A Market Assessment of Heavy Oil, Oil Sands, and Oil

Shale Resources

Jennifer Spinti & Michael HogueDOE/NETL Unconventional Fuels Project Review

MeetingMarch 10-11, 2011

Acknowledgements• I wish to thank all who have contributed

to the assessment including Gary Aho & colleagues (Sage Geotech), Jake Bauman, Bernardo Castro, Milind Deo, Michael Hogue, Kerry Kelly, Michelle Kline, Terry Ring, John Ruple, Glen Snarr & colleagues (EER), Adam Taylor, Kirsten Uchitel, Michael Vanden Berg (UGS), Jon Wilkey

• Financial support from DOE/NETL under DOE Award No. DE-FE0001243

Our Assignment

–From the 2009 Statement of Project Objectives

An assessment that examines limiting factors to the development of domestic heavy oil, oil sands, and oil shale resources and identifies policy, technology, and economic gaps that could be advanced through increased research activities shall be researched and published. As part of the assessment, an economic impact analysis for existing upstream and downstream options/technologies for heavy oil, oil sands, and oil shale shall be completed. The assessment shall also identify preliminary infrastructure needs that are required for future development of all three resources under various production scenarios (e.g. refining, pipeline, water and power capacity).

Recent Reports Related to Unconventional Fuels

Strategic Significance of America’s Oil Shale Resource (ONPOSR/DOE, March 2004) - Use Alberta tar sand analog to suggest that U.S. oil shale could generate productivity & profitability. For 100,000 BOPD mining/surface retorting operation, compare in 5 areas: resource characteristics, technology performance & product quality, environmental impacts & controls, mass balances & energy requirements, production economic

Oil Shale Development in the United States - Prospects and Policy Issues (RAND Corporation, 2005) - 50,000 BOPD first-of-a-kind mining/surface retorting operation, CAPEX in $5B-$7B range, OPEX in $17-$23/bbl range, profitable at $70-$95/bbl (Union/Colony projects with inflation factors)

Economic Impacts of U.S. Liquid Fuel Mitigation Options (DOE/NETL, July 2006) - 100,000 BOPD facility using Shell ICP process, CAPEX is $8 B, OPEX is $14/bbl, perform economic impact analysis (tax revenues, jobs, industry sales).

NPOSR - Naval Petroleum & Oil Shale Reserves

NSURM - The National Strategic Unconventional Resources Model was developed by U.S. Department ofEnergy (DOE), Office of Naval Petroleum and Oil Shale Reserves (NPOSR) in the winter of 2005 – 2006. The model was developed, from the existing National Oil Shale Model1,specifically to support the Task Force mandated by Congress in section 369 of the Energy Policy Act of 2005. The model will be used in evaluating the potential for domestic unconventionalliquid production from oil shale, tar sands, coal to liquids, heavy oil, and CO2 Enhanced Oil Recovery. The model relies on publicly available information to evaluate the economics of several resource development technologies. For oil shale, the model evaluates: 1) Surface Mining, 2) Underground Mining, 3) Modified In-Situ, and 4) True In-Situ. For tar sands, the modelconsiders: 1) Integrated Mining and Upgrading, and 2) Steam Assisted Gravity Drainage. For coal to liquids, the model examines the Fischer-Tropsch process. For heavy oil and CO2 EOR,the model respectively evaluates steam flooding and carbon dioxide flooding. The model contains a resource database containing detailed petrochemical and geologic data on the Westernoil shale resources, the tar sands resources, the coal resources, and the existing oil reservoirs which are candidates for steam flooding and carbon dioxide flooding. An engineering basedprocess screening module assesses the applicability of each technology and determines the most appropriate recovery method. Based upon the recovery technology and the resourcecharacteristics, the potential production is determined. An integrated economic module evaluates the potential development of each resource through a detailed cash flow analysis. Theresource and process specific costs were obtained through a variety of DOE and industry sources and updated through 2004. Project development schedules and lead times were also developed for each resource and technology modeled. These were based upon the best available industry data and incorporated into the modeling system. The model evaluates each project individually and aggregates the results of the economically viable projects at the technology, resource, and national levels. At present, the model estimates a range of benefits including: production, reserves, transfer payments, investment and operating requirements, cash flow before and after tax, direct federal revenue, direct state revenue, direct sector revenue, the contribution to GDP, the value of imports avoided, and the indirect and direct sector employment. With these capabilities, the modeling system proves to be a “unique” analytical tool for the cost and benefit analysis of alternative local, state, and federal actions in the area of economic incentives, technology, and environmental regulation as theyrelate to domestic unconventional fuel resources. To increase credibility, the NPOSR has developed the model system from existing, vetted models wherever possible. The oil shale component has been thoroughly reviewed by experts in oil shale industry, policy and program analysts from DOE, as well as consultants specialized in resource evaluation, technology characterization, project economics, and resource modeling. The heavy oil and CO2 EOR components were developed from existing DOE process models which have been thoroughly examined and accepted by industry.

