must consider and evaluate water use and related 

activities from oil shale and tar sands development in the context of existing agreements 

(e.g., protection of endangered species), prior obligations (e.g., 1922 Colorado River Compact), 

and potential future commitments (e.g., Lower Colorado River Protection Act, Grand Canyon 

Watersheds Protection Act). 
Final OSTS PEIS J-8 

 Commentors stated that the impact of water derived from the development and 

production of oil shale and tar sands resources must also be addressed in the PEIS. It was 

suggested that the PEIS assess the entire water use cycle and consider what will ultimately 

happen to the water (e.g., potential reuse options). Other topics identified include descriptions 

and assessments of the facilities, technologies, and processes associated with the exploitation of 

oil shale and tar sands resources, leachate and surface runoff, wastewater treatment techniques, 

wastewater quantity and quality, discharge methods, potential for pipeline corrosion and leaks, 

and prevention and mitigation measures. Specifically noted were concerns about the creation of 

acid drainage, increased loadings of current pollutants (e.g., thiocyanates, tetrathionates, fluoride, 

cyanide, arsenic selenium, and other heavy metals), leaching of spent shale, introduction of new 

contaminants, alteration of flow patterns, changes in temperature, and increased salinity in 

regional surface water and groundwater resources. Assessment of the impacts of these issues on 

fisheries, riparian zones, and wetland areas was requested. It was also recommended that the 

PEIS include available and updated information since 2008, including information from 

development activities at RD&D lease sites on expected contaminants and from a reference 

study (Bartis et al. 2005) that found the burden of spent shale had significantly higher salt levels 

than raw shale and may yield other toxic substances. 

 Commentors stated that the PEIS should specifically analyze the impacts of grounddisturbing activities, such as extraction mining and in situ processing. Concerns were expressed 

related to the alteration of geological formations, aquifer hydraulic characteristics, groundwater 

flow patterns, subsurface water quality and contamination, and impacts on recharge of deepwater aquifers. Specifically, hydraulic fracturing practices in the development of shale oil and 

gas reserves were identified as causing contamination to drinking water supplies, which is 

currently being studied by the EPA. Commentors stated, whether true or not, that because oil 

shale and tar sands development involves such practices, the BLM has an obligation to review 

and analyze new and relevant data for inclusion in the environmental analysis. In addition, one 

commentor noted that the subsurface rock that remained after the oil shale was depleted would 

become a new aquifer and questioned how it would be cleaned to prevent leftover contaminants 

from leaching out into the ground water. 

 Finally, a few commentors made note of the U.S. Government Accountability Office 

(GAO) Water Report (GAO 2010), which reported on water usage and risks associated with the 

ultimate development of this resource. In general, commentors agreed with the importance of the 

research and the need to establish baseline conditions for water resources in oil shale regions, to 

model groundwater movement, and to coordinate with U.S. Department of Energy (DOE) and 

state agencies involved in water regulation. However, one commentor asserted that the report 

was not objective in terms of examination of water usage from oil shale technologies and costs, 

and that it offered improbable, theoretical operational scenarios for water demand. The 

commentor added that responsible, low-impact, and sustainable water usage is both technically 

and economically feasible for the industry, and thus suggested that the BLM perform its own 

objective examination of available technologies and costs. 

Waste Generation and Disposal. Concerns were voiced that the mining, extraction, and 

processing of oil shale and tar sands resources will create toxic waste materials, including: heavy 
Final OSTS PEIS J-9 

metals (e.g., mercury, lead, and arsenic); naphthenic acids; polycyclic aromatic hydrocarbons 

(e.g., pyrene and naphthalene), and volatile organic compounds (e.g., terpenes). These materials 

have the potential to leach into the environment, migrate from the oil shale and tar sands 

facilities, produce dust and contaminate nearby water resources and ecosystems (see the Water 

Quantity and Quality discussion above). The importance of measuring ore product and waste 

stream mass flows was noted. 

Air Quality, Noise, and Visual Impacts. Comments were received regarding concern 

over the unknown, yet potentially significant and far-reaching, impacts on local and regional air 

quality associated with oil shale and tar sands exploration, development, and associated activities 

(e.g., power generation, construction, and transportation). Potential impacts identified by 

commentors covered all stages of development (i.e., mining and processing through 

transportation of product) and included deterioration of overall air quality; higher levels of 

pollutants from emissions (e.g., ozone, sulfur dioxide, particulate matter, fugitive dust, volatile 

organic compounds, hazardous air pollutants, carbon dioxide [CO2], and other greenhouse 

gases); deleterious effect on humans, wildlife, and the environment; increased nitrogen 

deposition; impaired regional visibility; and impact of dust on mountain snow causing early 

snowpack melt and decreased tourism. Issues explicitly mentioned for ozone were wintertime 

conditions and projected oil shale and tar sands–related sources of ozone precursors and other 

emissions. Another commentor suggested utilizing data requirements, resource needs, 

constraints, and known impacts from technologies being utilized as part of existing applications 

and RD&D efforts (e.g., Shell’s oil shale research facility and American Shale Oil’s downhole 

burning process). 

 In general, commentors also asserted that both regional and local air quality concerns 

were not adequately addressed in the 2008 OSTS PEIS. Baseline air quality monitoring and 

on-site meteorological data collection in the planning areas were requested for all criteria 

pollutants. 

 With respect to air quality mitigation and in light of current technological uncertainties 

related to oil shale and tar sands development and operations, it was recommended that the BLM 

discuss potential control technologies, abatement measures, best management practices, and 

other design considerations that may minimize air pollutant emissions. 

 For noise impacts, commentors requested that background noise levels be established and 

recommended the use of audibility-based metrics for noise-sensitive areas rather than threshold 

standards for community annoyance. A widely voiced concern was that oil shale and tar sands 

development would degrade the visual landscape and topography of beautiful country. 

 In addition to the air quality effects on visibility, many commentors stated opposition to 

adverse impacts on the beauty and integrity of the visual landscape from oil shale and tar sands 

development processes. Commentors specifically noted that oil shale and tar sands development 

should not allow surface disturbance on areas eligible for Wild and Scenic designation or lands 

in Visual Resource Management Class I, II, or III. 
Final OSTS PEIS J-10 

Ecology and Wildlife. Many comments stated that oil shale and tar sands development 

will have significant impacts on wildlife and wildlife habitat and emphasized the need to protect 

not only threatened and endangered species, but special status species and priority habitat areas 

as well. Coordination with USFWS agencies and related foundations on all wildlife matters and 

conservation measures was recommended. Commentors also requested that the PEIS not defer 

biological diversity preservation to the project level. 

 In addition to identification of species, requests were made for baseline data on 

populations, ecological research plans to evaluate the impacts of development on those 

populations, and measures to avoid, protect, and/or mitigate their habitat areas. It was noted that 

seasonal restrictions for wildlife are ineffective mitigation measures because surface disturbance 

is anticipated to be 100%. One commentor specifically suggested pursuing underground mining, 

as opposed to open-pit, which would have less effect on surface habitats. Commentors also 

requested evaluation of the potential effect of oil shale and tar sands development on riparian 

areas, endemic wildflowers, and meadow grasses. 

 Commentors supported the inclusion of updated information and consideration for 

removal of additional areas, such as lands containing sage-grouse (Centrocercus urophasianus) 

habitats and/or wilderness characteristics, within potential oil shale and tar sands development 

areas. However, because of the size of potential development areas, commentors expressed 

additional concerns related to ecology and wildlife, summarized as follows. 

 Commentors asserted that fragmentation, destruction, and removal of sagebrush habitats 

would negatively impact sagebrush dependent and sensitive species within these areas, including 

sage-grouse, sage thrasher (Oreoscoptes montanus), sage sparrow (Amphispiza belli), and 

brewer’s sparrow (Spizella breweri). Consideration of sage-grouse habitat was specifically 

emphasized by many commentors because seasonal habitats exist throughout the area identified 

for potential leasing. Noted was the opinion that any type of development would have the 

potential to impact sage-grouse habitat by further fragmenting the remaining population, leaving 

it vulnerable to extinction and increasing its potential for listing and federal protection under the 

ESA. As a result, it was requested that the PEIS thoroughly analyze habitat loss, destruction, and 

fragmentation; evaluate the consequences of development; adequately disclose all impacts of 

industrial activities, and identify measures to minimize potential effects. In addition, commentors 

recommended that the PEIS and RMP amendments include a no surface occupancy (NSO) and 

no surface disturbance/vegetation treatment buffer, suggesting a 3-mi minimum (preferably 5 mi) 

for sage-grouse leks, nesting habitats that surrounds the leks, winter habitat, and other vital sagegrouse habitats. In addition, it was suggested that human activity during the production phase be 

limited near leks during breeding season. Conversely, some other commentors believed that the 

new information related to sage-grouse should not change the status quo. 

 Commentors reported that the proposed development area contains all or a significant 

portion of the distribution of six mammalian Species of Greatest Conservation Need (SGCN) in 

Wyoming: canyon mouse (Peromyscus crinitus), cliff chipmunk (Tamias dorsalis), Great Basin 

pocket mouse (Perognathus parvus), piñon mouse (Peromyscus truei), pygmy rabbit 

(Brachylagus idahoensis; petitioned for listing under the ESA in 2003), and Wyoming pocket 

gopher (Thomomys clusius; petitioned for listing under the ESA in 2007) (USFWS 2006). An 
Final OSTS PEIS J-11 

additional 14 SGCN were also noted to have distributions overlapped by the project area, 

including Uinta chipmunk (Eutamius umbrinus), Idaho pocket gopher (Thomomys idahoensis), 

olive-backed (or Wyoming) pocket mouse (Perognathus fasciatus), pallid bat (Antrozous 

pallidus), spotted bat (Euderma maculatum), water vole (Arvicola amphibious), little brown 

myotis (Myotis lucifugus), long-eared myotis (Myotis evotis), western small-footed myotis 

(Myotis ciliolabrum), long-legged myotis (Myotis volans), northern flying squirrel (Glaucomys 

sabrinus), northern river otter (Lontra canadensis), vagrant shrew (Sorex vagrans), and Preble’s 

shrew (Sorex Preblei). The majority of these species are limited by available habitat and 

dispersal ability; therefore, commentors recommended that the BLM work cooperatively with the 

Wyoming Game and Fish Department to delineate and maintain important habitats within the 

proposed project area. Other mammalian species identified as sensitive are the dwarf shrew 

(Sorex nanus), ringtail cat (Bassariscus astutus), big free-tailed bat (Nyctinomops macrotis), 

Townsend’s big-eared bat (Corynorhinus townsendii), white-tailed prairie dog (Cynomys 

leucurus), and black-footed ferret (Mustela nigripes). Various reptile and amphibian species 

were also noted by commentors as being within the study area, including the Utah milk snake 

(Lampropeltis triangulum taylori) and Great Basin gopher snake (Pituophis catenifer 

deserticola). 

