A Technical, Economic, and Legal Assessment of North American Heavy Oil, Oil Sands, and Oil Shale Resources: In Response to Energy Policy Act of 2005 Section 369(p)

The purpose of this report is to assess unconventional North American resources, summarize current technologies for extracting and processing the resources, identify the issues which will affect the economic viability of various resource development schemes, evaluate the socioeconomic costs to communities and states impacted by such development, and analyze the regulatory and environmental climate in which the resource development will operate.

A T E C H N I C A L , E CO N OMI C , A N D LEG A L A S S E S SME N T O F North American Heavy Oil, Oil Sands, and Oil Shale Resources In Response to Energy Policy Act of 2005 Section 369(p) PREPARED FOR U.S. DEPARTMENT OF ENERGY PREPARED BY UTAH HEAVY OIL PROGRAM INSTITUTE FOR CLEAN AND SECURE ENERGY THE UNIVERSITY OF UTAH SEPTEMBER 2007 Disclaimer !is report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United Stated Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, complete-ness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the Unites States Government or any agency thereof. !e views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government. A Technical, Economic, and Legal Assessment of North American Heavy Oil, Oil Sands, and Oil Shale Resources In Response To Energy Policy Act of 2005 Section 369(p) Work Performed Under DE-FC-06NT15569 Prepared for U.S. Department of Energy O!ce of Fossil Energy and National Energy Technology Laboratory Prepared by Utah Heavy Oil Program Institute for Clean and Secure Energy The University of Utah 155 South 1452 East, Room 380 Salt Lake City, Utah 84112 September 2007 Utah Heavy Oil Program Unconventional Oils Research Report September 2007 ii Acknowledgments A Technical, Economic, and Legal Assessment of North American Oil Shale, Oil Sands, and Heavy Oil Resources In Response To Energy Policy Act of 2005 Section 369(p) is a report sponsored by the U.S. Department of Energy, Office of Fossil Energy and National Energy Technology Laboratory, and prepared under Contract Number DE-FC-06NT15569 by the Utah Heavy Oil Program in the Institute for Clean and Secure Energy at the University of Utah. Dr. David Alleman of the National Energy Technology Laboratory served as the Project Director for this report. Special recognition is due those who directly performed the work on this report. "e principal authors were Dr. Richardson Allen, Dr. Milind D. Deo, Mr. Alan E. Isaacson, Robert B. Keiter, Esq., Mr. Christopher Kessler, Dr. Raymond Levey, Dr. Kyeong Seok Oh, Dr. Philip J. Smith, Dr. Jennifer P. Spinti, and Kirsten Uchitel, Esq. on behalf of the Utah Heavy Oil Program. "is report benefited greatly from the input of Dr. Murray R. Gray, Constance K. Lundberg, Esq., Dr. Olayinka Ogunsola, Dr. David K. Olsen, and Mr. Bruce Ramzel. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 iii Forward !e Energy Policy Act of 2005 (EPAct) section 369 paragraph (p) calls for a heavy oil technical and economic assessment as follows: "(p) Heavy Oil Technical and Economic Assessment.--!e Secretary of Energy shall update the 1987 technical and economic assessment of domestic heavy oil resources that was prepared by the Interstate Oil and Gas Compact Commission. Such an update should include all of North America and cover all unconventional oil, including heavy oil, tar sands (oil sands), and oil shale." !e U.S. Department of Energy has tasked the Utah Heavy Oil Program (UHOP) of the Institute for Clean and Secure Energy at the University of Utah with preparation of this assessment in its Statement Of Program Objectives (SOPO) as follows: "To develop an update of the 1987 technical and economic assessment of domestic heavy oil resources that was prepared by the Interstate Oil and Gas Compact Commission, incorporating the 1995 DOE-funded update entitled ‘Feasibility Study of Heavy Oil Recovery in the United States' prepared by BDM-Oklahoma Inc. and other recent studies and data by others in the subject area. Such an update will include all of North America and cover all unconventional oil, including heavy oil, tar sands (oil sands), and oil shale. In addition, a publicly accessible online repository for infor-mation, data, and software pertaining to heavy oil resources in North America will be developed." !is report has been prepared in compliance with the requirements of the UHOP SOPO as derived from EPAct for this technical and economic assessment. Technical and economic issues are not independent of legal and environmental issues. As the legal and environmental issues impact technical and economic ones, they have been included in this report. In the spirit of providing both historical and ongoing information, data and software to individuals and organizations seeking information on heavy oil issues, the Institute for Clean and Secure Energy has created and maintains a publicly accessible online repository at http://www.heavyoil.utah.edu. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 iv Utah Heavy Oil Program Unconventional Oils Research Report September 2007 v Table of Contents List of Figures ..............................................................................................................................viii List of Tables .................................................................................................................................x List of Acronyms ...........................................................................................................................xi List of Units ...............................................................................................................................xiv Executive Summary ......................................................................................................................xv 1 Introduction ........................................................................................................................... 1.1 1.1 Energy and Global Economic Development ................................................................. 1.1 1.2 North American Unconventional Oil Resources ........................................................... 1.2 1.3 Unconventional Oil Resources and the Global Petroleum Market ................................. 1.4 1.4 Heavy Oil ..................................................................................................................... 1.4 1.5 Oil Sands ...................................................................................................................... 1.5 1.6 Oil Shale ....................................................................................................................... 1.5 1.7 Upstream Processing ..................................................................................................... 1.5 1.8 Downstream Processing and Markets ............................................................................ 1.7 1.9 Economic Issues ............................................................................................................ 1.7 1.10 Legal and Environmental Issues .................................................................................. 1.8 1.11 Summary .................................................................................................................... 1.8 1.12 References ................................................................................................................... 1.9 2 Utah Heavy Oil Program ArcIMS® Map Server Interface ....................................................... 2.1 2.1 UHOP ArcIMS® Map Server Interface ......................................................................... 2.1 2.2 Toolbar Description ...................................................................................................... 2.2 2.3 ArcIMS® Table of Contents ........................................................................................... 2.3 2.4 Usage Tips .................................................................................................................... 2.4 2.5 Accessing the UHOP Repository through the Map Server Interface .............................. 2.4 2.5.1 Using the Identify Results Tool ............................................................................ 2.5 2.5.2 Using the Select by Rectangle Tool ...................................................................... 2.6 2.5.3 Using the Query UHOP Repository Tool ............................................................ 2.7 2.6 Future Work ................................................................................................................. 2.8 3 The North American Unconventional Oil Resource ............................................................... 3.1 3.1 Heavy Oil Resource ...................................................................................................... 3.3 3.1.1 Canadian Heavy Oil Resource ............................................................................. 3.5 3.1.2 U.S. Heavy Oil Resource ..................................................................................... 3.6 3.1.3 Mexican and Central American Heavy Oil Resource ........................................... 3.8 3.2 Oil Sands Resource ..................................................................................................... 3.12 3.2.1 Canadian Oil Sands Resource ............................................................................ 3.14 3.2.2 U.S. Oil Sands Resource .................................................................................... 3.14 3.2.3 Mexican and Central American Oil Sands Resource .......................................... 3.17 3.3 Oil Shale Resource ...................................................................................................... 3.17 3.3.1 Canadian Oil Shale Resource ............................................................................. 3.20 3.3.2 U.S. Oil Shale Resource..................................................................................... 3.20 3.3.3 Mexican and Central American Oil Shale Resource ........................................... 3.21 3.4 New Technology Impacts ............................................................................................ 3.21 3.5 References ................................................................................................................... 3.21 4 Production/Processing Technologies for Unconventional Oil Resources ................................. 4.1 4.1 Production Processes for Heavy Oil .............................................................................. 4.2 4.1.1 Evolution of Steam Injection Technologies .......................................................... 4.3 4.1.2 Reservoir and Performance Monitoring ............................................................... 4.5 4.1.3 Screening Criteria for Steamflood Technologies ................................................... 4.5 4.1.4 Models for Steamflood Performance .................................................................... 4.6 4.1.5 New Technology Impacts and Future Research .................................................... 4.6 4.1.6 Selected Field Surveys .......................................................................................... 4.8 Utah Heavy Oil Program Unconventional Oils Research Report September 2007 vi 4.1.6.1 PRU Fee in the Midway-Sunset Field ........................................................... 4.8 4.1.6.2 Kern River Field ........................................................................................... 4.9 4.1.6.3 Coalinga Field ............................................................................................ 4.10 4.1.7 In Situ Combustion ........................................................................................... 4.10 4.2 Production Processes for Oil Sands ............................................................................. 4.11 4.2.1 Oil Characteristics ............................................................................................. 4.11 4.2.2 Surface Mining and Processing .......................................................................... 4.13 4.2.2.1 Surface Mining........................................................................................... 4.14 4.2.2.2 Hot Water Extraction Process ..................................................................... 4.14 4.2.2.3 Water Process for Utah Oil Sands ............................................................... 4.16 4.2.2.4 Solvent Extraction Processes ....................................................................... 4.17 4.2.2.5 Thermal Cracking ...................................................................................... 4.17 4.2.3 In Situ Processes ................................................................................................ 4.19 4.2.3.1 Cyclic Steam Stimulation and Related Methods ......................................... 4.19 4.2.3.2 Steam Assisted Gravity Drainage ................................................................ 4.20 4.2.3.3 Vapor Extraction (VAPEX)......................................................................... 4.21 4.2.3.4 Steamflooding ............................................................................................ 4.21 4.2.3.5 In Situ Combustion ................................................................................... 4.22 4.3 Production Processes for Oil Shale .............................................................................. 4.23 4.3.1 Chemical Nature of Oil Shale ............................................................................ 4.24 4.3.2 Surface Mining and Retorting ........................................................................... 4.26 4.3.2.1 Indirect Retorting ...................................................................................... 4.28 4.3.2.2 Direct Retorting ......................................................................................... 4.29 4.3.2.3 Alberta Taciuk Processor............................................................................. 4.29 4.3.3 In Situ Retorting ............................................................................................... 4.31 4.3.3.1 In Situ Conversion Process ......................................................................... 