Recent Reports Related to Unconventional Fuels - con’t.

National Strategic Unconventional Resources Model (DOE/NPOSR, 2006) - Description of modules but no analysis using model

A Technical, Economic, and Legal Assessment of North American Heavy Oil, Oil Sands, and Oil Shale Resources (September 2007) - Canadian oil sands economics, influence of crude oil & nat. gas prices on steam injection, Shell ICP may be profitable at $30/bbl, infrastructure, socioeconomics/employment by industry

America’s Strategic Unconventional Fuels (Task Force on Strategic Unconventional Fuels, September 2007) - factors constraining investment & strategies, national economic impact from NSURM (federal & state revenues, employment, GDP, imports avoided)

Secure Fuels from Domestic Resources (ONPOSR/DOE, August 2008) - company profiles showing continuing evolution of oil

shale/sands technologies

Recent Reports Related to Unconventional Fuels - con’t.

Unconventional Fossil-Based Fuels - Economic and Environmental Tradeoffs (RAND Corporation, 2008) - SCO from Canadian oil sands with analysis of production cost & CO2 management costs/strategies

Report on the energy sector in the U.S. commissioned by Secretary Chu - Reviewed material written by EER early last fall but haven’t heard when report will be released/what exactly the scope is

Reports from Canada analyzing oil sands economics

It is difficult to estimate future production costs for unconventional fuels. There is oftena bias toward underestimating costs and overestimating performance of new fuel-productionfacilities and their operations. Since facilities that upgrade and refine bitumen from oil sandsor produce CTL require significant levels of investment, the average cost of producing a unitof product over the facility’s lifetime is sensitive to a number of assumptions regarding the timeto construct the facility, the mixture of capital and debt used to finance the construction, thecosts of the feedstocks, and the successful start-up and long-term capacity factor of the facility.All of these parameters are uncertain and difficult or impossible to accurately predict earlyin the planning process.

A Useful Contribution

“It is difficult to estimate future production costs for unconventional fuels. There is often a bias toward underestimating costs and overestimating performance of new fuel-production facilities and their operations. Since facilities that upgrade and refine bitumen from oil sands ... require significant levels of investment, the average cost of producing a unit of product over the facility’s lifetime is sensitive to a number of assumptions regarding the time to construct the facility, the mixture of capital and debt used to finance the construction, the costs of the feedstocks, and the successful start-up and long-term capacity factor of the facility. All of these parameters are uncertain and difficult or impossible to accurately predict early in the planning process.”

- RAND Corp., Unconventional Fossil-Based Fuels -

Economic and Environmental Tradeoffs

Scenario-Based Approach

Three unconventional fuels considered: heavy oil, oil sands, oil shale

Heavy oil produced commercially in CA but not yet in AK - focus on obstacles to AK production

Oil sands produced commercially in Alberta but not Utah; estimated size of US resource is 76B barrels with 32B barrels in Utah

Oil shale not produced commercially in North America - Piceance Basin in CO has richer, thicker (1000+ ft) deposits, but Mahogany zone located between two aquifer systems; Uinta Basin’s Birds Nest aquifer several 100 ft above Mahogany zone

Photo by Judy Patrick, Associate Press

A-Groove (364 ft)

Mahogany Zone(374 ft)

B-Groove (460 ft)

Upper R-6 (503 ft)

Middle R-6 (607 ft)

Big Three

(206-218 ft)

Top of eco-

nomic oil shale

Stillwater

(242-250 ft)

Four Senators

(266-284 ft)

Wavy Tuff (334-336 ft)

Mahogany Bed(406 ft)

Salin

e Zon

e (surfa

ce-130 ft)

R-8

Green

Riv

er Form

ation - P

arachute C

reek M

ember

0 20 40 60

Oil Yield - from Fischer Assay (gal/ton)

0

100

200

300

400

500

600

700

800

900

1000

Dep

th (ft)

Top of economic oil shale (206 ft)

Lower R-6 (638 ft)

L-5 (671 ft)

R-5 (744 ft)

80

L-4 (821 ft)

Economicranking

1

2

3

4

Based on: Skyline Oil Co. well Watson 3 and WRSP well P 4

Scenario-Based Approach

In situ & ex situ production methods; methods chosen to maximize available industrial data/expertise

50,000 BOPD production for 20 years

Product equivalent to WTI crude

Elements include: production, primary/secondary upgrading, transportation to a refinery

Carbon management included as variation of all scenarios; use oxy-firing with CO2 capture for unit operations/steam generation with CO2 stream compressed to pipeline conditions (for EOR)

What is “Economic Analysis”?