 Commentors requested evaluation of the direct, indirect, and cumulative effects on 

migratory birds, raptors, their habitats, and nesting sites, specifically noting the Migratory Bird 

Treaty Act and the Bald and Golden Eagle Protection Act. Migratory and other bird species 

specifically identified were the ferruginous hawk (Buteo regalis), peregrine falcon (Falco

peregrines), golden eagle (Aguila chrysaetos), bald eagle (Haliaeetus leucocephalus), burrowing 

owl (Athene cunicularia), short-eared owl (Asio flammeus), Mexican spotted owl (Strix 

occidentalis lucida), willow flycatcher (Empidonax traillii), northern goshawk (Accipiter 

gentilis), Williamson’s sapsucker (Sphyrapicus thyroideus), Lewis’ woodpecker (Melanerpes 

lewis), grasshopper sparrow (Ammodramus savannarum), bobolink (Dolichonyx oryzivorus), 

long-billed curlew (Numenius americanus), and yellow-billed cuckoo (Coccyzus americanus). It 

was suggested that the BLM refer to the large datasets on nesting available from each BLM field 

office within the area under consideration. Commentors also stated that current BLM nest buffers 

for oil and gas, which are 0.25 mi for NSO and 2 mi for seasonal stipulations, are inadequate, 

and they recommended 3-mi buffers. 

 Commentors highlighted the fragmentation of crucial habitat for large mammal and big 

game species that is occurring as a result of current energy development (i.e., oil, gas, and wind). 

Species specifically identified by commentors included black bear (Ursus americanus), cougar 

(Puma concolor), bobcat (Lynx rufus), bighorn sheep (Ovis Canadensis), mule deer (Odocoileus 

hemionus), pronghorn (Antilocapra Americana), and elk (Cervus Canadensis). Commentors 

asserted that BLM should include these wildlife populations, habitat (regular and seasonal), and 

migration routes as part of the impact analysis on the areas identified for potential leasing and 

future surface-disturbing activities. Commentors also requested that BLM exclude big game 

areas, ranges, and corridors from oil shale and tar sands development or, at the very least, allow 

NSO in these areas. For Wyoming, specific range areas mentioned include Powder Mountain, 

Powder Rim, Cherokee Basin, Cherokee Rim, Haystacks, and surrounding areas. 
Final OSTS PEIS J-12 

 Commentors also expressed concern about the potential impacts of oil shale and tar sands 

development on wild horses and natural viewing opportunities for them. 

 Commentors noted that Colorado State Wildlife Areas (SWAs) provide important habitat 

for wildlife as well as recreational opportunities and an economic draw for local communities. 

SWAs are managed by the Colorado Division of Wildlife and serve to provide wildlife-related 

recreational opportunities. Six areas were identified as bordering BLM lands or overlapping with 

BLM-managed subsurface resources opened for oil shale and tar sands development according to 

the 2008 PEIS and ROD: the Shell Oil SWA hunting lease, the Yellow Creek Unit, the Square S 

Summer Range Unit, the Square S Ranch Unit, the Little Hills Unit, and the North Ridge Unit of 

the Piceance SWA. 

Fish and Fisheries. Noting that the Colorado River system and its tributaries provide a 

home for the many endangered, threatened, and sensitive fish species, as well as other native 

nongame and game fish, commentors voiced concerns over the impacts of oil shale and tar sands 

development on fish populations and fisheries. Concerns over habitat disturbance, sedimentation, 

water pollution, water supply reductions, and downstream condition were expressed. Further 

concern was expressed over the impacts of alterations in river water quality on native fish 

species, with particular concern related to the Endangered Fish Recovery Implementation 

Program, for which major efforts and expenses have already been incurred in the Colorado River 

Basin. It was recommended that the PEIS specifically include distribution and habitat data for 

endangered, threatened, and sensitive species, including Colorado pikeminnow (Ptychocheilus 

lucius), Colorado River cutthroat trout (Oncorhynchus clarkii pleuriticus), flannelmouth sucker 

(Catostomus latipinnis), bluehead sucker (Catostomus discobolus), razorback sucker (Xyrauchen 

texanus), mountain sucker (Catostomus platyrhynchus), and roundtail chub (Gila robusta). It was 

further recommended that measures be taken to identify monitoring plans that could be used to 

develop mitigation techniques necessary to lessen impacts on water quality and related impacts 

on aquatic species. 

 Specifically, multiple commentors stated that there is a need to protect the last remaining 

Colorado River cutthroat trout, which have habitats and native population strongholds located 

with the Upper Colorado River system, particularly the Green River basin where proposed oil 

shale lease areas are located. In 2009, the USFWS reviewed this species listing under the ESA 

and determined that listing was not warranted at that time. However, the Colorado River 

cutthroat trout is categorized by the Wyoming Game and Fish Department as a Native Species 

Status 2 (NSS2) species, which means the species are physically isolated and/or exist at 

extremely low densities throughout their range, while habitat conditions appear to be stable. 

Thus, commentors noted that habitat degradation and loss of populations within their distribution 

range could result in new petitions to list Colorado River cutthroat trout or in petitions to list 

other species of concern. A further review and impact analysis of the Colorado River cutthroat 

trout was recommended to be included in the new PEIS. In addition, stronger mitigation or 

conservation measures were recommended to meet the management objectives of the 

Conservation Agreement for Colorado River Cutthroat Trout (2010), including all three states in 

the study area. The commentors specifically requested a more substantial analysis than was 

completed in the 2008 PEIS and ROD and the identification of appropriate mitigation measures.
Final OSTS PEIS J-13 

 Commentors noted that both the flannelmouth and bluehead sucker are categorized by the 

Wyoming Game and Fish Department as NSS1 species, which are physically isolated and/or 

exist at extremely low densities throughout their range, while habitat conditions are declining or 

vulnerable. Therefore, it was recommended by commentors that no loss of habitat function occur 

as a result of the BLM’s actions. However, it was noted that some modification of the habitat 

could occur, provided that habitat function is maintained (i.e., the location, essential features, and 

species supported are unchanged). 

 Commentors reported that the Upper Colorado River system supports important sport 

fisheries based on wild populations of rainbow trout (Oncorhynchus mykiss), brown trout (Salmo 

trutta), and brook trout (Salvelinus fontinalis) and on introduced populations of cutthroat trout 

(Oncorhynchus clarkia). The commentors noted that the maintenance and enhancement of 

instream habitat is important to the long-term sustainability of fisheries and that the condition of 

instream habitat is directly related to the overall condition and health of the surrounding 

watershed. It was further recommended that the analysis of impacts and development of 

mitigation measures specifically address recreational and economic issues related to local fishing 

activities, native fisheries, and/or related businesses. 

Soil and Vegetation Impacts. Commentors expressed concern that land disturbance and 

mining will create a landscape that does not ecologically function as equivalent to the premining 

conditions. They also asserted that mining increases erosion and creates a temporal loss of 

ecosystem functions that is not mitigated even by successful reclamation and revegetation. Some 

commentors noted that portions of the proposed mining areas have unique soil properties 

(cryptobiotic crust) that should be preserved. Other commentors were concerned about 

desertification. 

 Special status, sensitive, and/or rare plant species and habitats noted by commentors 

include federally threatened Uinta Basin hookless cactus (Sclerocactus wetlandicus), Graham’s 

beardtongue (ESA candidate; Penstemon grahamii), Garrett’ s beardtongue (Penstemon 

scariosus garrettii), Barneby’s columbine (Aquilegia barneybi), Caespitose catseye (Oreocarya 

caespitosa), Mancos columbine (Aquilegia micrantha var. mancosana), Eastwood’s 

monkeyflower (Mimulus eastwoodiae), Colorado blue spruce (Picea pungens), red osier 

dogwood (Cornus sericea), boxelder (Acer negundo), narrowleaf cottonwood (Populus 

angustifolia), narrowleaf evening primrose (Oenothera fruticosa), Indian ricegrass (Achnatherum 

hymenoides), hanging garden sullivantia (Sullivantia hapemanii var. purpusii), southwest 

stickleaf (Mentzelia argillosa), Dudley Bluffs bladderpod (Lesquerella congesta), Dudley Bluffs 

(or Piceance) twinpod (Physaria obcordata), Ute-lady’s tresses orchid (Spiranthes diluvialis), 

White River beardtongue (Penstemon scariosus var. albifluvis), and narrow-stem gilia (Gilia 

stenothyrsa). 

 For many of these plant species, requests were made to have a buffer ranging anywhere 

from 300 ft to 0.5 mi around all known occurrences. Concerns were also noted that strip mining 

and/or some in situ methods (if used) and the associated infrastructure (e.g., road development) 

would require that vegetation be stripped from much of the land, resulting in destruction of 

habitats and long recovery periods. 
Final OSTS PEIS J-14 

Wilderness Areas, Other Specially Designated Areas, and Lands with Wilderness 

Characteristics. Commentors stated that BLM must perform an updated inventory of lands for 

wilderness characteristics, as well as preserve and protect areas with wilderness characteristics in 

management decisions. Commentors also proposed that some areas be excluded from 

development, including designated and proposed WAs, Wilderness Study Areas (WSAs), 

citizen-identified inventories, and Areas of Critical Environmental Concern (ACECs) that were 

nominated or considered for potential designation in a RMP. 

 Other areas specifically identified within Colorado include the Bitter Creek proposed 

wilderness unit (straddles the Colorado–Utah state lines in the Eastern Book Cliffs) and South 

Shale Ridge Citizen Proposed Wilderness (CPW), in addition to core and linkage areas within 

Heart of the West Wildland Network Design (also covering areas within Utah and Wyoming). 

 In Utah, areas identified include Fiddler Butte WSA, Glen Canyon Recreation Area, Rat 

Hole Canyon, Book Cliffs (includes Turtle, Desbrough, and Desolation Canyon, along with 

extensive wetlands), Dirty Devil CPW, Sids Mountain CPW area (encompasses a large portion 

of the San Rafael Swell), White Canyon proposed wilderness complex (including White Canyon, 

Fort Knocker Canyon, and Tuwa Canyon), Bitter Creek proposed wilderness unit, Lower Bitter 

Creek proposed wilderness unit, Dragon Canyon proposed wilderness unit (includes Davis, Side, 

Atchee, and Dragon Canyons in Utah, and Little Whiskey Creek in Colorado), Sunday School 

Canyon proposed wilderness unit (adjacent to Winter Ridge WSA and bounded by Wood 

Canyon, Buck Canyon, Willow Creek drainage, and Seep Ridge), and Seep Canyon proposed 

wilderness unit (includes Park Canyon, Park Ridge, and Crooked Canyon). 

 In 2008, the State of Wyoming designated the Adobe Town area as Very Rare or 

Uncommon under the state’s environmental quality act; part of it is an SWA. It was 

recommended that this entire area be protected from oil shale and tar sands development to 

preserve its ecological, environmental, geological, cultural, historical, archaeological, scenic, and 

recreational value. Other Wyoming areas proposed by commentors for wilderness protection 

include Kinney Rim (North and South), Red Creek Badlands, Devils Playground, Buffalo Hump, 

and Sand Dunes. In addition, commentors requested that citizens’ proposed additions to existing 

WSAs also be excluded from oil shale and tar sands development. 