4.31 4.3.4 Ongoing Commercialization Efforts .................................................................. 4.33 4.3.4.1 Surface Mining and Extraction Processes .................................................... 4.33 4.3.4.2 In Situ Processes ......................................................................................... 4.33 4.4 References ................................................................................................................... 4.34 5 Upgrading and Refining ......................................................................................................... 5.1 5.1 Unconventional Fuels Market ....................................................................................... 5.1 5.2 Canadian Upgrading and Refining Strategies ................................................................ 5.2 5.3 Upgrading of U.S. Unconventional Fuels ...................................................................... 5.4 5.3.1 Oil Sands Bitumen .............................................................................................. 5.6 5.3.2 Shale Oil ............................................................................................................. 5.7 5.4 Primary Upgrading Technologies .................................................................................. 5.8 5.4.1 Visbreaking ......................................................................................................... 5.8 5.4.2 Delayed Coking .................................................................................................. 5.8 5.4.3 Fluid Coking and Flexicoking ............................................................................. 5.8 5.4.4 Fluid Catalytic Cracking...................................................................................... 5.9 5.4.5 Hydroconversion ............................................................................................... 5.10 5.5 Secondary Upgrading Technologies ............................................................................. 5.10 5.5.1 Hydrocracking ................................................................................................... 5.10 5.5.2 Hydrotreatment for Bitumen-Derived Liquids .................................................. 5.10 5.5.3 Hydrotreatment for Shale Oil ............................................................................ 5.12 5.6 Enhanced Upgrading .................................................................................................. 5.13 5.6.1 Solvent Deasphalting and Supercritical Extraction ............................................. 5.13 5.6.2 Gasification ....................................................................................................... 5.14 5.6.3 Novel Hydrovisbreaking and Fast Pyrolysis ........................................................ 5.15 5.7 Summary .................................................................................................................... 5.15 5.8 References ................................................................................................................... 5.16 Utah Heavy Oil Program Unconventional Oils Research Report September 2007 vii 6 Economic and Social Issues Related to Unconventional Oil Production ................................. 6.1 6.1 Operating Economics ................................................................................................... 6.2 6.1.1 Heavy Oil ............................................................................................................ 6.3 6.1.2 Oil Sands ............................................................................................................. 6.7 6.1.3 Oil Shale ............................................................................................................. 6.9 6.2 Infrastructure .............................................................................................................. 6.11 6.2.1 Refining Capacity .............................................................................................. 6.11 6.2.2 Transportation ................................................................................................... 6.13 6.3 Socioeconomics .......................................................................................................... 6.17 6.3.1 Heavy Oil .......................................................................................................... 6.18 6.3.2 Oil Sands ........................................................................................................... 6.25 6.3.3 Oil Shale ........................................................................................................... 6.28 6.4 New Technology Impacts ............................................................................................ 6.31 6.5 Refinery Capacity Data by State.................................................................................. 6.33 6.6 References ................................................................................................................... 6.38 7 Environmental, Legal and Policy Issues Related to Unconventional Fuel Resource Development on the Public Lands ............................................................................................................... 7.1 7.1 General Legal and Policy Framework for Unconventional Fuel Resource Development 7.3 7.1.1 Mineral Leasing Act of 1920, as Amended by the Combined Hydrocarbon Leasing Act of 1981 and the Energy Policy Act of 2005 ................................................... 7.3 7.1.2 Energy Policy Act of 2005 ................................................................................... 7.5 7.1.2.1 Programmatic Environmental Impact Statement for Oil Shale and Oil Sands Leasing in Colorado, Wyoming and Utah .................................................... 7.6 7.1.2.2 Research, Development and Demonstration Leases for Oil Shale Technologies .. 7.6 7.1.2.3 Regulatory Framework for Oil Sands and Oil Shale ..................................... 7.7 7.1.3 Summary ............................................................................................................. 7.8 7.2 Existing Environmental Analysis and Land Use Planning Obligations under the National Environmental Policy Act and the Federal Land Policy and Management Act for Commercial Leasing and Development of Unconventional Fuel Resources ........... 7.10 7.2.1 National Environmental Policy Act ................................................................... 7.10 7.2.2 Federal Land Policy and Management Act ......................................................... 7.13 7.2.3 Summary ........................................................................................................... 7.16 7.3 Legal and Policy Framework for Air Quality Issues and Impacts Related to Unconventional Fuel Resource Development ............................................................. 7.17 7.3.1 Clean Air Act .................................................................................................... 7.18 7.3.2 Comprehensive Environmental Response, Compensation and Liability Act ...... 7.20 7.3.3 Greenhouse Gas Emissions ................................................................................ 7.20 7.4 Legal and Policy Framework for Flora and Fauna Issues and Impacts Related to Unconventional Fuel Resource Development ............................................................. 7.21 7.4.1 Endangered Species Act ..................................................................................... 7.21 7.4.2 Migratory Bird Treaty Act; Bald Eagle Protection Act ........................................ 7.23 7.5 Legal and Policy Framework for Land Management Issues and Impacts Related to Unconventional Fuel Resource Development ............................................................. 7.23 7.6 Legal and Policy Framework for Water Issues and Impacts Related to Unconventional Fuel Resource Development ....................................................................................... 7.24 7.6.1 Clean Water Act ................................................................................................ 7.25 7.6.2 Safe Water Drinking Act .................................................................................... 7.25 7.6.3 Colorado River Basin Salinity Control Act ........................................................ 7.25 7.6.4 Law of the River ................................................................................................ 7.26 7.6.5 Endangered Species Act ..................................................................................... 7.27 7.7 Reclamation ................................................................................................................ 7.28 7.8 References ................................................................................................................... 7.29 Utah Heavy Oil Program Unconventional Oils Research Report September 2007 viii List of Figures Figure 1-1. World marketed energy consumption by region ..............................................1.1 Figure 1-2. Total world primary energy consumption (% by fuel) .....................................1.1 Figure 1-3. Historical and projected domestic energy consumption by fuel in quadrillion BTUs .................................................................................1.2 Figure 1-4. Size of world conventional oil reserves compared to U.S. oil shale and Canadian oil (tar) sands reserves .......................................................1.3 Figure 1-5. Costs of oil dependence to the U.S. economy from 1970-2006 assuming a constant competitive world oil price of $13 per barrel ...................1.4 Figure 2-1. Some of the frames available in the UHOP map server interface .....................2.1 Figure 2-2. Table of contents for map server interface .......................................................2.3 Figure 2-3. Accessing the UHOP repository through posted tabular results .......................2.5 Figure 2-4. Tabular results using the Identify Results tool..................................................2.6 Figure 2-5. Tabular results using the Select by Rectangle tool ............................................2.7 Figure 2-6. Results from a UHOP Dspace repository query ..............................................2.8 Figure 3-1. Chart of heavy oil, extra heavy oil, and bitumen based on viscosity vs. density .....3.1 Figure 3-2. Main distribution of heavy oil to bitumen, and variation during degradation. .3.2 Figure 3-3. Map from the UHOP map server interface showing the location of heavy oil deposits in North America ................................................................3.3 Figure 3-4. Age of heavy oil deposits in the United States and Canada ..............................3.4 Figure 3-5. Location of the Grosmont Platform in Alberta and its relationship to the Athabasca Oil Sands and the Lloydminster heavy oil deposits ..........................3.6 Figure 3-6. Location of the southwestern California heavy oil basins .................................3.7 Figure 3-7. Distribution of heavy oil overlying the Kuparuk River, Milne Point, and Prudhoe Bay fields on the North Slope of Alaska .............................................3.8 Figure 3-8. Map of the exploration and production regions (Región) of Mexico ..............3.10 Figure 3-9. Map of the areas (Activo Integral) in the Marina Noreste region in Mexico ...........................................................................................3.10 Figure 3-10. Map of the areas (Activo Integral) in the Norte region in Mexico ..................3.11 Figure 3-11. Map from the UHOP map server interface showing the location of oil sands in the North America ......................................................................3.12 Figure 3-12. Age of oil sands deposits in the United States and Canada .............................3.13 Figure 3-13. Location of oil sands in Utah ........................................................................3.16 Figure 3-14. Map from the UHOP map server interface showing the location of oil shale deposits in North America ...........................................................3.17 Figure 3-15. Age of oil shale deposits in the United States and Canada .............................3.18 Figure 3-16. Location of the Green River Formation in Wyoming, Utah and Colorado ....3.20 Figure 4-1. California heavy oil production and steam injection to produce the heavy oil during the period 1991-2005 ......................................................4.3 Figure 4-2. Breakdown of steamflood/steamdrive processes in California over a 40-year period .......................................................................................4.4 Figure 4-3. Heat management in a steamflood process ......................................................4.5 Figure 4-4. Evolution of steamflood theory from a pressure displacement process to a gravity drainage process ................................................................4.6 Figure 4-5. Schematic diagram of a water-based bitumen recovery process. .....................4.15 Figure 4-6. Bitumen liberation and aeration in water-based extraction process ................4.16 Figure 4-7. Schematic of a cyclic steam stimulation process showing injection, soak and production ......................................................................4.20 Figure 4-8. Illustration of the SAGD process including the horizontal injector, the horizontal producer, and some surface facilities. .........................4.21 Utah Heavy Oil Program Unconventional Oils Research Report September 2007 ix Figure 4-9. Schematic of the THAI Process .....................................................................4.22 Figure 4-10. Generalized processes for conversion of shale to fuels and byproducts ...........4.23 Figure 4-11. TOSCO II process ........................................................................................4.28 Figure 4-12. Gas combustion retorting process ..................................................................4.29 Figure 4-13. Alberta Taciuk Process system........................................................................4.30 Figure 4-14. Shell In situ Conversion Process ....................................................................4.32 Figure 5-1. Combination of technologies to reduce dependence of upgrading on natural gas .................................................................................5.3 Figure 5-2. Schematic of a fluid coker ...............................................................................5.9 Figure 5-3. Conceptual simulated distillation curves for the extract, bitumen and the residue after supercritical extraction ....................................5.13 Figure 6-1. Real price of imported, low-sulfur crude oil with forecasts to 2030 .................6.1 Figure 6-2. Price of WTI and less than 20° API gravity crude ...........................................6.4 Figure 6-3. Internal rates of return for a single inverted nine-spot well pattern ..................6.6 Figure 6-4. Petroleum Administration for Defense Districts ............................................6.12 Figure 6-5. PADD IV refinery utilization rates ................................................................6.13 Figure 6-6. Crude oil pipelines and refineries, with capacities in barrels per day, in the Rocky Mountains and the Midwest ..............................................6.15 Figure 6-7. Kern County, California ................................................................................6.19 Figure 6-8. Southern California area................................................................................6.20 Figure 6-9. Utah counties directly impacted by future oil sands development ..................6.25 Figure 6-10. Counties directly impacted by future oil shale development ..........................6.28 Figure 7-1. The White River oil shale mine located south of Bonanza, Uintah County, Utah ......................................................................................7.2 Figure 7-2. Oil shale and oil sands deposits in Utah, including STSA and sensitive lands designations .......................................................................7.4 Figure 7-3. Utah oil sands with seeping bitumen ...............................................................7.9 Figure 7-4. Oil shale from the Green River Formation ......................................................7.9 Figure 7-5. Green River Formation oil shale outcropping ................................................7.17 Figure 7-6. The Colorado River Basin .............................................................................7.27 Utah Heavy Oil Program Unconventional Oils Research Report September 2007 x List of Tables Table 2-1. Tools and buttons available for use with the UHOP map server .........................2.2 Table 3-1. U.S. Heavy Oil Database (10°-20° API gravity) ................................................3.5 Table 3-2. Table of the remaining proven, probable and possible hydrocarbon reserves in Mexico as of January 1, 2006 .......................................3.9 Table 3-3. Original in-place crude oil and oil sands and remaining proven reserves for Alberta ..........................................................................................3.14 Table 3-4. Oil sands resource in the Athabasca, Peace River and Cold Lake deposits .........3.14 Table 3-5. Oil sands resource in the United States ............................................................3.15 Table 3-6. Table of the Utah oil sands resource in-place ....................................................3.15 Table 3-7. Characterization of North American oil shale deposits .....................................3.19 Table 4-1. Typical physical and chemical properties of Utah oil sands bitumen ............................................................................................4.12 Table 4-2. Typical physical and chemical properties of Canadian Athabasca and Cold Lake bitumens .................................................................4.13 Table 4-3. Bitumen viscosity comparison of Utah and Canadian Athabasca oil sands ..........................................................................................4.13 Table 4-4. Properties of bitumen-derived products obtained by thermal fluidized-bed pyrolysis of oil sands ..................................................................4.18 Table 4-5. Material balance and Fisher Assay results for reference shales............................4.25 Table 4-6. Average chemical and elemental compositions of several oil shale samples from Rifle, Colorado in the Green River Formation ........................................4.26 Table 5-1. Available upgrading processess ...........................................................................5.5 Table 5-2. Operating temperatures and pressures of upgrading technologies .......................5.6 Table 5-3. Comparison of yield and conversion results for upgrading of Asphalt Ridge bitumen ......................................................................................5.7 Table 5-4. Properties of shale oil (raw and upgraded) and of a light Arab crude ..................5.7 Table 5-5. Properties of bitumen and bitumen-derived liquids from the Whiterocks, Utah oil sands deposit ..................................................................5.12 Table 5-6. Extraction yields and properties from the supercritcal propane extraction of four Utah bitumens ....................................................................5.14 Table 6-1. Costs applicable to steam injection, 1990-2004 .................................................6.5 Table 6-2. Steam injection economic parameters considered for internal rate of return calculations ..................................................................................6.7 Table 6-3. Production costs of Canadian oil sands, 2005 dollars per barrel .........................6.8 Table 6-4. Refinery capacity by PADD district and process ...............................................6.12 Table 6-5. Petroleum flows by pipeline (thousand barrels) between the Rocky Mountains and adjacent areas, 2005 .....................................................6.14 Table 6-6. Estimated construction costs of proposed pipeline projects, 2006 ....................6.16 Table 6-7. Annual average wages in the affected states by industry, 2005 ..........................6.18 Table 6-8. Socioeconomic profiles of examined heavy oil areas..........................................6.20 Table 6-9. Oil industry employment and wages in the heavy oil areas, 2005 .....................6.21 Table 6-10. Employment by industry in Kern County, California, 2005.............................6.21 Table 6-11. Employment by industry of North Slope Borough, Alaska, 2005 .....................6.22 Table 6-12. Employment by industry of the three southern California counties, 2005 ........6.23 Table 6-13. Recent oil and gas production in heavy oil areas ...............................................6.24 Table 6-14. Socioeconomics of the oil sands area ................................................................6.26 Table 6-15. Employment by industry in the oil sands area, 2005 ........................................6.26 Table 6-16. Recent oil and gas production in the oil sands area ...........................................6.27 Table 6-17. Socieoconomics of the oil shale area .................................................................6.29 Table 6-18. Employment by industry in the oil shale area, 2005 .........................................6.29 Table 6-19. Recent oil and gas production in the oil shale area ...........................................6.30 Table 6-20. Petroleum refineries in states most likely to produce heavy oil, oil sands and oil shale ......................................................................................6.33 Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xi List of Acronyms ACEC Areas of Critical Environmental Concern ARC Alberta Research Council API American Petroleum Institute ATP Alberta Taciuk Processor BACT Best Available Control Technology BEPA Bald Eagle Protection Act BLM Bureau of Land Management BOPD Barrels of Oil per Day C Carbon C1 Methane C4 Butane C5 Pentane C$ Canadian Dollars CAA Clean Air Act CAPP Canadian Association of Petroleum Producers CCR Conradson Carbon Residue CEQ Council on Environmental Quality CERCLA !e Comprehensive Environmental Response, Compensation, and Liability Act CFR Code of Federal Regulations CHLA Combined Hydrocarbon Leasing Act CO2 Carbon Dioxide CRBSCA Colorado River Basin Salinity Control Act CSS Cyclic Steam Stimulation CWA Clean Water Act DOE Department of Energy DOI Department of Interior DTS Distributed Temperature Sensing EA Enviromental Assessment EIS Environmental Impact Statement EOR Enhanced Oil Recovery EPA Environmental Protection Agency EPAct Energy Policy Act of 2005 ES-SAGD Expanding Solvent Steam-Assisted Gravity Drainage ESA Endangered Species Act FCC Fluid Catalytic Cracking FERC Federal Energy Regulatory Commission FLPMA Federal Land Policy and Management Act FONSI Finding of No Significant Impact FWS Fish and Wildlife Service GCRA Global Change Research Act GIS Geographic Information System GML General Mining Law GDP Gross Domestic Product H Hydrogen H2 Hydrogen Gas H/C Hydrogen to Carbon Ratio HUTF Hydrocarbon Upgrading Task Force IBP Initial Boiling Point Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xii ICP In situ Conversion Process IOGCC Interstate Oil and Gas Compact Commission IOR Improved Oil Recovery IRR Internal Rate of Return LAER Lowest Achievable Emissions Reduction LASER Liquid Addition to Steam for Enhancing Recovery LNG Liquified Natural Gas LPG Liquified Petroleum Gas MACT Maximum Available Control Technology MBTA Migratory Bird Treaty Act MLA Mineral Leasing Act MMBO Million Barrels of Oil MW Molecular Weight N Nitrogen NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification System NaOH Sodium Hydroxide NCUT National Centre for Upgrading Technology NEPA National Environmental Policy Act NESHAPS National Emission Standards for Hazardous Air Pollutants Ni Nickel NMFS National Marine Fisheries Service NPS National Park Service O Oxygen OECD Organisation for Economic Co-operation and Development OIP Oil in Place OOIP Original Oil In Place OPEC Organization of the Petroleum Exporting Countries PADD Petroleum Administration for Defense Districts PEIS Programmatic Environmental Impact Statement PET Production Enhancement Tools PNC Pulsed Neutron Capture PSD Prevention of Significant Deterioration RACT Reasonably Available Control Technology RCRA Resource Conservation and Recovery Act RD&D Research, Development and Demonstration RMP Resource Management Plan S Sulfur SAGD Steam-Assisted Gravity Drainage SARA Saturates, Aromatics, Resins and Asphaltenes SCO Synthetic Crude Oil SG Specific Gravity SI International System of Units SIP State Implementation Plan SO2 Sulfur Dioxide SOR Steam to Oil Ratio STSA Special Tar Sand Area SWDA Safe Water Drinking Act Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xiii TESS !reatened and Endangered Species System THAI Toe-to-Heel-Air-Injection TMDL Total Maximum Daily Load UHOP Utah Heavy Oil Program UNITAR United Nations Institute for Training and Research USFS United States Forest Service USGS United States Geological Survey V Vanadium VAPEX Vapor Extraction WOR Water to Oil Ratio WPC World Petroleum Congress WQS Water Quality Standard WSA Wilderness Study Area WSR Wild and Scenic River WTI West Texas Intermediate Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xiv List of Units BTU British !ermal Unit BTU/lb British !ermal Units per pound cP Centipoise D Darcies g/cc Grams per cubic centimeter GW Gigawatt KW Kilowatt KW-hr Kilowatt hour m3/s Cubic meters per second MCF !ousand cubic feet mD Millidarcies MJ/kg Megajoules per kilogram MMBTU Million British !ermal Units MPa Megapascals Pa•s Pascal seconds ppm Parts per million psia Pounds per square inch absolute wt% Weight percent Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xv Executive Summary Against the backdrop of world population growth, rapid economic expansion in the world's most populous countries, challenging political climates in many oil-producing nations, and the specter of climate change, worldwide energy consumption is projected to increase from the 2004 level of just over 400 quadrillion British !ermal Units (BTUs) to over 700 quadrillion BTUs in 2030 [1]. With 35% of the world's energy needs being met by petroleum in 2003 [2], petroleum is expected to remain a domi-nant player in worldwide energy markets for the foreseeable future. Consequently, world economic development will continue to be significantly impacted by the cost of oil. In the United States, energy policy is again focused on evaluating domestic energy resources and their potential to achieve greater energy independence and reduce future energy crises. Unconventional hydrocarbon resources, including heavy oil, oil sands, and oil shale, represent a significant North American resource. Estimates of proven conventional oil reserves worldwide are 1.0 trillion barrels with an additional 1.7 trillion barrels of possible/undiscovered reserves [3]. Canadian oil sands reserves are estimated at 1.7 trillion barrels with 174 billion barrels recoverable using proven current tech-nologies [4]. A conservative estimate of worldwide in-place oil shale reserves is 2.9 trillion barrels, with 2.0 trillion barrels of this resource located in the United States [5]. !e Rand report puts the range of oil recovery from shale at 0.5-1.1 trillion barrels depending on the percent accessible and recoverable [6]. !e purpose of this report is to assess unconventional North American resources, summarize current technologies for extracting and processing the resources, identify the issues which will affect the economic viability of various resource development schemes, evaluate the socioeconomic costs to communities and states impacted by such development, and analyze the regulatory and environmental climate in which the resource development will operate. In addition to this written report, the Utah Heavy Oil Program (UHOP) of the Institute for Clean and Secure Energy at the University of Utah has been commis-sioned to build a repository to hold information relevant to the resources of heavy oil, oil shale and oil sands in North America. UHOP has developed a map server interface to deliver dynamic maps and to explore the UHOP repository in a geospatial setting. All that is required for users to interface with the UHOP map server is a fast internet connection and a compatible web browser. !e current URL for the UHOP map server is http://map.heavyoil.utah.edu/website/uhop_ims. Origin of unconventional fuel resources. !e unconventional fuels assessed in this report are classified as heavy oil/extra heavy oil, bitumen from oil sands, and oil shale. To form conventional and unconventional fuels, organic material was buried in fine grained sediments in an oxygen poor environment. !is buried material was first converted to kerogen, an immature form of organic material and a precursor to oil, at shallow depths and at temperatures below 122°F (50°C). Kerogen was further converted to oil at depths of 1.2-2.4 miles (2-4 kilometers) and temperatures of 122°- 212°F (50°-100°C) [8]. Heavy and extra heavy crude oil are biodegraded forms of oil that occur when lighter oil fractions are lost or are consumed by bacteria in the reservoir, leaving the heavier molecules behind [9]. Oil sands are an extremely heavy form of crude oil [10]. Oil sand is defined as any consolidated or unconsolidated rock, An unconventional fuel cannot be recovered in its natural state from an ordinary production well, i.e. it cannot be pumped without being heated or diluted [7]. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xvi exclusive of coal or oil shale, that contains a hydrocarbon material known as bitumen. Oil sands are generally comprised of crude bitumen, sand, water, and clay. Oil shale is defined as a fine-grained sedimentary rock bound with kerogen where the organic and the inorganic matter are inextricably combined. Classification of unconventional fuel resources. Heavy oil, extra heavy oil, and bitumen from oil sands, all organic liquids, are classified by their American Petroleum Institute (API) gravity and viscosity. !e API gravity scale, graduated in degrees, was designed so that most hydrocarbon liquids would be in the range from 10°-70°. Light crude oil has an API gravity that exceeds 31.1° [7]. Heavy oil has an API gravity of 10°-22.3° and viscosity of 100-10,000 cP at 60°F (15.6°C); extra heavy oil has an API gravity below 10° and viscosity of 100-10,000 cP at 60°F (15.6°C); and bitumen has viscosity above 10,000 cP at 60°F (15.6°C) [11]. Bitumen viscosity is so high that it does not flow and cannot be pumped without being heated, diluted, or upgraded. Oil shale, a fine-grained sedimentary rock rich in kerogen, has a distinct classification from heavy oil and bitumen. All known processes for disengaging the kerogen from the inorganic matrix and converting it to oil require heat input. Heating the source rock yields oil, natural gas, and/or graphite [12,13]. Heavy oil resource. North American heavy oil/extra heavy oil deposits are located in Canada, the United States, and Mexico. !e three largest North American deposits are the Lloydminster deposits in western Canada containing 101.7 billion barrels original oil in place (OOIP) [14], a series of deposits in California with 75.8 billion barrels OOIP, and the deposits in the Schrader Bluff/West Sak/Ugnu area on the North Slope of Alaska with 25 - 30 billion barrels OOIP [15,16]. In the U.S. Heavy Oil Database [17], which is exclusive of Alaska, total OOIP constitutes 84.2 billion barrels. Cumulative production has reached 10.8 billion barrels, leaving the remaining oil in place at 73.4 billion barrels. Estimates of Mexican heavy oil reserves are 18.8 billion barrels remaining oil in place, which accounts for about 57% of the total remaining proved, probable and possible oil in place in Mexico [18]. Oil sands resource. North American oil sands deposits are located in Canada and the United States. Canada has one of the greatest oil reserves in the world in the form of oil sands, with almost 1.7 trillion barrels of OOIP in the form of bitumen in western Canada [4]. !e U.S. oil sands resource is estimated at 54 billion barrels OOIP in the form of bitumen; 22 billion barrels are considered to be a measured resource with 32 billion barrels considered speculative [19]. !e largest oil sands deposits in the United States are in the state of Utah with proven reserves of 8-12 billion OOIP in the form of bitumen and total reserves (including speculative reserves) of 23-32 billion barrels OOIP [19-21]. Oil shale resource. North American oil shale resources occur in Canada and the United States. !e Green River Formation in Colorado, Utah, and Wyoming is, volumet-rically, the largest oil shale resource in the United States with resource estimates of 1.5-1.8 trillion barrels OOIP in shale deposits exceeding a grade of 15 gallons of oil per ton of shale [22]. Devonian-Lower Mississippian shales in the eastern United States show lower total organic content than the Green River Formation but may contain 189 billion barrels OOIP in the form of kerogen [5]. Canadian oil shale reserves have been identified, but many lack estimates on the size of the resource [5,23]. API Gravity = (141.5/speci!c gravity at 60°F) - 131.5. Water has an API gravity of 10°. A liquid with API greater than 10° "oats on water while a liquid with API less than 10° sinks in water. Centipoise (cP) is one hundredth of a poise, a unit of viscosity in the centimeter-gram-second unit system. OOIP refers to oil in place prior to any production. The terms oil sands and tar sands are synonymous. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xvii Current unconventional fuel production. In the United States, the only unconven-tional fuel currently being produced on a commercial scale is heavy oil. Most heavy oil production is in the state of California, where production levels have declined continu-ously in the past decade from a high of 660,000 BOPD in 1996 to 470,000 BOPD in 2005 [24]. Continued high oil prices have spurred additional investment and drilling in California, the effect of which might be a slower decline in production in 2007. However, unless other large fields come on line, it is unlikely that the observed decline will be arrested. !ere are also large heavy oil resources in Alaska, but Alaskan produc-tion of heavy oil is low relative to total heavy oil production in the United States. In 2003, combined Alaskan heavy oil production from two units was 26,800 BOPD [25]. Heavy oil production also occurs on a commercial scale in Canada and Mexico, however, both countries use definitions of heavy oil that vary from that used in this report. Pemex, the Mexican state oil company, reported production of 2.4 million BOPD of heavy crude oil during 2005. In 2006, reported production dropped 6% from 2005 levels [26]. Similarly, the Canadian Association of Petroleum Producers (CAPP) reported that Canada produced 526,000 BOPD of heavy oil in 2005, down from 497,000 BOPD of heavy oil in 2004 [27]. North American oil sands production experience is concentrated in Alberta, Canada, where current production levels are 1.2 million BOPD in the form of bitumen [28]. Based on anticipated growth, production could increase to 3 million BOPD by 2020 [29]. Oil sands production in the United States is limited to two pilot-scale operations in Utah [30,31]. Oil shale is not produced on a commercial scale anywhere in North America. Despite the technical progress that has been made in oil shale processing since the last oil shale boom in the 1970s, oil shale commercialization faces major obstacles. !ose obstacles include the high initial capital investment, the possible instability of world crude oil prices, the lack of a clearly defined federal oil shale development policy, and environmental considerations [6,12,13]. Heavy oil production processes. !e production processes for these unconventional fuels are classified according to whether the oil-bearing material is processed on the surface (surface extraction and processing) or the oil is produced "in-place" (in situ). In the United States, heavy oil is produced in situ due to the depth of most deposits, primarily using steam injection technologies (steamflood/steamdrive). !ese tech-nologies involve the continuous injection of steam to displace oil toward production wells. !e NIPER/BDM report estimated that about 8 billion of the 68 billion barrels of California heavy oil could be recovered using steam injection technologies [32]. Profitability of a steam injection operation depends on the steam to oil ratio (SOR), the energy source used to generate the steam and the cost of that source. Natural gas is the predominant energy source in California steamfloods. Current high natural gas prices may be influencing the heavy oil production decline in California. Oil sands production processes. Oil sands in Alberta, Canada, are produced via surface extraction/processing or in situ, depending on the depth of the deposit. Currently, surface extraction/processing accounts for 60% and in situ processes account for 40% of the total production of 1.2 million BOPD in the form of bitumen [28]. In the Athabasca region in Alberta, mining has provided access to vast quantities of uniformly rich, unconsolidated oil sands deposits with little or no overburden. Commercial devel-opment of mining and extraction processes has been achieved through efficiencies of scale (i.e. very large mining and processing operations) and extensive research over the BOPD refers to barrels of oil per day. Pemex de!nes heavy oil as that with an API gravity of less than 27°. CAPP de!nes heavy oil as that with an API gravity of less than 28°. In a steam"ood/steamdrive process, steam is injected into the heavy oil reservoir through injection wells and oil, steam, gases and water are produced from a second set of wells, the production wells. Steam to oil ratio (SOR) is the amount of water equivalent barrels injected per barrel of oil produced. Process e#ciency improvements will decrease this number. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xviii past 30 years [33]. Surface extraction processes are solvent-based, with water being the most common solvent; other (mainly hydrocarbon) solvents have been reported, but are not yet commercial [34]. In situ technologies for oil sands production are modifica-tions of steam injection technologies for heavy oil reservoirs, of which the best known is steam-assisted gravity drainage (SAGD) [35]. !e contribution to Canadian oil production from in situ technologies is expected to grow and dominate the targeted 3 million BOPD of production in the next ten to fifteen years. Mining Utah oil sands will be more challenging than mining Canadian oil sands because the Utah deposits, while relatively shallow, are lenticular, are located in more rugged and mountainous terrain, and are geologically condensed. !e consolidated deposits will require milling-type mining equipment in contrast with the shovel-type equipment used in Canada. Nevertheless, Utah oil sands have two significant advantages over Canadian oil sands. One, the quantity of fines is lower and two, the percentage of sulfur in the bitumen is much lower. Differences between Canadian and Utah oil sands require the optimization of the Canadian hot water extraction process for Utah oil sands. In general, Utah oil sands have lower porosity, lower bitumen content, lower water content, higher consoli-dation, higher viscosity bitumen and fewer clay minerals than their Canadian counterpart. Optimal conditions for hot-water extraction have been determined from research specific to Utah oil sands [36]. Presently, pilot-scale and small commercial-scale activities involving mining and solvent extraction are being conducted by Temple Mountain Energy and Earth Energy Resources Inc. in some Utah deposits. While the solvents used in these processes have not been publicly disclosed, both companies claim very high bitumen recovery (99%+) and good solvent recovery. Based on what has been publicly stated, if the mining costs can be controlled, these processes should be economical [30,31]. If commercial development of Utah oil sands were to occur in the short term, it appears that solvent extraction would be the process of choice. As substantial portions of the Utah deposits are deep and not easily accessible, in situ processing should also be considered. !e stratified and lean nature nature of the Utah deposits implies that in situ processing will require considerably more energy than a comparable process in Canada as energy will be wasted in heating non-oil-bearing layers. One advantage of in situ methods in the arid western United States is reduced water consumption over surface extraction methods [37,38]. Oil shale production processes. Production processes for the thermal treatment of oil shale deposits fall into the same categories as oil sands production processes. With surface (ex situ) mining and processing, oil shale is mined, crushed, and then subjected to thermal processing at the surface in an oil shale retort. With in situ production, the shale is left in place and the retorting (e.g. heating) of the shale occurs in the ground. Higher efficiencies can be obtained with surface mining and processing, but the over-burden is so thick and the deposits so large in the western United States that the mines would be comparable to the largest open-pit mines in the world [6,22]. Oil shale can be produced through traditional mining methods, followed by crushing and retorting of the ore. During retorting, kerogen decomposes into three organic fractions: oil, gas and residual carbon. Oil shale decomposition begins at relatively low retort temperatures (572°F/300°C) but proceeds more rapidly and more completely at In lenticular deposits, the rich deposits are often interspersed with lean sands or shales. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xix higher temperatures with the highest decomposition rates occurring at retort tempera-tures of 896°-968°F (480°-520°C) [39]. Most conventional retorts are operated in or near this temperature range. !e shale oil produced from the retort is partially upgraded and is an appropriate feedstock for the existing U.S. oil refining infrastruc-ture, comparable to a light, sweet crude oil. Spent shale disposal and the environmental degradation that comes with mining the ore are two principal environmental concerns with oil shale development. A high yield deposit of oil shale will yield 25 gallons (0.60 barrels) of oil per ton (0.91 metric tons) of material. About 8 million tons (7.3 metric tons) of ore would need to be mined daily to meet one-quarter of the U.S. demand of 20 million BOPD, resulting in massive quantities of spent shale that would need to be reclaimed [6,22]. Nevertheless, the Canadian oil sands operations have demon-strated that the efficiency of mining operations improves at larger scales. Additionally, significant advances have been made in the fields of process design and control, simu-lation/ modeling, separation and purification, and environmental impact reduction. Pilot plants would need to be built to test the viability of this production method. In the early 1980s, Shell proposed a new method of in situ retorting, the In situ Conversion Process (ICP). ICP is comprised of a series of underground heaters drilled into an oil shale deposit on a one square mile (2.6 square kilometer) grid. Approximately 15 to 25 holes are drilled per acre in a variety of configurations, and electrical resistance heaters are inserted into the holes. !e target depth zone for the wells is 1000-2000 feet (305-610 meters), depending on deposit location. !e shale deposit is heated to temperatures of 650°-700°F (343°-371°C), which are much lower than surface retort temperatures, for 2-3 years in order to release the oil from the shale [40]. !e oil and any associated gas are then pumped out of the ground using conven-tional methods [6]. !e oil is of a very high quality and quite different from traditional crude oils in that it contains light hydrocarbons and almost no heavy ends. However, the energy costs of heating the oil shale are significant. With electrical heating, 2 units of energy are gained from the oil shale for every unit of energy consumed assuming the electricity is produced by a standard coal-fired power plant. If the power plant is a 60% efficient, combined cycle gas power plant, the energy balance is 3.5 to 1. Research on gas-fired heating, which will utilize the natural gas being recovered from the drilling process, may improve the energy balance to 5.5 to 1 [41]. Upgrading of unconventional fuel resources. Lower API crude oils such as heavy oil, oil sand bitumen, and shale oil from surface retorts produce lower quantities of conventional refinery products than light crude oils. As a result, the value of these oils is less than that of higher API crude oils. Upgrading is the process of converting these lower value oils to higher API oils more suitable for conventional refinery feedstocks. Partial upgrading reduces the heavy oil/bitumen viscosity and density, rendering it suitable for transportation to a refinery [42]. In contrast, the ICP process produces a refinery-ready shale oil that will not require partial upgrading prior to transportation to a refinery. !e most common international standard for upgrading is the conversion of the vacuum residue to lower boiling point fractions. Oil sands and oil shale development in the United States is most likely to occur in the Rocky Mountain region, where very limited refinery capacity exists for processing heavy oils/bitumen and refinery capacity utilization is high [43,44]. Partially or fully upgraded synthetic crude oil produced from oil sands and oil shale would need to be shipped to other regions of the country for refining. In addition, no partial upgrading A metric ton is 1000 kilograms. Vacuum residue is the cut which boils above 1000°F/538°C. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xx capacity exists in either Colorado's Piceance Basin or Utah's Uinta Basin, the probable epicenter for both oil sands and oil shale development. !e two ten-inch pipelines serving the basins could not be utilized unless partial upgrading were available in the field; additional pipeline capacity would then be needed to handle the volume of expected product. Canada already faces this situation, with potential production expected to be constrained by existing pipeline capacity within a decade [45]. !e choices for upgrading unconventional fuels in the Rocky Mountain region will depend on the quality of the oil produced, the refining market and pipelines available at the time, the energy sources (gas, coal, etc.) in the vicinity, the qualities of other crude oils being produced at the time, and how successfully current Canadian upgrading tech-nologies can be integrated into the U.S. refinery framework. Upgrading technologies are classified as primary, secondary or enhanced. Primary upgrading is mainly a molecular weight reduction process, while secondary upgrading involves removal of impurities from the feed. !e primary upgrading processes may or may not use a catalyst, while the secondary processes are catalytic. Emerging tech-nologies are classified as enhanced upgrading methods. !e mainstay of the oil sands upgrading operations in Canada has been coking. Hydrotreating is less common but has been used in upgrading conventional heavy oil (of the type produced in California). A sharp increase in the use of natural gas as a source of hydrogen and of energy in the upgrading process has led to the exploration of residue (atmospheric and vacuum) gasification as an alternative source [46]. Since shale oil is produced by thermal means, it is partially upgraded and may only require mild hydrotreatment depending on the shale. Bitumen produced from oil sands, via surface extraction methods or in situ processes, requires more extensive upgrading. Relevant economics of conventional petroleum market. Petroleum derived from heavy oil, oil sands and oil shale must achieve profitability in a worldwide commodity market with transparent pricing that is dominated by conventional crude oil. !e future of these sources of energy is strongly linked to the future price of crude oil. In constant dollars (with 2005 purchasing power), the price of crude oil peaked in the early 1980s at over $80 per barrel. Prices dropped precipitously in the latter half of the 1980s to $20-$30 per barrel, then dropped again in 1998 to $16 per barrel. Prices have since rebounded to $66 per barrel in 2007 [47]. Forecasts show a gradual decrease in the price of crude oil through 2015 as additional exploration and development brings new supplies to the world market [48]. After 2015, real prices (constant dollars with 2005 purchasing power) are forecast to increase due to rising worldwide demand and higher-cost supplies with the average real price of imported low-sulfur crude oil fore-cast to be over $59 per barrel by 2030. In addition, worldwide demand for crude oil is projected to grow from 80 million BOPD in 2003 to 118 million BOPD in 2030 [48]. Given this forecast for high crude oil prices and growth in demand, it is highly likely that profitable operating economics will lead to additional development of heavy oil, oil sands and oil shale resources in the United States. Heavy oil production economics. !e degree to which the economics of heavy oil, oil sands, and oil shale are understood is dependent on the extent of resource commer-cialization. Heavy oil is produced in large quantities in southern California, Canada, and Mexico, and the economics of this industry are well understood. Heavy oil must compete with lighter grades of crude oil. !e price of heavy crude from California During the coking process, heavy oil/bitumen is thermally decomposed in an oxygen-free environment to form the solid carbonaceous product, coke. Hydrotreating is an upgrading process used to remove nitrogen, sulfur, and heavy metals from petroleum feedstocks. Gasi!cation is a process in which a carbonaceous material (e.g. natural gas, liquid hydrocarbon, coal, or heavy oil residue) is reacted with steam to produce a mixture of carbon monoxide and hydrogen known as synthesis gas or syngas. This process is also called steam reforming. Constant dollars take into account in"ation so they have equal purchasing power. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xxi trades at a discount to West Texas Intermediate (WTI) crude, and the discount has recently widened. During 2003, California 13° API heavy crude oil traded at a $5.66 per barrel discount to WTI crude, a discount that widened to $12.34 per barrel in 2005 [49]. !is price discount is driven by the market for oil and is influenced by both worldwide demand and local factors such as pipeline and refinery capacity; it does not represent the higher capital and operating costs required for heavy oil recovery using steam injection nor the cost of the additional upgrading/refining. Heavy oil economics are largely driven by three factors: oil price, the price of energy to generate steam, and the amount of recoverable oil in place using steam injection tech-nology. !e critical parameter that determines the profitability of heavy oil production is the SOR. While engineering can aid in optimizing this ratio, geology establishes the baseline SOR and the ultimate success of a project. As natural gas is used to generate steam, production economics have also been complicated by the volatile price of natural gas in recent years. Each $1.00 fluctuation in the price changes operating costs by approximately $1.60 per barrel [50]. Past variations in the prices of both natural gas and crude oil have altered production at heavy oil operations in the United States [51]. Oil sands production economics. Oil sands production in Alberta provides a large body of economic data from which to glean insights into production economics. Significant capital has already been invested, and announced projects indicate additional spending in the future. From 1996 to 2004, the Alberta oil sands industry spent an estimated $25 billion on new projects with an additional $57 billion in spending planned for 2006-2011 [55]. While early production costs were estimated at C$35 per barrel, efficiency gains and increased economies of scale between the early 1980s and the late 1990s dropped the operating costs to less than C$13 per barrel for an integrated mining and upgrading operation. However, in recent years the cost of oil sand produc-tion has risen, primarily due to rising energy costs and to higher capital costs [53]. !e operating costs for bitumen are linked to the price of natural gas as natural gas is used for steam generation and bitumen upgrading. !e rule of thumb in the Canadian oil sands industry is that 1 MCF of natural gas is necessary to produce one barrel of bitumen [54]. !e present total cost of an integrated mining and upgrading operation is estimated at $32-$35 per barrel [54]. Upgrading is essential as the price of bitumen has averaged 51% of that of WTI crude in recent years [55]. Despite this plethora of data, the large U.S. oil sands deposits, located predominantly in Utah, have signifi-cantly different characteristics than those in Alberta and the economics of a Utah oil sands industry may be noticeably different than the Canadian experience. Oil shale production economics. Oil shale is the least understood of the three resources examined, as new technologies, still in the research and development phase, have the potential to drastically alter the economics of oil shale production. Despite a long history of activity in the oil shale industry, there is not a large body of industrial knowl-edge based on successful operations from which to draw, so published costs for oil shale production have ranged from $10-$95 per barrel [6,56]. !ese cost estimates are generated either by companies involved in developing oil shale resources using cost estimates based on engineering calculations or by analysts at various government agencies and think tanks. Actual operating costs, determined through pilot plants and West Texas Intermediate (WTI) refers to a crude stream produced in Texas and southern Oklahoma that serves as a reference or "marker" for pricing a number of other crude streams. The term C$ refers to Canadian dollars. In this report, a dollar sign ($) refers to U.S. dollars unless otherwise indicated. MCF refers to one thousand cubic feet. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xxii small demonstration units, will be needed before larger-scale commercial plants can be constructed. !is process can take several years. !e different technologies of mining followed by surface retorting and of in situ retorting have the possibility of drastically different economics [57]. By applying infla-tion factors to published costs for the Colony and Union projects of the 1970s and 1980s and other published design studies from the same era, the Rand Corporation estimated that a 50,000 BOPD mining and surface retorting plant would have capital costs of $5-$7 billion and operating expenses of $17-$23 per barrel. !e Rand Corporation also estimated that WTI Crude would have to be priced at $70-$95 per barrel for a first generation oil shale plant to be profitable [6]. In contrast, based on the experience of operating the Alberta-Taciuk Processor, a surface retorting technology, at a demonstration level in Australia, a full-sized plant incorporating 13 Alberta-Taciuk reactors to produce 157,000 BOPD of synthetic crude oil was projected to cost $3.5- $4.0 billion and have operating costs of $7.50-$8.00 per barrel [13]. !e economics of in situ oil shale production are based largely on information released by Shell Oil relative to their ICP technology. Shell has stated that their technology may be profitable at an oil price of $30 per barrel [6]. With current electric heater technology, the cost of heating equates to $12-$15 per barrel. A 100,000 BOPD operation would require 1.2 GW of dedicated electric generating capacity. Socioeconomics of unconventional fuel development. Increased development of unconventional fuels will have varying social and economic impacts. !e states most likely to experience rising production of these resources are all current producers of crude oil and natural gas. Jobs in these industries pay significantly better than the average job, and these pay differentials can be expected to continue with rising produc-tion [58]. Increased heavy oil production is likely to have minimal impacts for the producing areas. !e areas most likely to see increased production, including Kern County, California, a three-county area in southern California, and the North Slope Borough, Alaska, already have significant oil production, although production has been declining since the 1980s. Any increase in heavy oil production would offset this decline and maintain the petroleum industry in these areas. Development of oil sands and oil shale has a strong possibility of altering the econo-mies of the areas where these resources are located (i.e. Colorado and Utah). Oil sands and oil shale production growth will increase in-migration to the area, with resulting population and workforce growth. While additional jobs and economic growth are desirable, rapid in-migration tends to strain local resources and infrastructure such as housing, schools, utilities, sanitation and roads. Some of these impacts can be mitigated through planning and permitting, but development of a large-scale oil sands and/or oil shale industry will alter the economic and social structure of nearby communities. Unconventional fuel development under the Energy Policy Act of 2005. At present, oil shale and oil sands development are proceeding under specific timelines and mandates set by the Energy Policy Act of 2005 (EPAct). Although the EPAct encour-ages further development of all strategic unconventional fuels, heavy oil development beyond current production arenas and levels is not under active agency review. !e The Shell ICP process produces a re!nery-ready shale oil that will not require partial upgrading prior to transportation to a re!nery. A gigawatt (GW) is equal to one billion watts. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xxiii Bureau of Land Management (BLM) is in the process of preparing a Programmatic Environmental Impact Statement (PEIS) for a commercial leasing program for oil shale and oil sands on the public lands. !e PEIS is intended to satisfy threshold anal-ysis obligations under the National Environmental Policy Act (NEPA) and provide a basis for amending existing BLM management plans under the Federal Land Policy and Management Act (FLPMA) for those areas selected for commercial oil sands and oil shale development. (Should commercial oil sands or oils shale development proceed, NEPA and FLPMA compliance requirements will continue to attach to the BLM's individual commercial oil shale and oil sands leasing decisions and to subse-quent project development decisions.) Additionally the BLM has revised existing oil sands regulations and is currently drafting regulations for oil shale development. Six Research, Development and Demonstration (RD&D) leases on small test sites on the public lands have been issued by the BLM in order to test and refine oil shale technologies. Five of the RD&D lease sites are located in Colorado and involve in situ technologies. !e sixth RD&D lease site is located in Utah and involves a surface retort method. Following completion of the PEIS, the EPAct directs the Secretary of Interior to consult with the affected states prior to deciding whether to issue any federal oil sands or oil shale leases. If it is determined that commercial development of oil sands or oil shale should proceed on the public lands, several important environmental issues and land use questions will need to be addressed. Land and resource management issues. While oil shale and oil sands resources are predominantly located on federal land, these federal lands are interspersed with state and private lands. !us, construction of industrial infrastructure and management of attendant environmental impacts may require obtaining rights of way and access to nearby state, tribal or private lands. In many instances, federally protected sensitive lands (including wilderness, wilderness study areas, national parks and national monu-ments) are in proximity to or co-located with the oil sands and oil shale resources. Management practices and mitigation measures that comport with the statutory protections afforded these lands will need to be developed and implemented. Additionally, several animal and plant species protected under the Endangered Species Act reside in the areas of Colorado, Utah and Wyoming that are currently being evaluated as potential areas for unconventional fuel development by the BLM. !e Migratory Bird Treaty Act, the Bald Eagle Protection Act and state law protections are also likely to be relevant to the manner in which commercial development of uncon-ventional resources can proceed on the public lands. Air and water quality management. Adequate measures will need to be developed and implemented to insure that commercial oil sands and/or oil shale activities comply with applicable air and water quality standards for the areas selected for development. !e Clean Air Act, the Clean Water Act, the Safe Water Drinking Act, the Colorado River Basin Salinity Control Act, and applicable state laws all will be relevant to unconven-tional fuel resource development. Although emissions associated with climate change are not yet federally regulated, it should be expected that such a regulatory scheme will be finalized and relevant to future commercial oil sands and oils shale development. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xxiv Water consumption. Water consumption also will be an issue in the context of uncon-ventional fuel development. Due to shifting and increased population demands, as well as recent dry weather conditions and dropping reservoir levels, it is unclear whether the Colorado River can continue to meet the anticipated water needs of the Colorado River Basin States and of Mexico, even without adding the consumptive water demands of unconventional fuel development. Moreover, within Colorado, Utah and Wyoming, most of the surface waters have been allocated under prevailing state law water regimes. Policy questions. Commercial development of oil sands and/or oil shale on the public lands will raise several energy and resource management policy issues. In particular: (1) the balance between preserving existing landscapes and developing unconven-tional energy resources on the public lands; (2) the carbon emissions issues attendant to developing unconventional fuel resources; (3) the "energy in, energy out" calculus of developing unconventional fuel resources; and (4) the policy issues associated with developing these resources through highly water-consumptive technologies in the arid West. References [1] Energy Information Administration (EIA) Reports. Strong Growth in World Energy Demand is Projected !rough 2030. http://www.eia.doe.gov/neic/press/press271. html (accessed February 27, 2007). Press Release on June 20, 2006. [2] International Energy Agency. World Energy Outlook 2005: Middle East and North Africa Insights. SourceOECD Energy 2005, 2005(26), pp i-631. Also available at http://www.iea.org/textbase/nppdf/free/2005/weo2005.pdf. [3] Dammer, A.R. Strategic Significance of America's Oil Shale Resource. 2005 EIA Midterm Energy Outlook Conference, U.S. Department of Energy, Washington, D.C., April 12, 2005. Also available at http://www.eia.doe.gov/oiaf/archive/aeo05/ conf/pdf/dammer.pdf. [4] Alberta Energy and Utilities Board. Oil Reserves and Production: Alberta; Alberta Energy and Utilities Board: Calgary, Alberta, 2006. Also available at http://www. energy.gov.ab.ca/docs/oilsands/pdfs/PUB_osgenbrf2004.pdf. [5] Dyni, J.R. Geology and Resources of Some World Oil-Shale Deposits. Oil Shale 2003, 20(3), pp 193-252. Also available at http://www.krij.ee/oilshale/vol_20_3.html. [6] Bartis, J.T.; LaTourrette, T.; Dixon, L.; Peterson, D.J.; Cecchine, G. Oil Shale Development in the United States; MG-414-NETL; RAND Corporation: Santa Monica, CA, 2005. [7] Centre for Energy - Oil & Natural Gas. What are Oil Sands and Heavy Oil? http:// www.centreforenergy.com/silos/ong/ET-ONG.asp (accessed February 28, 2007). [8] Naslund, H.R. Geology 111 - Energy Resources. http://www.geol.binghamton. edu/faculty/naslund/Geol.111.lect33a.html (accessed August 2, 2007). University of Oregon. [9] http://en.wikipedia.org/wiki/Heavy_crude_oil#Origin [10] http://en.wikipedia.org/wiki/Tar_sands [11] Cornelius, C.D. Classification of Natural Bitumen: A Physical and Chemical Approach. In Exploration for Heavy Crude Oil and Natural Bitumen, Meyer, R.F., Ed.; Studies in Geology, Vol. 25; AAPG: Tulsa, OK, 1987; pp 165-174. [12] Johnson, H.R.; Crawford, P.M.; Bunger, J.W. Strategic Significance of America's Oil Shale Resource: Volume I, Assessment of Strategic Issues; AOC Petroleum Support Services, LLC: Washington, D.C., March 2004. [13] Johnson, H.R.; Crawford, P.M.; Bunger, J.W. Strategic Significance of America's Oil Shale Resource: Volume II, Oil Shale Resources, Technology and Economics; AOC Petroleum Support Services, LLC: Washington, D.C., March 2004. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xxv [14] Buschkuehle, B.E.; Grobe, M. Geology of the Upper Devonian Grosmont Carbonate Bitumen Deposit, Northern Alberta, Canada. In American Association of Petroleum Geologists Annual Meeting, Dallas, TX, 2004; AAPG: Dallas, TX, 2004. Also available at http://www.ags.gov.ab.ca/activities/conference_presentations.html. [15] Advanced Resources International. Undeveloped Domestic Oil Resources: !e Foundation for Increasing Oil Production and a Viable Domestic Oil Industry; U.S. Department of Energy, 2006. Also available at http://fossil.energy.gov/programs/ oilgas/eor/Undeveloped_Domestic_Oil_Resources_Provi.html. [16] Bidinger, C.R.; Dillon, J.F. Milne Point Schrader Bluff: Finding the Keys to Two Billion Barrels. SPE International Heavy Oil Symposium, June 19-21, 2005, Calgary, Alberta; Society of Petroleum Engineers: Richardson, TX, 1995; SPE 30289. [17] National Energy Technology Laboratory. U.S. Heavy Oil Database. http://www.netl. doe.gov/technologies/oil-gas/Software/database.html (accessed February 27, 2007). [18] Pemex. Las Reservas de Hidrocarburos de México: Evaluación al 1 de enero de 2006; Pemex Exploración y Producción, 2006. [19] Reid, T.B.; Mikels, R. U.S. Tar Sands Deposits; Department of Energy, Office of Fossil Energy, 1993. Also available at http://www.oildrop.org/lib.html. [20] Oblad, A.G.; Bunger, J.W.; Hanson, F.V.; Miller, J.D.; Ritzma, H.R.; Seader, J.D. Tar Sand Research and Development at the University of Utah. Annual Review of Energy 1987, 12, pp 283-356. [21] Ritzma, H.R. Oil-impregnated Rock Deposits of Utah; Map 47; Utah Geological and Mineralogical Survey, 1979. Also available at http://geology.utah.gov/online/ m/m-47.pdf. [22] U.S. Office of Technology Assessment. An Assessment of Oil Shale Technologies, Volume I; PB80-210115; Congress of the United States: Washington, D.C., 1980. [23] Macauley, G. Geology of the Oil Shale Deposits of Canada; Open-File Report 754; Geological Survey of Canada, 1981. Also available at http://ess.nrcan. gc.ca/esic/index_e.php. [24] California Department of Conservation; Division of Oil, Gas & Geothermal Resources. Monthly Production and Injection Databases. http://www.conservation. ca.gov/DOG/prod_injection_db/index.htm (accessed October 1, 2006). [25] Advanced Resources International. Undeveloped Domestic Oil Resources: !e Foundation for Increasing Oil Production and a Viable Domestic Oil Industry; U.S. Department of Energy, 2006. Also available at http://fossil.energy.gov/programs/ oilgas/eor/Undeveloped_Domestic_Oil_Resources_Provi.html. [26] Pemex. Pemex 2006 Annual Report, Pemex Corporate Finance Office: C. P. 11311 México. Exploration and Production. Also available at http://www.pemex.com/ index.cfm?action=content§ionID=11&catid=149&contentID=2711. [27] Canadian Association of Petroleum Producers (CAPP). Canadian Crude Oil Production and Supply Forecast, 2006-2020, CAPP: Calgary, Alberta, May 2006. Also available at http://www.capp.ca/raw.asp?x=1&dt=NTV&e=PDF&dn=103586. [28] Alberta Energy and Utilities Board Staff. Alberta's Energy Reserves 2006 and Supply/ Demand Outlook 2007-2015; ST98-2007; Alberta Energy and Utilities Board: Calgary, Alberta, June 2007. [29] Oil Sands. http://www.energy.gov.ab.ca/89.asp (accessed June 18, 2007). Govern-ment of Alberta; Energy. [30] Temple Mountain Energy, Inc. U.S. Oil Sands Production Project. http://www.templemountainenergy.com/ (accessed September 7, 2007). [31] Earth Energy Resources Inc. http://www.earthenergyresources.com/index.php (accessed September 7, 2007). [32] Strycker, A.R.; Wadkins, R.; Olsen, D.K.; Sarkar, A.K.; Ramzel, E.B.; Johnson, W.I.; Pautz, J. Feasibility Study of Heavy Oil Recovery in the United States; NIPER/BDM- 0225; BDM-Oklahoma, Inc.: Bartlesville, OK, March 1996. [33] Masliyah, J.; Zhou, Z.J.; Xu, Z.; Czarnecki, J.; Hamza, H. Understanding Water- Based Bitumen Extraction from Athabasca Oil Sands. Canadian Journal of Chemical Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xxvi Engineering 2004, 82, pp 628-654. [34] Ophus, K. Removal of Hydrocarbons from Particulate Solids. International Patent Application number: PCT/CA2004/001826, April 20, 2004. [35] Sandler, K. and Davis, P. In Situ Bitumen Overview and Activity Update in the Province of Alberta. SPE/PS-CIM/CHOA International !ermal Operations and Heavy Oil Symposium, November 1-3, 2005, Calgary, Alberta; Society of Petroleum Engineers: Dallas, TX, 2005; SPE 97800. [36] McLendon, T.R.; Bartke, T.C. Tar Sand, Technology Status Report; DOE/METC- 91/0274 (DE91002070); Office of Fossil Energy, U.S. Department of Energy: Morgantown, WV, 1990. [37] Flint, L. Bitumen Recovery Technology: A Review of Long Term R&D Opportunities; LENEF Consulting Limited, 2005. [38] Gray, M. Research Challenges for Sustainable Oil Sands Production. Research presentation to the Utah Heavy Oil Program, University of Utah, March 15, 2007. [39] Koel, M. Estonian Oil Shale. www.kirj.ee/oilshale/Est-OS.htm (accessed June 18, 2007). Oil Shale, A Scientific-Technical Journal, Oil Shale Extra. [40] Shell Oil Company. Welcome to the Mahogany Research Project. http://www. shell.com/home/Framework?siteId=us-en&FC2=/us-en/html/iwgen/leftnavs/ zzz_lhn4_4_0.html&FC3=/us-en/html/iwgen/shell_for_businesses/exploration_produc-tion_ shared/mahogany_shared/dir_mahogany.html (accessed October 1, 2006). [41] Vinegar, H.J. Shell Oil Company. Personnal communication, July 2006. [42] Heidrick, T.; Bilodeau, V.; Godin, M. Oil Sands Research Inventory; Alberta Energy Research Institute: Edmonton, Alberta, March 2004. Also available at http://www. aeri.ab.ca/sec/new_res/docs/Oil_Sands_Public_Research_27Apr07.pdf. [43] Energy Information Administration. Refinery Capacity Report 2007; Department of Energy: Washington, D.C., June 2007. Also available at http://www.eia.doe.gov/ oil_gas/petroleum/data_publications/refinery_capacity_data/refcapacity.html. [44] Energy Information Administration. Refinery Capacity and Utilization. http:// tonto.eia.doe.gov/dnav/pet/pet_pnp_top.asp (accessed December 13, 2006). [45] Gossen, S.; Partial Upgrading of Heavy Oil and Bitumen: Strategic Value in Western Canada, Canadian Heavy Oil Association, Calgary, Alberta, May 8, 2002. Also avail-able at http://www.ensyn.com/info/08052002.htm. [46] Speight, J.G.; Özüm, B. Petroleum Refining Process, Marcel Dekker, Inc: New York, 2002. [47] Energy Information Administration. Annual Energy Outlook 2007 with Projections to 2030; DOE/EIA-0383(2007); U.S. Department of Energy: Washington, D.C., February 2007. Also available at http://www.eia.doe.gov/oiaf/aeo/index.html. [48] Energy Information Administration. International Energy Outlook 2007; DOE/EIA- 0484(2006); U.S. Department of Energy: Washington, D.C., May 2007. Also available at http://www.eia.doe.gov/oiaf/ieo/index.html. [49] Berry Petroleum. 