• Microeconomic analysis = profitability analysis

• First component is estimation of capital & operating costs for extraction, upgrading, & transportation

• Second component is project revenue; it’s estimated based on various price projections for oil (& CO2 sales)

• Macroeconomic analysis = economic impact analysis

• Broad regional impacts if scenario were realized; may result from but do not cause private investment

• Impacts include total addition to regional levels of employment, personal income, and government revenue

The financial analysis of the scenarios in this report includes two components. The first component is an estimation of the capital and operating

costs for the extraction, upgrading and transportation of the various unconventional fuels. [In this report, "supply-cost" refers to capital and operating

costs put in terms of cost-per-barrel.] In all scenarios, the rate of production is 50,000 BOPD, the production time period is 20 years, and the product

is equivalent to a light, sweet crude. The second component, project revenue, is estimated based on projections of the price of oil. Since the

production rate and upgraded product are the same for all the scenarios, revenue projections are equal across scenarios. [Actually, there are some

small differences in revenue between scenarios involving CO2 sales in addition to oil sales and scenarios involving only oil sales.] A number of

measures of profitability are applied to the supply cost and revenue estimates, and the results are reported for each scenario. As revenue projections

are the same, variation in profitability across scenarios only reflects differences in supply costs.

The term "microeconomic analysis" is used in this report as a synonym for the "profitability analysis.” The term is used to distinguish the

attractiveness of these scenarios as private investments from the broad regional economic impacts that may result as side-effects if the scenario were

realized. The term "macroeconomic analysis," or "economic impact analysis" is used in this report to denote these latter effects which may result

from, but do not cause, private investment.

• Absence of federal policy that articulates role of unconventional fuels in domestic energy portfolio

• Divergent paths for development on federal and state lands

1. Recent ruling on oil shale/tar sand leases - RD&D leases okay, but no commerical leases; DOI will prepare new EIS

2. SITLA lands are open for business

3. Redundant /inefficient infrastructure

• Climate change policies

Government & Public Policy

n case you hadn't seen this yet, I'm attaching the settlement reached between various environmental groups and DOI in respect of the legal challenges brought to the Programmatic EIS. As summarized by John, the high points of the settlement are: (1) DOI will not solicit or act on any new expressions of interest for commercial oil shale or tar sands leases made in accordance with the 2008 PEIS & ROD; (2) DOI will prepare a new EIS to evaluate amendments to the 2008 ROD; (3) DOI, however, can solicit new RD&D leases; and (4) DOI can act upon prior expressions of interest in commercial tar sands leasing in the Asphalt Ridge STSA.

Public Costs (Externalities)

• Actual cost vs. public perception of cost

• Not currently amenable to reliable quantification - water availability, land use impacts, air quality, carbon footprint

• During winter of 2009-2010, Uinta Basin ozone levels as high as worst ozone areas in US; could halt energy development activities

• Can assign costs to carbon capture system, but what about public perception, low-carbon fuel standards, etc.

• See work of Robert Stavins, environmental economist at Harvard’s Kennedy School

Supply Cost Analysis Issues

In situ oil shale scenario

• Based on simulations of conductive heat transfer in reservoir, vertical drilling with TX 5-spot pattern requires that 1000s of wells be drilled

• Drilling becomes cost & equipment prohibitive

• New approach is to run simulations with horizontal wells

• Also run with increased permeability (AMSO process) to determine what reservoir permeability is required to reduce number of wells to “acceptable” level

Supply Cost Analysis IssuesEx situ/in situ oil sands

scenarios

• Size/nature of resource precludes large scale development

• Stripping ratio on Asphalt Ridge reaches uneconomic levels within 4 years

• New approach is to have 10,000 BOPD operation, run merchant upgrader

• Much of Utah resource is lenticular with thin bitumen layers (laid down by meandering streams); geological surveys conducted in 1970s/80s show

• SAGD is very difficult with this type of resource

Wally Gwynn- P.R. SPRINGAND HILL CREEKTAR SAND AREAS

A RESOURCE ASSESSMENT

Supply Cost Analysis Issues

In situ heavy oil scenario

• Number of wells required was prohibitive given Arctic environment, cost of drilling wells

• Well spacing was factor of 10 closer than current practice in CA

• Move to horizontal drilling from single wellpad to reduce impact to Arctic environment, reduce costs

BP via Getty Images

Economic Impact Analysis -Ex Situ Oil Shale Scenario

Economic impacts are the additional jobs, wage earnings, and economic output accruing to the host region

Impacts are estimated and reported for the state and for the Uinta Basin (comprised of Utah’s Duchesne and Uintah Counties)

Impacts are estimated and reported separately for the construction and operations phases of the project

Conditions determining the accuracy of the estimates are discussed

Construction Impacts for State - Ex Situ Oil Shale

Analysis

Construction Impacts for Basin - Ex Situ Oil Shale

Operations Impacts for State - Ex Situ Oil Shale Analysis

Operations Impacts for Basin - Ex Situ Oil Shale Analysis

Assumptions & Limitations of Model

There are no opportunity costs associated with development

Production methods of regional firms are reasonably approximated by production methods that are typical for nation as a whole

Scope of impacts does not include positive or negative externalities