Cultural Resources. The Dirty Devil and Fiddler Butte CPWs in Utah were identified to 

contain an abundance of archeological resources, including rock shelters, campsites, lithic 

scatters, stone tool quarries, and petroglyph sites. Commentors noted that studies by the NPS and 

BLM in this area have suggested that this region contains an average density of 24 archeological 

sites per square mile. The Glen Canyon and San Juan River area was also stated to contain 

significant cultural resources, including more than 26,000 documented archaeological sites, the 

majority on BLM-administered lands, thus making the region among the most significant 

concentrations of archaeological sites in the western United States. It was further noted that the 

Bitter Creek WSA has a number of pictograph and petroglyph sites, as well as graves, historic 

homesteads, an old growth forest, and inspiring scenery. Main Canyon in Utah contains sites of 

the historical Northern Ute migration route. 
Final OSTS PEIS J-15 

 Commentors noted that significant cultural resources are found within the Colorado 

portion of Dragon Canyon, including 43 sites registered with the Colorado Office of 

Archaeology and Historic Preservation. A Wickiup Village, which is listed on the National 

Register of Historic Places, was also identified in and around the Duck Creek ACEC. 

Commentors added that the BLM White River Field Office in Colorado has identified cultural 

resources through its cultural resource interpretation program, which should also be included and 

preserved. In addition, it was recommended that an archeologist be used to help assess the 

impacts on historical archeological sites. 

Recreation. Commentors expressed concern over the impacts on recreational users of 

national parks and other public lands, specifically noting hikers, rafters, hunters, sport fishers, 

skiers, and photographers. A few commentors also voiced concerns related to impacts on tourism 

within the study area. One commentor stated the opinion that most people do not have time to 

explore all the lands set aside for recreation, so more lands should be opened up for other 

purposes (such as productivity, industry, trade, and the ability to live off the land). 

Special Areas of Concern. Commentors identified many areas of special concern or 

interest to them, in addition to the aforementioned WAs and areas with cultural and 

archaeological significance. Commentors expressed concern over the protection of these areas 

and suggested their exclusion from leasing areas. Some of these additional areas included 

existing and potential ACECs, Research Natural Areas (RNAs), Outstanding Natural Areas 

(ONAs), recreation areas, NPS lands, USFWS-administered lands (e.g., National Wildlife 

Refuge System lands), National Monuments, National Conservation Areas, Wild and Scenic 

River segments, National Historic and Scenic Trails (e.g., the Pony Express, Oregon/California 

Mormon Trail, Overland Stage Trail, and Cherokee Trail), areas with high recreational value, 

and other areas that are part of the National Landscape Conservation System (NLCS). In general, 

commentors requested that these areas be excluded from oil shale and tar sands development. 

Commentors also requested maps illustrating special areas of concern with respect to exposed oil 

shale and tar sands formations and indicating how these areas may be altered as a result of 

projected surface mining activities. 

 Specific rivers, gulches, creeks, and watersheds identified by commentors that may or 

may not have special designations included the Colorado River, Green River, New Fork River, 

Henrys Fork River, Blacks Fork River, Hams Fork River, San Juan River, White River, Big 

Sandy River, Corral Gulch, Ryan Gulch, Piceance Creek and Basin, Range Creek, Horse Creek, 

Cottonwood Creek, Muddy Creek, Bitter Creek, Whiskey Creek, Little Whiskey Creek, Clear 

Creek, Spring Creek, Black Sulphur Creek, Fawn Creek, Hunter Creek, West Fork Parachute 

Creek, Parachute Creek, Dry Fork Piceance Creek, Tent Creek, Davis Creek West Evacuation 

Creek, and Willow Creek along with their tributaries, watersheds, and side drainages. 

 Colorado special areas of concern designated as ACECs for their visual, wildlife, 

botanical, fisheries, and ecological values include the East Fork Parachute Creek ACEC, 

Trapper/Northwater Creek ACEC, Duck Creek ACEC, Ryan Gulch ACEC, and Dudley Bluffs 

ACEC. Also identified were potential Colorado ACECs that encompass the Snake John 
Final OSTS PEIS J-16 

Subcomplex of the Coyote Basin Complex (important habitat for the sensitive white-tailed 

prairie dogs and endangered black-footed ferret), Dudley Bluffs bladderpod and twinpod habitat 

outside of existing ACECs, Graham’s Penstemon habitat outside the Raven Ridge ACEC, 

Narrow-stem gilia habitat outside the existing Lower Greasewood ACEC, Narrowleaf evening 

primrose habitat outside existing ACECs, and White-tailed prairie dog complexes outside of the 

Snake John Subcomplex of the Coyote Basin Complex. 

 Special areas of concern for Utah identified by commentors as having scenic value 

wildlife, crucial habitats, special status species, watersheds, cultural resources, historical 

features, and paleontological resources include the Colorado River Basin (including by extension 

Lake Mead and Lake Powell), Big Pack Mountain, Sids Mountain, Uinta Basin and Mountains, 

Book Cliffs, Bates Knolls, Tavaputs Plateau, McCook Ridge, Winter Ridge, Seep Ridge, Greater 

Canyonlands, Seep Canyon, Sweet Water Canyon, Desolation Canyon, Sunnyside Special Tar 

Sand Areas (STSAs), White Canyon, Happy Canyon, Wood Canyon, Buck Canyon, Fort 

Knocker Canyon, Tuwa Canyon, Rat Hole Canyon, Turtle Canyon, Desbrough Canyon, Davis 

Canyon, Side Canyon, Atchee Canyon, Dragon Canyon, Sunday School Canyon, Park Canyon, 

Park Ridge, Crooked Canyon, Red Rocks, Natural Bridges National Monument, areas adjacent to 

Capitol Reef, and parts of the Heart of the West Wildland Network. Also noted were potential 

Utah ACECs that encompass Bitter Creek and Bitter Creek-P.R. Springs, Nine Mile Canyon, 

Main Canyon, Devil Canyon-North Wash, White River Canyon, Coyote Basin Complex 

(includes Kennedy Wash, Myton Bench, and Snake John), Four Mile Wash, Sids Mountain, and 

Tar Sands Triangle. Also specifically noted for Utah were lands included for wilderness 

designation in the proposed America’s Red Rock Wilderness Act (originally introduced in 1989, 

not enacted). 

 In Wyoming, the following ACECs were noted: Cedar Canyon ACEC, Greater Red 

Creek ACEC (originally Red Creek ACEC, expanded to include relevant and important values in 

the Currant Creek and Sage Creek Drainages), Greater Sand Dunes ACEC, Natural Corrals 

ACEC, Oregon Buttes ACEC, Pine Springs ACEC, White Mountain Petroglyphs ACEC, South 

Pass ACEC, Special Status (Candidate) Plants ACEC, and Steamboat Mountain ACEC. The 

potential ACECs include sage-grouse potential ACECs in the South Pass and Salt Wells areas as 

identified in the Sage-Grouse Plan Amendment process, Monument Valley Management Area as 

identified in the Green River RMP, and Powder Rim migration corridor for the Grand Teton 

pronghorn herd (extending southward from Trapper’s Point to Seedskadee National Wildlife 

Refuge [NWR]). In addition, Sugarloaf Basin Special Management Area (SMA), Jack Morrow 

Hills Planning Area, and the Seedskadee NWR itself were recommended for protection and 

exclusion from oil shale and tar sands leasing. 

 Also in Wyoming, the Little Mountain ecosystem in the Green River Basin and the 

Vermillion Creek drainage in the Washakie Basin were identified as critical habitat to a host of 

big game, game bird, sport fish, and nongame species. The headwaters of Bitter Creek (in the 

Washakie Basin), Henrys Fork River (from the Wyoming–Utah state line to Flaming Gorge 

Reservoir), Big and Little Sandy drainages (from their confluence near Farson to the head of the 

Green River Basin), along with parts of the Blacks Fork (from Flaming Gorge Reservoir 

upstream to Interstate 80), and Hams Fork (from its confluence upstream to Kemmerer) Rivers 

were identified to support viable populations of Colorado River cutthroat trout (NSS2), 
Final OSTS PEIS J-17 

flannelmouth suckers (NSS1), bluehead suckers (NSS1) and/or roundtail chub (NSS1), and 

important trout fisheries. In addition, the Fontenelle Reservoir, Flaming Gorge Reservoir, and 

Green River corridor between the two reservoirs were specifically identified as waters supporting 

economically important sport fisheries, in addition to providing domestic water to the 

communities of Green River, Rock Springs, and the surrounding communities. The Red Desert, 

Horseshoe Bend, The Haystacks, Willow Creek Rim, and Skull Creek Rim in Wyoming were 

also identified by commentors. 

 The proposed project area was also reported to overlap a number of mammalian SGCN 

(listed under the Ecology and Wildlife section above) habitats, including the piñon-juniper 

woodlands (of the Colorado Plateau), sagebrush steppe, gardner’s saltbush, and barren areas 

within the Washakie Basin. It was recommended that the PEIS take into account and avoid 

disturbance of these ecosystems and sensitive habitats. 

 The issue of buffer zones, which includes additional areas surrounding areas of concern 

(e.g., water resources, sensitive habitats, and National Historic and Scenic Trails) where 

development would be excluded, was brought up by several commentors. It was noted that 

current buffer zones (typically 0.25 mi) were inadequate to protect and prevent degradation of 

these resources. 

Environmental Justice. Commentors requested that the PEIS thoroughly analyze 

environmental justice impacts, given that there are numerous small communities within the 

planning area. 

Climate Change. Commentors stated that climate change discussion and analysis must 

be considered more thoroughly in the new PEIS. This section should include a description and 

summary of ongoing and projected climate change impacts (regional and local) relevant to the 

action, potential impacts that could be exacerbated by climate change (e.g., water resources, air 

quality), and reasonable mitigation measures, protocols, or policies to guide oil shale and tar 

sands leasing and development considerations. Also noted were recent advancements made since 

2008 in both the study and science of climate change, which have specifically made analysis of 

localized impacts more viable. In addition, it was remarked that the PEIS review and incorporate 

relevant federal (e.g., Council on Environmental Quality [CEQ] guidance), regional, state, and 

tribal climate change plans or goals to help the BLM reconcile its proposed action for oil shale 

and tar sands leasing and development with such plans. 

 Climate change issues and topics specifically cited in the scoping comments are increased 

greenhouse gas (GHG) emissions (i.e., CO2), rise of summer temperatures, warmer water, 

changes in streamflows, alterations in water levels, reduction in water availability, and increasing 

frequency and intensity of disturbances such as floods and wildfires. These were all identified by 

commentors as likely having deleterious ecological effects resulting in the degradation of 

existing habitats as well as the potential for adverse economic ramifications. By contrast, other 

commentors stated that CO2 emissions should not be a significant consideration within the scope 

of the PEIS and that climate change is mitigated through the absorption of CO2 by green plants.
Final OSTS PEIS J-18 

 A qualitative discussion of the link among GHGs, climate change, and potential impacts 

of climate change was requested. One commentor specifically suggested that the PEIS describe 

the potential range of GHG emissions that may be associated with life-cycle commercial oil 

shale and tar sands development under each alternative. The commentor asserted that this 

analysis would help illustrate how GHG emissions scenarios may vary according to the amount 

of public lands the BLM ultimately decides to make available to potential commercial-scale 

leasing and development. It was asserted that the development of oil shale emits more GHGs 

than do conventional liquid fuels from crude oil. 