2005 Form 10-K. http://www.bry.com/index.php?page=investor (accessed January 20, 2007). [50] Berry Petroleum. 2006 Form 10-K. http://www.bry.com/index.php?page=investor (accessed May 7, 2007). [51] Guntis, M. California Steam Produces Less: Other EOR Continues. Oil & Gas Journal 2002, 100(15), pp 48-74. [52] Athabasca Regional Issues Working Group; Regional Municipality of Wood Buffalo; Fort McMurray Public Schools; Fort McMurray Catholic Board of Education; Northland School Division; Keyano College; Northern Lights Health Region. Wood Buffalo Business Case 2005: A Business Case for Government Investment in the Wood Buffalo Region's Infrastructure; Athabasca Regional Issues Working Group, March 2005. Also available at http://www.oilsands.cc/pdfs/Wood%20Buffalo%20Busines s%20Case%202005.pdf. [53] National Energy Board - Canada. Canada's Oil Sands: Opportunities and Challenges to 2015: An Update; National Energy Board - Canada, May 2004. Also Utah Heavy Oil Program Unconventional Oils Research Report September 2007 xxvii available at http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/lsnd/pprtntsnd-chllngs20152004/ pprtntsndchllngs20152004-eng.pdf. [54] National Energy Board - Canada. Canada's Oil Sands: Opportunities and Challenges to 2015: An Update; National Energy Board - Canada, June 2006. Also available at http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/lsnd/pprtntsnd-chllngs20152006/ pprtntsndchllngs20152006-eng.pdf. [55] Canadian Association of Petroleum Producers. Bitumen Pricing Methodology for SEC Reserves Disclosure; Canadian Association of Petroleum Producers, September 2005. Also available at http://capp.ca/raw.asp?x=1&dt=NTV&e=PDF&dn=91581. [56] Bauman, J. Vernal Company Set to Exploit Oil Shale. Deseret Morning News. March 14, 2005. [57] Isaacson, Alan E. Western Oil Shale: Past, Present and Future. Utah Economic and Business Review 2006, 66, pp 1-11. [58] Bureau of Labor Statistics. Quarterly Census of Employment and Wages. http:// stats.bls.gov/cew/home.htm (accessed November 10, 2006). 1I ntroduction Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.1 1 Introduction Due to the current political climate in many oil-producing nations and the significant increases in global energy demand, United States energy policy proposals are once again focused on North American unconventional hydrocarbon resources for their potential to reduce future energy crises. !e purpose of this report is to assess uncon-ventional North American resources, summarize current technologies for extracting and processing the resources, identify the issues which will affect the economic viability of various resource development schemes, evaluate the socioeconomic costs to communities and states impacted by such development, and analyze the regulatory and environmental climate in which the resource development will operate. 1.1 Energy and Global Economic Development In 2007, there are 6.6 billion people in the world, with 98% of the world's popula-tion growth in developing countries [1]. A tremendous rate of development, sparked largely by rapid economic expansion in India and China, has enormous implications for worldwide energy consumption. Figure 1-1 shows projected growth in energy consump-tion worldwide from 2004 to 2030 [2]. !e strongest growth is in developing countries outside the Organisation for Economic Co-operation and Development (OECD) and is led by non-OECD Asia. Economic development and the rate of economic expansion are driven in a large part by the availability of energy. For the foreseeable future, the largest energy source will be petroleum as illustrated in Figure 1-2 [3]. !us, the world economy and its state of economic development are significantly impacted by the cost of oil. Figure 1-1. World marketed energy consumption by region. Source: International Energy Outlook 2007, Energy Information Administration Figure 1-2. Total world primary energy consumption (% by fuel). QuickTime™ and a decompressor are needed to see this picture. QuickTime™ and a decompressor are needed to see this picture. Source: World Energy Outlook 2005, Energy Information Administration Marketed energy sources include electricity, propane, and gasoline. Non-marketed energy sources include wood and waste used for heating and cooking [2]. Non-OECD Asia includes China and India. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.2 Compared to the rest of the world, the United States is more dependent on oil than on other energy sources. Figure 1-3 shows the historical and projected domestic energy consumption by fuel in quadrillion British !ermal Units (BTUs) between 1980 and 2030 [4]. In 2003, oil represented approximately 45% of domestic energy consump-tion compared to 35% of the world energy consumption. While oil as a percentage of worldwide energy consumption is projected to remain relatively constant through 2030, domestic oil consumption will continue to surpass 40% of total domestic energy consumption. !is projected energy consumption indicates that the United States will be dependent on oil for its energy future through the first third of this century if not longer. Figure 1-3. Historical and projected domestic energy consumption by fuel in quadrillion BTUs. Source: Annual Energy Outlook 2007, Energy Information Administration 1.2 North American Unconventional Oil Resources An unconventional fuel is one that is "not recoverable in its natural state through a well by ordinary production methods" [5] or that cannot be pumped without being heated or diluted. !e unconventional fuels assessed in this report are classified as heavy oil/ extra heavy oil, bitumen from oil sands, and oil shale. Conventional and unconven-tional fuels originated as organic material that was transformed through geologic time to its present form. More than 60% of the world's petroleum resources occur in rocks older than 2 million year and younger then 65 million years. !is time period repre-sents a balance between the minimum amount of time required to form oil and gas and the maximum time where rocks have not yet eroded away or been heated to high temperatures [6]. To form conventional and unconventional fuels, organic material was buried in fine grained sediments in an oxygen poor environment. !is buried material was first converted to kerogen through diagenesis at shallow depths and temperatures below 122°F (50°C). Hence, kerogen is an immature form of organic material and a precursor to oil. !is kerogen was further converted to oil at depths of 1.2-2.4 miles (2-4 kilometers) and temperatures of 122°-212°F (50°-100°C). At great depths (2.4- 4.3 miles or 4-7 kilometers) and higher temperatures (212°-392° F/100°-200° C), the oil was converted to natural gases including propane and butane. Methane formed from the conversion of complex natural gases at even greater depths (more than 4.3 Diagenesis is a biological, chemical, or physical change that a sediment undergoes at low temperatures and pressures. Change at high temperatures and pressures is called metamor-phism [7]. Quadrillion BTU Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.3 miles or 7 kilometers) and at temperatures that exceeded 392°F (200°C) [6]. Heavy and extra heavy crude oil are a biodegraded form of oil that occur when lighter oil frac-tions are lost or are consumed by bacteria in the reservoir, leaving the heavier molecules behind [8]. Oil sands are an extremely heavy form of crude oil [9]. Heavy oil, extra heavy oil, and bitumen from oil sands, all organic liquids, are classified by their American Petroleum Institute (API) gravity and viscosity (see Section 3). !e API gravity scale, graduated in degrees, was designed so that most hydrocarbon liquids would be in the range from 10 to 70 degrees. Light crude oil has an API gravity that exceeds 31.1° and medium oil has an API gravity between 31.1° and 22.3° [5]. Heavy oil has an API gravity of 10°-22.3° and viscosity of 100-10,000 cP at 60°F (15.6°C); extra heavy oil has an API gravity below 10° and viscosity of 100-10,000 cP at 60°F (15.6°C); and bitumen has viscosity above 10,000 cP at 60°F (15.6°C) [10]. Oil shale has a distinct classification from heavy oil and bitumen. As noted above, it is a fine-grained sedimentary rock rich in kerogen where the inorganic and organic matter are inextricably combined. All known processes for disengaging the kerogen from the inorganic matrix and for converting the kerogen to oil require heat input (see Section 4.3). Upon heating of the source rock, kerogen can produce crude oil, natural gas, and/or graphite [12,13]. How large is the North American unconventional oil resource? Figure 1-4 puts the size of the resource in perspective relative to proven and unproven conventional oil reserves [14]. A conservative estimate of the total world in-place oil shale resources are approxi-mately 2.9 trillion barrels [15]. If half this resource could be exploited, it would surpass the total proven conventional oil reserves. !e 2.0 trillion barrels of proven oil shale resources in the United States constitute the bulk of the oil shale resource worldwide in both quantity and quality. !e Rand report [16] puts the range of recovery at 500 billion to 1.1 trillion barrels depending on the percent recoverable and accessible. However, even the conservative estimate translates into a 270-year supply if shale oil were to provide one-quarter of the United States petroleum demand of 20 million barrels a day. Figure 1-4. Size of world conventional oil reserves compared to U.S. oil shale and Canadian oil (tar) sands reserves. Source: A. R. Dammer, Strategic Signi!cance of America's Oil Shale Resource, 2005 The de!nition presented here for heavy oil, extra heavy oil, and bitumen is from the United Nations Institute for Training and Research/United Nations Development Programme Information Centre for Heavy Crude and Tar Sands (UNITAR) [10]. Although the Department of Energy (DOE) uses the World Petroleum Congress de!nition for heavy oil [11], most published information for the United States and Canada is based on the UNITAR de!nition. Mexico uses a de!nition for heavy oil based on an API gravity of 27° or below. Centipoise (cP) is one hundreth of a poise, a unit of viscosity in the centimeter-gram-second unit system. The terms oil sands and tar sands are synonymous Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.4 1.3 Unconventional Oil Resources and the Global Petroleum Market Ultimately, economic issues will control the development of North American uncon-ventional oil resources. Historically, the global liquid fuels market has been controlled by a relatively few oil producers. Unconventional fuel resource development may present an opportunity for the United States to achieve greater oil and energy inde-pendence than it currently enjoys. !e cost of oil dependence to the U.S. economy has been significant. Figure 1-5 [17] shows the breakdown of those costs assuming a competitive oil price of $13 per barrel [18] and then computing costs based on the actual price of the oil. !ese costs include the transfer of wealth from oil consumers to oil producers, a Gross Domestic Product (GDP) loss because of the economy's diminished ability to produce due to the scarcity of energy, and a GDP "macroeco-nomic adjustment" because of losses of output in the economy due to inflation and unemployment [17]. Figure 1-5. Costs of oil dependence to the U.S. economy from 1970-2006 assuming a constant competitive world oil price of $13 per barrel. QuickTime™ and a decompressor are needed to see this picture. Source: D. L. Greene, et al., Oil Independence: Achievable National Goal or Empty Slogan?, Transportation Research Board Annual Meeting 2007 As oil impacts primarily the transportation sector of the U.S. economy, increasing engine efficiency, increasing the use of alternate transportation fuel sources, improving technologies for producing conventional oil, and producing petroleum from uncon-ventional sources will all play a role in achieving greater oil independence. With the exception of heavy oil production using steam injection, petroleum production from unconventional sources is not a mature field. Hence, significant investment would be required in all aspects affecting unconventional oil utilization if it were to proceed on a commercially significant scale and thereby make a greater contribution to global or national energy security. 1.4 Heavy Oil North American heavy oil/extra heavy oil resources occur in the United States, Canada and Mexico (see Section 3.1). !e three largest North American deposits are the Lloydminster The competitive oil price refers to the price that oil would have been if world oil markets had been competitive. Most esti-mates put the competitive price below $13 per barrel [18]. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.5 deposits in western Canada containing 101.7 billion barrels original oil in place (OOIP) [19], a series of deposits in California with 75.9 billion barrels OOIP, and the deposits in the Schrader Bluff/West Sak/Ugnu area on the North Slope of Alaska with 25 to 30 [20,21] billion barrels OOIP. !e remaining heavy oil resources in North America are distributed in deposits listed in the U.S. Heavy Oil Database [22] (153 deposits greater than 50 million barrels OOIP) and in heavy oil deposits in Mexico [23]. !e total remaining oil in place in the United States, exclusive of Alaska, is estimated at 73.4 billion barrels with 91% of this resource total in the state of California (see Table 3-1) [24]. Mexico has a series of fields containing medium and heavy oil. !e total estimated heavy oil resource in these fields is approximately 19 billion barrels OOIP or 57% of the total remaining proved, probable and possible oil in place in Mexico (see Table 3-2) [23]. A key feature of Mexican heavy oil deposits is that viscosities are low enough that the oils are produced using conventional methods. Most heavy oils are produced using steam injection technologies (see Section 4.1). 