 Commentors suggested that the BLM reference climate-change–related studies on supply 

and demand aspects of Colorado River management such as those of the USGS National Climate 

Change and Wildlife Science Center, the Regional Climate Science Centers, Western Water 

Assessment, and the Bureau of Reclamation (BOR). 

J.3.1.2 Issues outside the Scope of the PEIS, but Which May Present Related Policy 

 Considerations 

Air Quality, Noise, and Visual Impacts. One commentor requested that leasing not 

proceed until more is specifically known about the amount of energy and resulting pollution 

output required to extract oil shale and tar sands; thus, these issues can be taken into 

consideration in the impact analysis. 

Cultural Resources. It was commented that all potential oil shale and tar sands 

development areas, especially those where the entire surface area may be affected, need to 

receive the highest priority to ensure adequate tribal review, physical archaeological surveys, 

and paleontological baseline assessments prior to any leasing or development in these areas. 

It was recommended that the PEIS identify areas with cultural, historic, archaeological, or 

paleontological properties and/or resources which are at risk, employ one or more administrative 

measures to protect the resources, and ultimately consider closing these areas to oil shale and tar 

sands leasing and development. 

While some of the types of areas noted in this comment are excluded from possible 

leasing or development under one or more alternatives analyzed, the PEIS does not address the 

full breadth of this comment. 

Human Health. Commentors voiced the opinion that development of oil shale and tar 

sands resources should not be permitted until data are available on health consequences. It was 

mentioned by commentors that deleterious effects and public health consequences have been 

occurring in the areas in which oil shale and tar sands techniques are used. Commentors 

associated these effects with increased levels of highly toxic chemicals and heavy metals, 

deteriorating air quality, and changes in climate. Examples given include longer allergy/asthma 

seasons and increased injuries from snowstorms. One commentor also mentioned solastalgia, 
Final OSTS PEIS J-19 

which is the emotional distress caused by environmental change. Another commentor questioned 

if the oil shale and tar sands development companies would put up a bond to cover health 

impacts. 

J.3.1.3 Issues outside the Scope of the PEIS 

Beyond what is provided in the draft PEIS, the kind of specific information requested in 

the issues within this section on environmental concerns is not necessary to make an allocation 

decision of the kind contemplated here. 

NEPA Analysis. Several commentors requested that the PEIS analyses perform a 

baseline study of the various resource areas (e.g., water, air, ecology and wildlife, cultural 

resources) to document a starting point for measuring impacts and their significance. 

Given that the three “most geologically prospective” areas in Colorado, Utah, and 

Wyoming encompass approximately 3,538,000 acres, it would not be practicable nor affordable 

for the BLM to conduct baseline surveys for these various resources. More importantly, it would 

be premature to try to establish a baseline so far in advance of any commercial development; the 

appropriate time to establish a baseline is just before an area is to be leased. 

 It was requested by some commentors that the BLM not defer the analysis of 

environmental consequences and impacts of commercial oil shale and tar sands development to 

site-specific NEPA evaluations; while acknowledging that there are many unknowns with oil 

shale and tar sands technology and development, commentors request that the BLM not defer 

analysis of consequences to later NEPA documents. In addition, it was mentioned that sitespecific NEPA review will likely not provide an adequate region-wide analysis of the 

relationships and impacts to resources (e.g., water use) across the three state region. On the other 

hand, different commentors believe that it is not up to the BLM to determine what technologies 

are appropriate or will succeed, but to simply ensure that the resource is available on a fair basis. 

Given the high degree of uncertainty of the nature of future development of oil shale or 

tar sands resources on public lands, the nascent character of the industry in the United States in 

general, and the nature of the proposed action as a land allocation action, the level of impacts 

analysis in the 2008 PEIS was appropriate for the decisions being addressed, and a similar 

approach will be used in the current PEIS. In this context, it bears noting that appropriate and 

applicable environmental laws will be addressed, regulations complied with, and environmental 

evaluations assessed at the project level when specific development plans are submitted and 

before a project can proceed. 

Similarly, with respect to a region-wide analysis, in the sense of cumulative impacts, the 

CEQ regulations at 40 CFR 1508.7 define a cumulative impact as follows: “Cumulative impact 

is the impact on the environment which results from the incremental impact of the action when 

added to other past, present and reasonably foreseeable future actions regardless of what 

agencies (federal or non-federal) or person undertakes such other actions.” Clearly defining the 

scope and scale of potential environmental consequences of a proposed action, along with 
Final OSTS PEIS J-20 

identifying other reasonably foreseeable future actions, are the keys to effective cumulative 

effects analysis. Determining the appropriate scope and scale of analysis depends on a welldefined proposed action and on the identification of resources that could be affected by the 

action and issues about the proposed action identified in the scoping process. Until the BLM has 

information about the location and the type of technology that will be used, it cannot conduct an 

effective cumulative effects analysis of the relationships and impacts on resources as suggested 

in the comment. The BLM will consider the full range of consequences of actions in the 

appropriate NEPA document when the information to do so is available. 

Water Quantity and Quality. Commentors requested that the PEIS provide a thorough 

characterization of existing groundwater and surface water resources within the project area, 

including all waters that may be impacted by oil shale and tar sands development, the nature of 

potential impacts, and specific pollutants likely to impact those waters. Commentors further 

recommended that the PEIS identify within each alternative all source water protection areas and 

any water bodies that appear on a state impaired waters list (i.e., 303(d)), along with the 

constituents for which those water bodies are listed. In addition, it was requested that hydrologic 

monitoring be performed prior to, during, and after operations. Consultation with federal, state, 

and local water authorities and experts was recommended. 

The future development of oil shale or tar sands resources is too uncertain to perform 

meaningful analyses of the types suggested by the commentors. The recommended analyses 

would be more appropriately and more effectively performed in subsequent NEPA analyses at 

the project lease and development levels. 

 Commentors expressed concerns related to the potential impacts of oil shale and tar sands 

development on regional water sources and the insufficiency of analysis, recommendations, and 

conclusions in the 2008 PEIS. It was specifically emphasized that the new PEIS identify and 

evaluate the sources of water to be used and both the direct and indirect impacts of use, as well 

as cumulative effects. Commentors highlighted the importance of understanding the water 

implications, specifically as they relate to Colorado River entitlements, of the oil shale and tar 

sands industry prior to decisions regarding leasing or commercialization. Commentors also stated 

that alternative options for water supply should be explicitly addressed and the RMPs be 

modified to ensure access to water. One commentor suggested the importation of water by train 

tanker cars. 

The future development of oil shale or tar sands resources is too uncertain to perform 

meaningful analyses of the types suggested by the commentors. 

 Commentors recommend that the PEIS identify all currently available information 

regarding ongoing water demands and expected projections, including amounts required, 

location of draws, and source identification (agricultural, domestic, and public water supply 

wells or intakes), to consider whether there is sufficient surface and groundwater to support oil 

shale and tar sands development in the region without detrimentally affecting existing 

development and water use. 
Final OSTS PEIS J-21 

The future development of oil shale or tar sands resources is too uncertain to perform 

meaningful analyses of the types suggested by the commentors. It would not be practicable or 

affordable for the BLM to perform the detailed analyses suggested, while any such studies would 

be speculative given the current state of knowledge. 

Air Quality, Noise, and Visual Impacts. Commentors stated that analyses should 

include data and discussions on the sources, magnitudes, and emission factors associated with 

criteria and other pollutants of concern (including precursors) from conventional aspects of and 

preferred future processes for oil shale and tar sands development; that the data should also be of 

sufficient quality to be used in a full-scale quantitative assessment of direct, indirect, and 

cumulative impacts within both the study area and all surrounding affected areas; and that the 

analysis should include air dispersion modeling, regional and long-range transport evaluations, 

local effects, ozone analysis (including to Class I areas ),emission predictions, and airborne dust 

emissions estimates for each alternative to provide the level of information necessary to support 

any future leasing decisions and ensure that oil shale and tar sands development does not degrade 

air quality. Commentors further stated that, where possible, evaluations should be performed on 

the basis of real studies and data rather than modeling, and that projected pollutant levels should 

be compared with levels projected by using alternate oil production sources and using efficiency 

alternatives. This comparison would also entail estimating levels of development and changes in 

development depending on which land tracts are leased. One commentor recommended utilizing 

the Utah BLM Air Resource Management Strategy in the analysis. 

Given the nascent state of development of oil shale and tar sands technologies in the 

United States and the highly uncertain extent and specific locations of future development, the 

types of quantitative analyses suggested by the commentors would be speculative. The 

recommended analyses would be more appropriately and more effectively performed in 

subsequent NEPA analyses at the project lease and development levels. 

 It was requested that the PEIS address the air quality impacts of the estimated emissions 

for all criteria pollutants and compare them with the National Ambient Air Quality Standards 

(NAAQS) and Prevention of Significant Deterioration (PSD) incremental limitations. 

Commentors requested that air quality related values (AQRVs) be discussed and that sensitive 

receptor locations, including Class I air sheds, national parks, WAs, and other sensitive sites be 

identified. 

Given the nascent state of development of oil shale and tar sands technologies in the 

United States and the highly uncertain extent and specific locations of future development, the 

types of quantitative analyses suggested by the commentors would be speculative. 

Monitoring. Several commentors emphasized the importance of obtaining baseline 

conditions for meteorology, water, air, and soil quality, and wildlife populations (as noted above) 

in order to allow accurate measurement of impacts. In addition, concerns were expressed over 

monitoring and responsibility for impacts after the development sites have been closed and 
Final OSTS PEIS J-22 

abandoned. It was suggested that required monitoring for any oil shale and tar sands leasing 

program be at least as thorough as the Prototype Oil Shale Leasing Program. 

Given that the three “most geologically prospective” areas in Colorado, Utah, and 

Wyoming encompass approximately 3,538,000 acres, it would not be practicable nor affordable 

for the BLM to conduct baseline surveys for these various resources. More importantly, it would 

be premature to try to establish a baseline so far in advance of any commercial development; the 

appropriate time to establish a baseline is just before an area is to be leased. 

In any case, air quality monitoring is ongoing, and results of recent monitoring were 

used in the air quality analysis in Section 3.5.3, where it is noted that, under federal air quality 

regulations, each of the three states carries out an ongoing air quality monitoring program for 

criteria air pollutants. In addition, a number of the companies conducting the RD&D programs 

in Colorado and Utah have performed baseline surface water and groundwater quality studies, 

as noted in Appendix A. 

Human Health. Commentors requested that the PEIS include qualitative and quantitative 

discussions of the known health risks associated with the proposed action and populations at risk. 

In addition, commentors recommended that the PEIS incorporate a formal methodology to 

evaluate all health issues and potential mitigations, such as a Health Impact Assessment (HIA) or 

cost-benefit analysis, and that agencies with relevant health expertise in developing HIAs be 

consulted. Areas noted of specific concern to human health for analysis in detail include air 

pollution, water pollution, and climate change. 

The proposed action being a land allocation action does not, in and of itself, present 

human health risks. Health risks associated with any future related actions would be analyzed 

prior to their approval and with the specific knowledge of a given project’s dimensions. Any 

future actions would be subject to all prevailing environmental regulations protecting human 

health. 

J.3.2 Socioeconomics 

J.3.2.1 Issues within the Scope of the PEIS 

 Commentors asked that the PEIS take a hard look at the socioeconomic impacts from oil 

shale and tar sands development on communities in the area and consider utilizing community 

planning to mitigate socioeconomic impacts. Specifically, it was requested that the PEIS analyze 

impacts and develop mitigation measures addressing economic effects on local fishing activities, 

native fisheries, hunting, ranching and grazing, retirement communities, tourism, and related 

businesses. 

 The “boom and bust” cycle that the region has experienced over past decades as a result 

of oil shale and tar sands development was also referred to numerous times. Commentors noted 
Final OSTS PEIS J-23 

that these cycles, in addition to seasonal restrictions that concentrate development during seven 

months of the year, make it particularly difficult to attract and keep permanent workers. The 

adverse tradeoff between short-term jobs and long-term sustainable employment, along with 

increased profits for energy companies, was pointed out by commentors, noting that the 

temporary work force that has positive impacts on the local economy via the creation of jobs 

may also cause adverse local impacts in terms of inconsistent and unpredictable housing 

availability, motor vehicle traffic, demands on infrastructure, tax bases, and revenue flow. In 

addition, local governments would have to provide law enforcement, medical care, and other 

social services on a year-round basis, even when the peak needs fluctuate, which often results in 

shortages and straining of resources. Transportation issues noted by commentors related to the 

effects of transport of the oil shale and tar sands product on roads, including access roads and 

county roads, citing road wear and related required road maintenance, reconstruction, and 

upgrades. It was noted that investment in community services, facilities, and infrastructure would 

ideally be needed years in advance of commercial production. Commentors requested that the 

aforementioned regional and local economic impacts be weighed against economic benefits from 

industry over the long term in the PEIS. 

J.3.2.2 Issues outside the Scope of the PEIS, but Which May Present Related Policy 

Considerations 

 Concern was expressed over the transparency of the companies developing oil shale and 

tar sands, whether or not they pay taxes, and where that tax money goes. Further concern was 

expressed over taxpayers having to foot the bill for any cleanup that may result from oil shale 

and tar sands activities. Commentors also suggested that the companies who develop this 

resource be taxed or have bond requirements with the money set aside to either cover restoration 

costs, or be directed toward sustainable and renewable energy development, or granted in 

another way that would be beneficial to the taxpayers. Other commentors requested that federal 

funding be provided to impacted local communities to assist with infrastructure improvements 

and service expansions, or that federal incentives be established for companies to promote 

upfront and ongoing investment in and contributions to state agencies and local governments 

directly affected by oil shale development and production. 

 One commentor noted that about half of the royalties, by law, return to state and local 

governments and are intended to help mitigate the impacts of development and that reduced 

royalty rates would directly diminish their ability to deal with the impacts of that development. 

Another commentor asked the BLM to consider the ancillary benefits to the American public 

from a robust oil shale industry when considering a fair return to the taxpayer, noting that rates 

should be established in a way that would be beneficial to the taxpayers, yet not deter investment 

in oil shale and tar sands development. 
Final OSTS PEIS J-24 

J.3.2.3 Issues outside the Scope of the PEIS 

Beyond what is provided in the draft PEIS, the kind of specific information requested in 

the issues within this section on socioeconomic concerns is not necessary to make an allocation 

decision of the kind contemplated here. 

 Commentors recommended that the analysis include baseline data for community 

infrastructure and capacity to be used to assess what additional needs will be required to support 

oil shale and tar sands development; a thorough housing analysis incorporating local constraints, 

including buildable land; and an assessment of how capital costs will be covered. 

The current level of knowledge of future oil shale or tar sands development does not 

warrant the detailed analysis proposed, which, consequently, would be speculative. 

 It was further recommended that the broader economic impacts on the region be 

analyzed, should the BLM close areas to energy development. It was suggested that the BLM 

consider using a total economic value approach for this analysis that includes estimation of 

nonmarket values for the planning area and define an opportunity cost of keeping lands 

available. The concept of assessing the carrying-capacity thresholds of the regional and local 

economies was also mentioned by several commentors. 

The proposed scope and methods of economic analyses are alternative methods to those 

conventionally used in a NEPA analysis. The current conventional methods of analysis meet the 

needs of the PEIS, while remaining reasonably feasible to perform by using readily available 

public information. See Alternatives and Issues Considered but Eliminated from Detailed 

Analysis, Section 2.5.1, Carrying-Capacity Thresholds. 

J.3.3 Resource and Technology Concerns 

J.3.3.1 Issues within the Scope of the PEIS 

Resource Assessments. A number of commentors invoked the recent USGS oil shale 

resource assessment. It was noted that the assessment identifies the PEIS study area as the largest 

oil shale resource in the world and containing more oil resources than the total of all known 

proved conventional onshore and offshore reserves of the United States. 

Power and Energy. The amount of energy required to power the oil shale and tar sands 

development and extraction was a concern expressed by many commentors, as was the ratio of 

energy expended to actual oil produced. Commentors mentioned that power from the existing 

grid might not be adequate for oil shale and tar sands development; thus, the PEIS should 

examine how electricity needs will be met. In addition, commentors noted that the extraction of 

oil shale and tar sands resources may require substantial consumption of natural gas and water. 
Final OSTS PEIS J-25 

Technology. Several commentors suggested that the PEIS include a realistic assessment 

of the industry’s current technologies, quantifying their associated environmental impacts and 

the general ability to commercially develop oil shale and tar sands. It was noted that a perceived 

lack of detailed information regarding development technologies will make it difficult for BLM 

to adequately assess potential impacts. Additional concerns were expressed regarding which oil 

shale and tar sands technologies would be considered within the scope of the PEIS. 

J.3.3.2 Issues outside the Scope of the PEIS, but Which May Present Related Policy 

Considerations 

Power and Energy. One commentor suggested that the environmental costs of electricity 

generation should be factored into lease rates. Commentors also specifically requested that the 

PEIS include an analysis of options for meeting power demands for oil shale development in a 

manner consistent with Colorado’s renewable energy standard. 

Technology. One commentor suggested the PEIS address the need and readiness for a 

commercial program; another suggested that the BLM set an environmental basis for commercial 

processes that meets the final requirements. 

 Many commentors discussed BLM’s ongoing oil shale RD&D program and expressed 

concern that data from the projects would not be available in time for use in the PEIS. Many 

stated that development efforts should proceed slowly or not at all, with R&D facilities on small 

plots to demonstrate feasibility. In addition, commentors emphasized that these projects should 

be used to help assess not only the viability of technologies, but also to understand effects of oil 

shale and tar sands development (e.g., air quality or displacement of wildlife) and determine 

sources for required water and energy. 

 One commentor stated that research indicates the presence of possible valuable coproducts in the central Piceance basin, including lithium and rare earth metals that should be 

considered for recovery in the current RD&D program. The commentor proposed excluding 

further leasing in the area unless and until research on such co-product recovery was performed. 

 Other commentors stated that the BLM made an incorrect assumption in the NOI by 

stating “there are no economically viable ways yet known to extract and process oil shale for 

commercial purposes.” Commentors asserted that the viability of commercial technologies has 

been proven in Brazil, China, and Estonia. Shell Oil was identified as having invested in the 

technical and commercial development of the in-situ conversion process (ICP) for oil shale since 

the early 1980s as a means to economically develop oil shale in an environmentally responsible 

and socially sustainable manner. Other commentors noted that technologies currently exist that 

minimize water consumption (and even possibly eliminate or produce in situ water), reduce CO2 

emissions, require few workers, abate ground-disturbing footprints, and utilize natural gas 

produced in the production process. It was further emphasized that the issue that concerns the 

commercial viability of oil shale and tar sands resource development and the issue of whether 
Final OSTS PEIS J-26 

certain lands should be made available in the future are two separate issues, and thus the failure 

to make federal land available for leasing will only slow technological growth. 

 Commentors further suggested that the BLM could exclude processes which are not 

environmentally clean by limiting lease bids to those who can meet acceptable environmental 

standards, which would be defined as whether or not the process is worse than the exploration 

and production of crude oil. 

Economic Feasibility. Commentors requested that the BLM perform a cost-benefit 

analysis for oil shale and tar sands development and provide the ratio of energy in/out for each 

technology evaluated. In general, it was requested that leasing and the development of oil shale 

and tar sands resources not proceed unless it can be demonstrated that available commercial 

technologies are economically feasible. Commentors mentioned that the low resource recovery 

(about 10% to 40%) and small return on investment (ROI) from in situ technologies is not in the 

public interest. One commentor asserted that in order for oil shale to be economically feasible, a 

deposit would need to be 50 ft thick and provide 50 gal/ton, which is at least double what was 

considered in the 2008 PEIS for leasing requirements. Commentors stated that the BLM must 

further evaluate the potential development and viability of these resources, including a 

technological readiness assessment that looks at cost projections and comparisons to other 

energy sources. 

 On the other hand, other commentors expressed support for the 2008 RMP amendments 

and stated that coherent national policy and long-term regulatory stability are necessary to 

promote the research, development, and capital investment needed to explore environmentally 

responsible oil shale production options. Commentors also remarked that based on current 

practices and technology, oil shale has been proven around the globe to be economical, 

commercially viable, and environmentally acceptable. Commentors specifically mentioned the 

high input-to-output energy ratio. For example, one commentor asserted that an average grade of 

shale oil containing 25 gal/ton raw shale will have about 80% of the energy in the original 

resource found in products for sale. In addition, commentors noted that technologies exist that 

can extract certain impurities (e.g., pyridine) naturally found in oil shale and tar sands deposits, 

such that companies can sell it separately to make their projects more economically feasible. 

 Finally, some commentors requested that the BLM evaluate the impacts of oil shale and 

tar sands developments on oil and gas prices. 

J.3.3.3 Issues outside the Scope of the PEIS 

Beyond what is provided in the Draft PEIS, the kind of specific information requested in 

the issues within this section on resource and technology concerns is not necessary to make an 

allocation decision of the kind contemplated here. 
Final OSTS PEIS J-27 

Resource Assessments. Some commentors supported oil shale and tar sands 

development, stating that we need to take advantage of all available domestic energy resources, 

including unconventional ones, for our national security and strategic interests. Others noted that 

simply identifying a vast resource does not prove it to be productive, especially if it cannot be 

accessed or developed. In Wyoming, for example, one commentor mentioned that the land 

available for leasing is checkerboard; thus, a very small percentage is considered commercially 

attractive. 