1.5 Oil Sands !e presence of 1.7 trillion barrels of oil in the form of bitumen in western Canada has led to the development of a large oil sands industry in Canada. Of these total reserves, 174 billion barrels are proven reserves that can be recovered using current technology with an estimated 315 billion barrels recoverable with technology improvements [25]. Canadian production of synthetic crude oil and bitumen from oil sand deposits currently stands at about 1.2 million BOPD. Very large resource development proj-ects are underway, with production projections of 3 million BOPD by 2015 [26]. !e largest oil sand deposits in the United States are found in the state of Utah with proven reserves of about 8-12 billion barrels OOIP [27-30]. Significant oil sands deposits are also found in California and Texas, but data relating to these deposits is very sparse as they are associated with the heavy oil in their respective areas. Alabama is estimated to have 1.8 billion barrels of measured and 4.6 billion barrels of speculative oil sand resource. Similarly, western Kentucky is estimated to have 1.7 billion barrels of measured and 1.7 billion barrels of speculative oil sand resource [31]. 1.6 Oil Shale !e majority of the oil shale deposits in the United States lie in the Green River Formation of Colorado, Utah, and Wyoming. !is formation alone may contain as much as 1.8 trillion barrels of oil and is one of the highest quality shales in the world. !e widely studied Piceance formation in Colorado contains deposits more than 500 feet (152 meters) thick that are located beneath 500 feet (152 meters) of sedimentary rock. However, some portions lie in regions of up to 2,000 feet (610 meters) of over-burden. Most of this formation yields more than 25 gallons per ton of raw material, which translates into nearly 2.5 million barrels per acre [14]. !e technology to remove oil shale with high enough efficiency to yield high returns has yet to be fully explored, and some deposits lie in regions where shale oil will be difficult or impossible to recover, such as those beneath towns and those where there are ecological or environmental concerns. 1.7 Upstream Processing Unconventional oil deposits require upstream and downstream processing. Upstream OOIP refers to oil prior to any production. Remaining oil in place takes into account cumulative production. BOPD refers to barrels of oil per day. One barrel of oil contains 42 gallons. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.6 processing refers to the extraction/production of the oil from the deposit. !is oil is typically extremely viscous and is composed of very high molecular weight compounds. Downstream processing, including upgrading and refining, produces marketable petroleum products. Heavy oil has been produced in the United States for over 80 years [32]. Steam injec-tion remains the most prominent production process for "conventional" heavy oil. Over the last ten years, advances in sensing and monitoring methods for steam injec-tion have meant that California heavy oil recovery projects are profitable in the oil price range of $30-$35 (see Section 6.1). Nevertheless, project profitability is directly impacted by the energy source used for steam generation and by the cost of that source. In California heavy oil production, natural gas is the primary energy source [33]. As heavy oil production in California continues to decline, high natural gas prices may be contributing to that decline. !e decline may not be arrested unless some large projects are initiated. With oil sands production, asphalt-like bitumen must be extracted from the oil sands, a mixture of sand, water, clay, and bitumen. In Canada, mining followed by surface extraction is the technique of choice for the production of bitumen from shallow oil sands deposits. Over the last 30 years, the most common extraction method, which uses hot water, has been optimized with appropriate additives and solvents [34,35]. Water usage, residual oil on the discarded sand, and the need for large tailings ponds are some of the drawbacks of this technology. Nevertheless, about 60% of the oil produced from oil sands in Canada utilizes this technique. An in situ process that employs steam injection, Steam Assisted Gravity Drainage (SAGD), accounts for nearly all of the rest of production [36]. Canadian oil sands production is and will continue to be affected by natural gas avail-ability and price; natural gas provides process heat for bitumen recovery and extraction and is used to generate steam for SAGD. An integrated mining/surface extraction process requires 700 cubic feet (20 cubic meters) of natural gas to produce one barrel of bitumen while an in situ process such as SAGD requires 1,200 cubic feet (34 cubic meters) per barrel [26]. High natural gas prices in North America are a reflection of the inability of natural gas production to keep pace with demand. In Canada, despite record drilling, natural gas production has declined or been flat for the past several years, and reserve additions have approximately equaled or have been lower than production, indicating flat supply in the future [37]. Application of either surface mining or in situ processing for oil production from U.S. oil sands will be challenging. Large volumes of accessible deposits are not available in U.S. reservoirs. Hence, it will probably be necessary to operate small (1000 - 5,000 BOPD) plants at multiple locations. For a mining and surface extraction operation, special mining methods will be required to mine and crush the consolidated rock that forms much of these oil sand deposits. Special additives may be necessary to get good recovery efficiencies from a surface hot-water extraction process [38]. Solvent extrac-tion technologies may prove useful under the constraints imposed by U.S. resources, however, the use of certain solvents may be limited due to environmental concerns [39]. Application of in situ technologies requires further evaluation due to consoli-dated nature of some of the sands and the vertical heterogeneity of the resource. Two companies have announced pilot scale/demonstration scale projects using solvent extraction technologies for oil recovery from Utah oil sands, although technical project details have not been made public. It is possible that very thick, deeper shale deposits would be good candidates for in situ opera-tions while shallower thinner beds could be produced using surface retorts. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.7 In contrast to oil sands, enourmous quantities of oil shale that would support large-scale production operations are found in Utah and Colorado. Some form of thermal treatment (either on the surface or in situ) is required to produce oil from oil shale. Several on-surface retorting technologies have been reported and are ready for use [40- 42]. If mining and subsequent reclamation aspects are addressed, these on-surface retorting facilities would be feasible. Oil from these operations is partially upgraded and mild hydrotreatment may be adequate to make the oil refinery-ready. !e feasi-bility of an in situ heating method to produce oil from shale has been confirmed by Shell for their In situ Conversion Process (ICP) in documents made public thus far [43,44]. Some of the major mining and reclamation considerations are avoided by using the in situ option but, in general, more energy is required to produce a barrel of oil by this method than by a surface processing technique. Also, it is not yet clear the role that geologic complexities will play in the process. 1.8 Downstream Processing and Markets Finding markets for heavy oils produced from oil sands or oil shale will be challenging. !e North American bitumen market is immature and illiquid with no posted prices for bitumen. In the past few years, the price of bitumen has averaged 51% of West Texas Intermediate crude [45]. As recently as 2003, shale oil was not competitive with petroleum, natural gas, or coal on the world market. Nevertheless, it is still used in several countries like Estonia that possess easily exploitable deposits of oil shale but lack other fossil fuel resources [46]. Heavy oils from oils sands and oil shale must be upgraded to a synthetic crude oil to be acceptable at many refineries that can only process light crude oils. Upgrading reduces the oil viscosity, increases the hydrogen to carbon ratio (H/C), reduces the molecular weight, and may significantly reduce or remove impurities that are problematic for most refineries. Since upgrading constitutes 90% of the downstream processing [47], a central facility that provides both upgrading and refining capacity could be economi-cally viable depending on the location, the quality of the oil produced, the refining market at the time, available pipelines, energy sources (gas, coal, etc.) in the vicinity, the qualities of other crude oils being produced at the time, and a number of other factors. Partial upgrading renders the heavy oil/bitumen suitable for transportation via pipeline to a refinery for further downstream processing by reducing its viscosity and density [48]. 1.9 Economic Issues !e economics of heavy oil production in California and bitumen/heavy oil produc-tion from Canadian oil sands are well known for existing technologies. In contrast, there is presently no commercial scale production of oil from oil shale, so cost estimates for converting oil shale to useable products vary widely and are associated with a high level of uncertainty. In all three cases, a disruptive technology could change the entire economic picture. Any U.S. unconventional fuel development will require a refining and transportation infrastructure that does not currently exist to bring refined products to market. Due to the location of the resources, most oil shale and oil sands development will occur in the Rocky Mountain states, where refineries are running at the highest capacity utiliza-tion in the country [49]. Hence, synthetic crude oil produced in the area will need to be transported to other regions for refining. !e picture for heavy oil is similar with Shale oil contains alkenes (also called ole!ns), which are unstable and unsaturated hydrocarbons containing at least one C=C (carbon-carbon double bond). Hydrotreatment stabilizes the shale oil by adding hydrogen to unsaturated bonds and removing sulfur, nitrogen, oxygen, and trace metals from larger organic chains. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.8 refineries on the West Coast, the center for heavy oil production in the United States, running at high capacity utilization [49]. Two pipelines serve the area at the epicenter of oil sands and oil shale development, Colorado's Piceance Basin and Utah's Uinta Basin, but the rise in production of conventional fuel in the same area will require construction of additional pipeline capacity. 1.10 Legal and Environmental Issues A wide range of potential land use issues and environmental resource impacts frame the subject of unconventional oil development. Land ownership controls what laws are applicable, what uses are allowed and what mitigation measures are required. !e majority of the land in question is federally owned, but some lands also belong to states, Native American tribes, and private property owners. !e Mineral Leasing Act and the Combined Hydrocarbon Leasing Act, as amended by the Energy Policy Act of 2005, the National Environmental Policy Act, the Federal Land Management and Planning Act, the Endangered Species Act, the Clean Air Act, and the Clean Water Act, among others, will regulate the type of development that can and will occur. In the arid western United States, where the majority of domestic heavy oil, oil sands, and oil shale resources are located, the potential allocation of water for unconventional fuel development is expected to present significant policy questions. Water availability has been recognized as a potential limiting factor in the long term development of these industries. Surface mining and in situ production methods for oil sands both have a significant impact on fresh water resources. !ese include ground and surface withdrawal, waste from water treatment and long term tailings ponds management. Surface mining requires 2-4.5 barrels of fresh water for each barrel of bitumen produced [50]. !e predominant method of in situ production, SAGD, requires approximately 3 water equivalent barrels of steam injected to produce one barrel of bitumen although process water recycling reduces water consumption to as low as 0.2 units per unit of bitumen produced [51]. Estimates for water usage associated with oil shale production from mining and surface retorting vary from 2.1-5.2 barrels of water per barrel of oil produced [16]. 1.11 Summary !e issues surrounding the development of unconventional fuels in North America are shaped by the fields of engineering, geology, science, business, economics, law, and public policy. As this report is an update to the 1988 report, A Technical and Economic Assessment of Domestic Heavy Oil: Final Report [32], it cannot address all these fields in exhaustive detail. As a result, the Utah Heavy Oil Program (UHOP) of the Institute for Clean and Secure Energy at the University of Utah has created a digital repository of information relevant to North American heavy oil, oil sands and oil shale resources. !e repository can be accessed via a text-based interface (http:// www.heavyoil.utah.edu) or through a map server interface (http://map.heavyoil.utah. edu/website/uhop_ims). Information about the map server interface, which allows users to explore the UHOP repository in a geospatial setting, is found in Section 2 of this report. Ultimately, unconventional oil resource development will be driven by economics and policy. Policy-wise, the strategic need for domestic oil resources could trump all other barriers and roadblocks. It is an exciting and challenging picture that will be explored in this report. In Canada, the e"ect of water withdrawal from the Athabasca River for oil sands production and its consequent impact on the Peace-Athabasca Delta, the largest boreal delta in the world, has been listed by the Environment Canada as one of the threats to the integrity of the delta [52]. Utah Heavy Oil Program Unconventional Oils Research Report September 2007 Introduction 1.9 1.12 References [1] Population Reference Bureau. World Population Highlights: Key Findings from the 2007 World Population Data Sheet. http://www.prb.org/pdf05/05WorldDataSheet_ Eng.pdf (accessed September 7, 2007). [2] Energy Information Administration. International Energy Outlook 2007; DOE/ EIA-0484(2007); U.S. Department of Energy: Washington, D.C., May 2007. Also available at http://www.eia.doe.gov/oiaf/ieo/index.html. [3] International Energy Agency. World Energy Outlook 2005: Middle East and North Africa Insights. 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