The above comments are not relevant to the proposed action analyzed in the PEIS. 

 Several commentors requested that the resource assessment include a comparison of 

these resources with other oil shale and tar sands resources worldwide (e.g., Canada). 

This comment is not relevant to the proposed action analyzed in the PEIS. 

Power and Energy. Commentors further recommended that this analysis document 

existing power generation facilities and disclose any new facilities that would need to be 

constructed, including an analysis of the location of plants, stack parameters, plant fuel sources, 

along with an assessment of the air quality impacts of such plants. 

The analyses suggested by the commentors would be speculative given the current state 

of knowledge of future oil shale and tar sands development. 

Technology. Broad comments related to technology included statements that no 

methodologies have proved to be commercially viable and all options create environmental 

damage. One commentor specifically noted that even in situ technologies pose post-recovery 

problems (e.g., land subsidence and water contamination). Another mentioned that 

U.S. refineries are not equipped to handle the sulfur levels in the oil that result from the tar sands 

and the removal of sulfur requires a lot of hydrogen, typically derived from water and natural 

gas. Conversely, other commentors noted that underground mining options or directional drilling 

technologies can minimize, or even possibly eliminate, any measurable impact on wildlife. In 

addition, they noted that some emerging technologies do not use any solvents that would put 

groundwater at risk of contamination, are carbon neutral (produce oil from oil shale without 

CO2), and have rapid real-time reclamation that can mitigate as they go. Commentors also 

expressed concerns that technologies were too new and unproven to open up land for commercial 

leasing and development, or they objected to making assessments using information about 

technology that existed 40 to 70 years ago. Still others felt it should be left up to industry to 

decide what technology to use. 

 Commentors also voiced concern that a specialist in oil shale and tar sands technology or 

mining was not part of the BLM PEIS team. In addition, commentors requested that the PEIS 

show potential locations of facilities, wells, pipelines, extraction sites, and transport facilities. 
Final OSTS PEIS J-28 

The above comments are either not relevant to the proposed action, are speculative, or 

do not affect the scope of the analysis. 

J.3.4 Stakeholder Involvement 

J.3.4.1 Issues within the Scope of the PEIS 

 Issues identified in comments include recommendations for intergovernmental 

collaboration (at the local, county, state, and federal level), community and stakeholder input, 

and the formation of a federal government–industry alliance. Commentors also suggested 

consideration of political agendas, local area fiscal impacts, Native American concerns, 

consultation with subject matter experts (e.g., climate change, human health assessment), and 

interactions specifically with federal, state, and local departments and organizations 

(e.g., environmental, water). Many comments from state and local governmental agencies 

requested active involvement and inclusion in the PEIS process, as well as in discussing policy 

matters. Several individuals expressed general concerns that their input, comments, and opinions 

as stakeholders will not be considered or respected and that oil shale and tar sands development 

will eventually proceed despite their objections, thus diminishing the value of their efforts to 

participate in the process. 

 Some commentors asserted that the BLM has not done an adequate job of informing the 

public of the ramifications of extracting oil from these resources. Other commentors encouraged 

the BLM to disclose all efforts taken to ensure effective public participation and involvement. 

However, there was also concern that the NOI was deficient because notification by publication 

in public media with respect to the Salt Lake City, Utah, public meeting did not occur on a 

timely basis (before the 15-day period preceding the meeting). In addition, it was noted that the 

meetings in Price and Vernal, Utah, conflicted with other BLM meetings. 

J.3.4.2 Issues outside the Scope of the PEIS, but Which May Present Related Policy 

Considerations 

 None. 

J.3.4.3 Issues outside the Scope of the PEIS 

 None. 
Final OSTS PEIS J-29 

J.3.5 Cumulative Impacts 

J.3.5.1 Issues within the Scope of the PEIS 

 Commentors recommended that the PEIS cumulative impacts analysis account for the 

impacts from all past, present, and future energy development projects in the region. Such 

actions would include oil and gas, coal, shale gas, and renewable energy (e.g., solar, wind, and 

geothermal) development, as well as future transmission corridor development, refining projects, 

and any other mineral development that competes for surface use on public lands. It was 

specifically requested that a full and comprehensive analysis be included for water 

contamination, water quality, waste water disposal, aquatic life, fishery resources, and 

downstream environments. Other cumulative factors identified for consideration included water 

contamination issues, activities leading to soil and vegetation disturbance, disturbance of habitat 

structure, habitat fragmentation; air quality and pollution, contributions to global warming, 

population growth, growth in other sectors (e.g., recreation and tourism), and infrastructure 

factors (e.g., transmission lines, pipelines, roads, fire management, and secondary impacts from 

required power generation associated with large-scale oil shale and tar sands development). 

J.3.5.2 Issues outside the Scope of the PEIS, but Which May Present Related Policy 

Considerations 

 Commentors expressed concerns that the cumulative impact analysis in the previous 

PEIS was inconsistent with NEPA, which deferred detailed analysis to future analyses to be 

conducted on a lease-to-lease basis. In addition, it was noted that the assessment should not be 

performed based on a single, generic, oil shale facility in lieu of analyzing a reasonably 

foreseeable development scenario. 

J.3.5.3 Issues outside the Scope of the PEIS 

Beyond what is provided in the Draft PEIS, the kind of specific information requested in 

the issues within this section on cumulative impacts concerns is not necessary to make an 

allocation decision of the kind contemplated here. 

 Commentors recommended that the PEIS cumulative impacts analysis address a 

reasonably foreseeable development scenario (RFDS). It was further requested that these impacts 

be analyzed on multiple scales, including, for example, local, regional, and basin-wide scales. 

Given the nascent state of development of oil shale and tar sands technologies in the 

United States and the highly uncertain extent and specific locations of future development, an 

RFDS cannot be projected at this time, nor is it possible to meaningfully perform the suggested 

multiscale cumulative impacts analysis. 
Final OSTS PEIS J-30 

J.3.6 Mitigation and Reclamation 

J.3.6.1 Issues within the Scope of the PEIS 

 Commentors suggested that the PEIS link cumulative impacts with mitigation measures, 

adopt enforceable mitigation measures, and link mitigation measures with specific steps that 

should be taken in specific resource areas or over the larger landscape. Commentors further 

recommended that the PEIS specifically identify all relevant and reasonable mitigation measures 

to protect water sources, including technology selection to decrease potential contamination, 

water consumption, and groundwater flow effects; engineering practices to include water 

treatment and recycling, minimizing disturbed areas and hastening reclamation; and the 

preparation of erosion and sedimentation control plans. In addition, commentors recommended 

that mitigation address impacts on the demand for services and infrastructure in affected 

communities. One commentor believed that, as a programmatic document, the BLM should 

refrain from adopting any mitigation measures, allowing such measures to be addressed in the 

more site-specific NEPA analysis. Another commentor opposed mitigation measures that include 

private land purchases. 

 Some commentors noted that land has been and can be reclaimed after the resources are 

mined, while others stated that reclamation does not always work, has a poor track record, and 

sometimes cannot return systems to their original levels of ecological performance. It was further 

noted by one commentor that formations like the Uintah and Green River may not be able to be 

reclaimed because of unique geology and soil chemistry. 

J.3.6.2 Issues outside the Scope of the PEIS, but which May Present Related Policy 

Considerations 

 Commentors want the BLM to acknowledge and coordinate with the BOR and the 

U.S. Forest Service (USFS) on active and ongoing projects. In addition, they requested that the 

BLM try to minimize irreversible impacts. 

 The responsibility for long-term stewardship and responsibility for the areas impacted by 

oil shale and tar sands development was emphasized by some of these commentors. 

J.3.6.3 Issues outside the Scope of the PEIS 

Beyond what is provided in the Draft PEIS, the kind of specific information requested in 

the issues within this section on mitigation and reclamation concerns is not necessary to make an 

allocation decision of the kind contemplated here. 

 Commentors recommend that the PEIS describe reclamation options and processes for 

the various oil shale technologies (e.g., open pit, subsurface mining) and development phases 

(e.g., construction, decommissioning). Commentors believe it is important to define the metrics 
Final OSTS PEIS J-31 

used to measure success, such as “successful revegetation,” and to define reclamation by 

comparison to predevelopment conditions. Commentors voiced support for a reclamation plan 

that is based on actual soil types, precipitation, and altitude, while also taking into account use by 

wildlife, livestock, and wild horses. 

 The BLM believes that descriptions of reclamation options and their effectiveness would 

be most appropriately presented and analyzed in future NEPA analysis at the project lease and 

design stages. 

J.3.7 Land Use Planning and Leasing 

J.3.7.1 Issues within the Scope of the PEIS 

 Some comments raised issues associated with the land use planning process. One 

commentor noted that the BLM needs to explicitly address potential conflicts, for example, with 

oil and gas resources. It was suggested that the PEIS analyze the applicability of the Interim 

Final Rule on the Leasing in STSAs (October 2005) and how this specifically may affect NPS 

resources. One commentor asserted that the BLM should fully consider the impacts on or 

conflict with renewable energy development, suggesting coordination with the Solar Energy 

PEIS (BLM and DOE 2010). Others raised concerns about how development of oil shale and tar 

sands resources would be addressed in so-called “checkerboard” areas where federal lands are 

interspersed with state and private lands. 

 Commentors voiced concern about the continued multiple use of the BLM lands. It was 

noted that oil shale and tar sands development is generally inconsistent with multiple uses of 

land, because it displaces other land uses (e.g., recreation, mining, hunting, oil and gas 

production, livestock grazing, wild horse and burro herd management, communication sites, and 

ROW corridors). In addition, it involves the permanent removal of soil, which the commentors 

asserted therefore precludes other uses. Other commentors suggested that the BLM needs to 

show that there are actually competing priorities for the land. It was also noted that oil shale and 

tar sands development can be compatible with the development of other resources; commentors 

suggested that the BLM develop leasing programs that accommodate multimineral leasing. 

J.3.7.2 Issues outside the Scope of the PEIS, but Which May Present Related Policy 

Considerations 

 Commentors suggested that the BLM assess results from the RD&D leases with respect 

to safe production, cleanup, and restoration before large areas are opened. Commentors 

suggested that only competitive leases be accepted, that leasing targets and schedules be set to 

avoid exceeding carrying capacities, and that leasing regulations provide for minimum bonuses. 

In addition, it was suggested that leasing should be designed to test alternative recovery methods 

where shale is shallow but has adequate thickness and grade. 
Final OSTS PEIS J-32 

 Commentors noted that the BLM should avoid making irreversible commitments to oil 

shale and tar sands development within areas where Master Leasing Plans are being developed in 

consideration of other land uses and protections encompassed in such plans. Explicitly noted 

were Dinosaur Lowlands, Shale Ridge, Eastern Book Cliffs/Piceance Basin, Little Mountain, and 

Adobe Town. 

 It was recommended that the most recent RD&D lease progress reports be included in the 

PEIS. Commentors reiterated the fact that developers receiving leases will still have to go 

through the permitting process. 

J.3.7.3 Issues outside the Scope of the PEIS 

 One commentor also voiced concern over BLM’s ability to successfully manage impacts 

on the land from additional oil shale and tar sands leases, noting difficulties in managing impacts 

from off-road vehicle use and oil and gas leasing. Other commentors noted support for R&D on 

private lands. 

The above comment is not relevant to the proposed action being analyzed in the PEIS. 

J.3.8 Policy 

J.3.8.1 Issues within the Scope of the PEIS 

 Commentors identified a number of policy-related issues. The identified policy issues 

addressed in the PEIS include the following: 

• Concerns were raised over what new or different information and analysis 

should be expected from the EIS process and what guarantees the BLM can 

offer that this process will not be repeated in another two years. 

• Conformation of the PEIS scope to the legal mandates, requirements, and 

intent of Section 369(d)(1) of the Energy Policy Act of 2005 was a 

specifically noted concern. 

• Limitations associated with the PEIS only addressing the allocation of 

potentially suitable public lands for oil shale and tar sands development and 

not the actual leases were noted; it was suggested that the role of subsequent 

NEPA analyses in informing future decisions regarding leasing be addressed 

in the PEIS. 

• Some commentors stated that site-specific NEPA review will likely not 

provide an adequate region-wide analysis of the relationships to and impacts 

on resources (e.g., water use) across the three-state study area, while others 
Final OSTS PEIS J-33 

noted that it is not up to the BLM to determine what technologies are 

appropriate or will succeed, but to simply ensure the resource is available on a 

fair basis. In any case, appropriate and applicable environmental laws and 

regulations will be complied with and new information will be reviewed when 

specific development plans are submitted and before a project can proceed. 

• The need for consistency of any land use plan amendments with state and 

local plans and those of tribes to the extent provided by law, regulation, and 

policy was noted. 

• The need for identification and evaluation of key regulations, statutes, and 

agreements that will influence oil shale and tar sands development and 

support environmentally friendly practices was noted. 

• Inclusion of a discussion on the unique legislative history and purpose of 

Naval Oil Shale Reserves was recommended. It was stated that the reserves 

were meant for R&D and not for large-scale development, unless deemed 

essential to national security. 

• A need for the BLM to consult with other federal agencies, including the EPA 

and CEQ, was observed. 

• Conflicts with respect to the multiple uses of the public lands — particularly 

where oil shale and tar sands leasing and development could be in conflict 

with existing grazing, recreation, fishing, oil and gas development, and other 

resource objectives — were a noted concern. 

• Conflicting resource values (e.g., assessment of socioeconomic impacts of 

loss of recreational lands to oil shale and tar sands development uses) were 

observed by several commentors. 

J.3.8.2 Issues outside the Scope of the PEIS, but Which May Present Related Policy 

Considerations 

• Questions and concerns were raised about whether a revision of the original 

2008 PEIS is warranted or necessary. Specifically noted were the time and 

cost associated with the PEIS process. Commentors noted that the 2008 oil 

OSTS PEIS and RMP amendments (in addition to the 2008 Oil Shale Rule) 

were the result of a robust and valid public process which allows for resource 

development while protecting the environment and recreational uses of public 

lands. One commentor stated that by revisiting the PEIS, the BLM was in 

violation of the Federal Land Policy and Management Act of 1976 (FLPMA); 

another asserted the reduction of acreage sends a negative message to 

investment companies and the international community. Also mentioned was 

the fact that the areas proposed for removal from development are either 
Final OSTS PEIS J-34 

already off limits or may be precluded under BLM authority without redoing 

the entire PEIS. 

• Deferment of the PEIS and leasing decisions for development of public lands 

and further amendments to the RMPs was recommended until research, 

technology constraints, potential resource demands and impacts, 

environmental harms, and infrastructure challenges have been significantly 

and completely analyzed. Waiting until the RD&D results are available before 

promulgating regulations, so as to not render the regulations obsolete, was 

specifically recommended. 

• Support was expressed for the BLM to move forward with the leasing process 

and to develop the BLM oil shale and tar sands resources in an 

environmentally correct manner. 

• A need was identified for consistent and stable regulation and a reliable 

national policy from the BLM considering the needs of the entire country. The 

abandonment of federal R&D in the 1980s when oil prices decreased and the 

resulting uncertainty for industry was a noted concern. 

• Legality of oil shale and tar sands development and use was questioned under 

international and domestic climate change law, specifically Articles 2 and 3 of 

the United Nations Framework Convention on Climate Change (UNCCC). 

• Initiation of a process was recommended that will draft the regulations 

governing commercial leasing, mining, and development for this energy 

development scenario, prior to any commitment of land or commercial leasing 

approval. 

• One commentor stated that the PEIS must not incorporate any policy of 

“precautionary” bias or “worst case” scenarios, particularly any assumptions 

regarding impacts of extraction and mitigation technologies still undergoing 

development and testing. 

• Commentors urged acknowledgment and consideration of the Colorado River 

Storage Project Act and conservation programs, such as those in the Bear 

River Watershed of Idaho, Utah, and Wyoming. 

• Coordination and alignment of the OSTS PEIS with other energy EISs (such 

as the six-state Solar PEIS), thus turning these efforts into a National Energy 

Policy that addresses national needs more systematically, were suggested. 

• Needs for the development of oil shale and tar sands resources for national 

security, independence from foreign sources of fossil fuels, and the 

diversification of domestic energy resources were observed. Almost all 

commentors who stated strong support for oil shale and tar sands development 
Final OSTS PEIS J-35 

stated that their support was based on the nation’s need to end dependence on 

the import of foreign fuels and the desire to utilize this large domestic 

resource. 

• Concerns were expressed that taxes, royalties, and/or subsidies would be 

established or granted in a way that would be beneficial to the taxpayers, yet 

not deter investment in oil shale and tar sands development. One commentor 

suggested that royalty rates for commercial leases be at least equal to oil and 

gas rates. Another specifically mentioned that the NOI for the PEIS was 

deficient and gave no notice that the royalty rate (Title 43, Part 3903.52 of the 

Code of Federal Regulations [43 CFR 3903.52]) was to be reconsidered or 

removed. 

• Establishment of an adequate bond fund to finance future mitigation efforts 

and/or a trust fund to provide financial support to local communities early in 

the development process was recommended by several commentors. 

• Providing access to public lands for additional R&D outside the ongoing oil 

shale RD&D program was suggested. 

• Establishment of a technical advisory council, with members from the oil 

shale and tar sands industry and representing the region where findings from 

research could be shared with stakeholders, was recommended. 

• The importance of recognizing and considering preexisting contractual rights, 

in accordance with applicable law, was noted. 

J.3.8.3 Issues outside the Scope of the PEIS 

• A suggestion was made for the immediate release of 5% of federal lands in the 

study area to fast-track oil shale and tar sands development, with an additional 

10% released per year if success is demonstrated. 

This suggestion is outside the scope of the purpose and need of the PEIS. 

• Limiting the scope of the new PEIS to only those characteristics that differ 

from the originally known characteristics and that are relevant to the decisions 

in the 2008 ROD was recommended. 

This suggestion is outside the purpose and need of the PEIS to prepare a new PEIS. 

• Concerns were expressed that a specialist in oil shale and tar sands technology 

or mining was not specifically included as part of the BLM PEIS team. It was 

stated that such expertise would be essential in analyzing environmental 
Final OSTS PEIS J-36 

impacts associated with the resource development and extraction processes 

and developing a sound PEIS. 

The concerns expressed in the comment are not relevant to the scope of the PEIS. 

• Concerns were expressed that the state legislatures are too distant and do not 

have the authority to regulate tar sands and oil shale extraction, which will 

result in little or no oversight, emissions control, and protection against 

unanticipated construction. A bill passed by the Utah State legislature 

restricting the ability of a local town, city, or county to regulate any 

development for mining on any state or federally owned land was cited in 

support of this concern. 

The concerns expressed in the comment are not relevant to the scope of the PEIS. 

• The need for consistency with the ban on use of federal funds to implement 

Secretarial Order 3310, “Protecting Wilderness Characteristics on Lands 

Managed by the Bureau of Land Management,” was noted. It was further 

stated that any attempt to implement, administer, or enforce Secretarial Order 

3310 is a violation of Section 1769 of the April 21, 2011, Continuing 

Resolution, and thus the BLM should immediately cease all activities related 

to the OSTS PEIS. 

The concerns expressed in the comment are not relevant to the scope of the PEIS.

J.3.9 Alternatives 

J.3.9.1 Issues within the Scope of the PEIS 

 Commentors identified a number of issues related to alternative actions. The following 

considerations related to alternatives were submitted by one or more commentors: 

• Support for the No Action Alternative that would leave in place current 

commercial leasing land allocation decisions from the 2008 ROD was 

expressed by several commentors. They observed that attempts to reverse the 

ROD subverts the public process, contradicts the spirit of the 2008 ROD 

negotiations, would be in direct contravention of the Energy Policy Act of 

2005 and would be conducted without congressional authorization. 

• Support for a conservation alternative was expressed, which expands beyond 

the list of lands to be excluded in Alternative C from the 2008 OSTS PEIS. 

This alternative would remove from oil shale and tar sands development land 

that contains (1) identified and/or potential wilderness characteristics, 

(2) CPW areas, (3) all ACECs, (4) core sage-grouse and/or other priority 
Final OSTS PEIS J-37 

habitat areas, (5) migration routes of big game herds, (6) the Adobe Town 

Very Rare or Uncommon Area (Wyoming), (7) designated and potential 

ACECs; (8) suitable Wild and Scenic River segments, and (9) lands identified 

as excluded from commercial oil shale and tar sands leasing in Alternative C 

of the 2008 OSTS PEIS. 

• Consideration of a multiple-use alternative was proposed that would not 

remove several kinds of areas from oil shale and tar sands development. The 

proponent stated that it is possible to recover minerals without adversely 

impacting protected surface uses on lands that currently have restrictions for 

no surface disturbance through careful planning, management, mitigation and 

reclamation. 

• A suggestion was made for a limited leasing alternative that significantly 

limits the number of areas made available for commercial leasing until the 

extraction process and its effects on the environment are better understood. 

• Support was expressed for an alternative that limits leasing of public land to 

existing RD&D leases. 

• Concern was expressed regarding preexisting contractual rights that could be 

affected by any alternative that could remove significant areas from oil shale 

leasing. Maintaining the ability of RD&D leaseholders to exercise their 

commercial conversion rights (on the preference area identified in their lease) 

and other contractual rights contained in their leases was specifically noted. 

J.3.9.2 Issues outside the Scope of the PEIS, but Which May Present Related Policy 

Considerations 

• Addition of a deferred leasing and development alternative was recommended 

that would delay the decision on whether to make available certain lands for 

commercial leasing and development until a number of conditions are met, 

including (1) ongoing RD&D projects are significantly complete and results 

analyzed, (2) oil shale and tar sands development is demonstrated to be a 

viable industry, (3) BLM’s regulations are finalized, and (4) appropriate 

environmental quality standards are designed. 

• A suggestion was made that the BLM prepare a Statement of Energy Effects 

detailing the adverse effects on energy supply, distribution, and/or use 

(including a shortfall in supply, price increases, and increased use of foreign 

supplies) for all alternatives that reduce the original 2 million acres of oil 

shale and tar sands resources previously made available. 
Final OSTS PEIS J-38 

• A suggestion was made to consider the development of alternate energy 

sources and to include an alternative that compares renewable energy sources 

with oil shale and tar sands. 

• A suggestion was made for the inclusion of an alternative involving displacing 

the nation’s dependence on foreign oil through efficiency improvements. 

J.3.9.3 Issues outside the Scope of the PEIS 

• Addition of a No Action Alternative that would provide a baseline of 

environmental conditions in the area against which leasing alternatives could 

be assessed was recommended. 

The proposed additional No Action Alternative is not necessary; the current No Action 

Alternative provides a basis of comparison for other land allocation alternatives. See also the 

responses to similar comments regarding baseline studies in Section J.3.1.3. 

• Inclusion of the No Action Alternative A from the 2008 OSTS PEIS, under 

which no amendments to existing land use plans to identify lands available for 

application for commercial oil shale leasing would be completed, and under 

which there would be no commercial leasing or development of tar sands on 

public lands, was recommended. 

The proposed No Action Alternative is no longer relevant; land use plan amendments 

have already been made following the 2008 OSTS PEIS. 

• Inclusion of a No Development Alternative that would include no oil shale 

and tar sands leasing or development at all on public lands was recommended. 

The proposed No Development Alternative would not be responsive to the purpose and 

need of the PEIS, which is to analyze land allocation alternatives for a leasing program on 

public lands. 

• Inclusion of an alternative that allows an increase in the amount of acreage 

under consideration for leasing and development was recommended. 

The most geologically prospective area for oil shale and tar sands resources sets a 

reasonable and practical upper limit on the study area; Alternative 1, no action, includes the 

vast majority of the public lands in the study area. 

• Inclusion of Alternative C from the 2008 OSTS PEIS with no modifications 

was recommended, with supporters stating that the BLM’s reason for rejecting 

this alternative was flawed and that oil shale development was inappropriately 

prioritized over all other uses of public land. 
Final OSTS PEIS J-39 

It is not necessary to analyze the former Alternative C, since the current set of 

alternatives brackets lands therein and thus analyzes a range of impacts that encompasses that 

former alternative. 

• Opposition to Alternative C from the 2008 OSTS PEIS was expressed, which 

stated that the available acreage is trivial and would not facilitate development 

of the resources. 

The expressed opposition to the former Alternative C is not relevant to the scope of the 

current analysis. 

• Opposition was expressed to inclusion of an alternative that emphasizes 

natural resource protection. 

The expressed opposition to the mentioned alternative is contrary to the requirement of 

analyzing a full range of alternatives. 

• A suggestion was made that the BLM consider the incorporation of a phased 

development alternative. 

The suggested phased development alternative would not be compatible with the purpose 

and need of the PEIS, which is to analyze land allocation alternatives. 

• Consideration of an alternative was suggested, which would open all BLM oil 

shale and tar sands lands to development while specifically defining in each 

solicitation the environmental standards that must be met. 

The suggested alternative would not acknowledge existing restrictions on certain public 

lands, which would be in effect under any feasible alternative, and would not be responsive to 

the purpose and need of the PEIS to analyze alternatives which consider which lands should 

remain open for future leasing. 

• Inclusion of an alternative was proposed that limits development to deposits 

that are at least 25 ft thick and yield 25 gal/ton or more; different standards for 

different states would not be considered, and thus the poor resource deposits 

in Wyoming would be excluded. 

The separate criteria of 15 ft thick and 15 gal/ton used in Wyoming to define the study 

area were a necessary compromise to fairly account for the very large total (in-place barrels), 

albeit less rich, resource there. The proposed alternative would preclude this compromise. 

• A suggestion was made that the alternatives have varying production 

scenarios to allow for better comparison among the presented alternatives. 

Also suggested was setting regional production targets to minimize effects on 

parks and other conservation levels. 
Final OSTS PEIS J-40 

Given the nascent stage of the technologies in question, it would be premature to set 

regional production targets and use such targets to structure alternatives, because such an 

attempt would be speculative, at best. Moreover, it would be premature to set regional 

production targets as suggested, given the state of the technologies. 

• Concern was expressed related to alternatives that would remove any lands 

from leasing; it was cited that restricting available lands would choke off new 

technologies, impede progress being made, and hinder the ability to prove 

feasibility on federal land. It was further stated that such an alternative would 

create mostly noncontiguous parcels that would not allow for the efficient and 

economic development of the underlying oil shale resources. 

The PEIS includes the ongoing RD&D projects under all alternatives. Since these 

projects are located in some of the richest resource areas, there would be no concern of 

impeding technological progress under any of the alternatives analyzed. Regarding the second 

part of the comment, the current range of alternatives encompasses a variety of geographic 

distributions of available lands. 

J.3.10 Other Issues 

 Several other issues were raised in comments. The following were considered within the 

scope of the PEIS: the relationship between the PEIS and the ongoing oil shale RD&D program, 

their schedules, and data-sharing concerns. 

 Issues raised in scoping that were considered out of the scope of the PEIS were those 

more appropriately addressed in future NEPA analysis associated with lease applications, or 

within the ongoing RD&D programs. They included consideration of the mineral value of the 

shale itself (i.e., lithium, aluminum, and magnesium); consideration of natural seepage of oil into 

the ecosystem; and specifications on how the success of the technologies would be measured. 

J.4 INTERAGENCY COOPERATION AND GOVERNMENT-TO-GOVERNMENT 

CONSULTATION 

 The BLM initially invited about 55 federal, tribal, state, and local government agencies to 

participate in preparation of the OSTS PEIS as cooperating agencies. To date, 15 agencies have 

expressed an interest in participating as cooperating agencies and efforts are underway to 

establish Memoranda of Understanding. These 15 agencies are as follows: Grand County, Utah; 

Garfield County, Colorado; the State of Colorado; the State of Utah; the State of Wyoming; 

USFWS; NPS; Carbon County, Utah; Lincoln County, Wyoming; Uinta County, Wyoming; 

Uintah County, Utah; Coalition of Local Governments; Duchesne County, Utah; City of Rifle, 

Colorado; Sweetwater County, Wyoming; and Shoshone Business Council (Eastern Shoshone 

Tribe). 
Final OSTS PEIS J-41 

 In accordance with the requirements of Executive Order 13175, “Consultation and 

Coordination with Indian Tribal Governments,” the BLM will coordinate and consult with tribal 

governments, Native American communities, and individual tribal individuals whose interests 

might be directly and substantially affected by activities being considered in the Programmatic 

Environmental Impact Statement and Possible Land Use Plan Amendments for Allocation of Oil 

Shale and Tar Sands Resources on Lands Administered by the Bureau of Land Management 

in Colorado, Utah, and Wyoming.

J.5 FUTURE OPPORTUNITIES FOR PUBLIC INVOLVEMENT 

 Scoping is only the first phase of public involvement provided under the NEPA process. 

The next phase of public involvement will consist of public review and comment on the Draft 

OSTS PEIS. At this time, the BLM anticipates releasing the Draft OSTS PEIS for public review 

in early 2012; a 90-day comment period will be provided. 

 The public also will have an opportunity to review the Final OSTS PEIS when it is 

published. The BLM will provide a 30-day review period on the Final OSTS PEIS. In addition, 

the BLM will provide a protest period related to proposed RMP amendments. In accordance with 

43 CFR 1610.5-2, any person who participates in the planning process and has an interest that is 

or may be adversely affected by the proposed amendment of a RMP may protest such 

amendment. A protest may raise only those issues that were submitted for the record during the 

planning process. 

 Information about all opportunities for public involvement in the OSTS PEIS, including 

announcements of public meetings and releases of documents for review, will be maintained on 

the project Web site (http://ostseis.anl.gov). Individuals seeking e-mail notification of such 

opportunities can sign up for e-mail announcements. 

J.6 REFERENCES 

Note to Reader: This list of references identifies Web pages and associated URLs where 

reference data were obtained. It is likely that at the time of publication of this PEIS, some of 

these Web pages may no longer be available or their URL addresses may have changed. 

Bartis, J., et al., 2005, Oil Shale Development in the United States: Prospects and Policy Issues, 

prepared by RAND Corporation, Santa Monica, Calif., for the National Energy Technology 

Laboratory, U.S. Department of Energy. 

BLM (Bureau of Land Management), 2008a, Proposed Oil Shale and Tar Sands Resource 

Management Plan Amendments to Address Land Use Allocations in Colorado, Utah, and 

Wyoming and Final Programmatic Environmental Impact Statement, FES-08-32, Sept. 

Available at http://ostseis.anl.gov. 
Final OSTS PEIS J-42 

BLM, 2008b, Record of Decision for the Oil Shale and Tar Sands Resources Resource 

Management Plan Amendments, Nov. 17. 

BLM, 2011, “Notice of Intent To Prepare a Programmatic Environmental Impact Statement 

(EIS) and Possible Land Use Plan Amendments for Allocation of Oil Shale and Tar Sands 

Resources on Lands Administered by the Bureau of Land Management in Colorado, Utah, and 

Wyoming,” Federal Register 76:21003–21005. 

BLM and DOE (U.S. Department of Energy), 2010, Draft Programmatic Environmental Impact 

Statement for Solar Energy Development in Six Southwestern States, DES 10-59, DOE/EIS0403, Dec. 

GAO (Government Accountability Office), 2010, Energy-Water Nexus: A Better and 

Coordinated Understanding of Water Resources Could Help Mitigate the Impacts of Potential 

Oil Shale Development, GAO-11-35, Washington, D.C., Oct. Available at http://www.gao.gov/ 

products/GAO-11-35. 

USFWS (U.S. Fish and Wildlife Service), 2006, Guidelines for the State Wildlife Grant (SWG) 

Program, Oct. 18. Available at http://wsfrprograms.fws.gov/Subpages/ToolkitFiles/ 

SWG2007.pdf. 

USGS (U.S. Geological Survey), 2010a, Oil Shale and Nahcolite Resources of the Piceance 

Basin, Colorado, National Oil and Gas Assessment Project, Digital Data Series DDS–69–Y, 

USGS Oil Shale Assessment Team. 

 

USGS, 2010b, Oil Shale Resources of the Uinta Basin, Utah and Colorado, National Oil and 

Gas Assessment Project, Digital Data Series DDS–69–BB, USGS Oil Shale Assessment Team. 

 

USGS, 2011, Oil Shale Resources of the Eocene Green River Formation, Greater Green River 

Basin, Wyoming, Colorado, and Utah, National Oil and Gas Assessment Project, Digital Data 

Series DDS–69–DD, USGS Oil Shale Assessment Team.