Evaluation of Development Options for Alaska North Slope Viscous and Heavy Oil

Abstract

Current estimates of discovered viscous and heavy oil in Alaska’s North Slope are 12 billion barrels of oil-in-place and 12–18 billion barrels of oil-in-place, respectively (see Appendix 1 for conversion to SI units). Since the early 1990s to the end of 2010, cumulative viscous oil production has amounted to 150 million barrels, and there has been no commercial production of heavy oil. During the last three decades, the industry has been challenged to develop technologies to commercially produce these untapped oil resources in this Arctic environment. In this paper, the general locations and geologic properties of the viscous oil-bearing West Sak/Schrader Bluff and heavy oil-bearing Ugnu stratigraphic intervals are described first. The geologic variability within these deposits and the evolution of technology have forced an incremental development approach, requiring costly field testing at the pilot scale of innovative extraction techniques. Although viscous oil is currently produced, its development is not mature, and firms appear to be still spending large sums on new approaches to improve recovery. The analysis specifies a representative viscous oil project and then applies a “real options” framework using simulation to determine whether the risked expected project value is sufficient to fund required expenditures on extraction process research and field testing. Computations show available field test funds to be highly sensitive to the operator’s hurdle rate of return as well as the range in magnitude of potential State revenues. The contribution of the paper is solving this problem using an approach where the extreme low return and high scenarios need only be specified, and where the uncertainties are modeled with beta distributions based on historical data or expert opinion.

Appendices

Appendix 1

See appendix Table 7

Table 7 Conversion Factors for SI Units

Appendix 2: Cost components

Cost estimates are in 2012 US dollars, and the basic cost data are derived from QUE$TOR cost estimation software (IHS Inc. 2013b). The estimates were based on two well pads each with 50 wells, 25 production wells, and 25 injector wells. Vertical depth was assumed to be 5,000 feet, and each lateral had a length of 5,000 feet. The cost of drilling and equipping dual lateral production and injection wells was based on data from QUE$TOR (IHS Inc. 2013b) and a procedure described in Attanasi and Freeman (2011) averaged about 8 million dollars per well. Well drilling, completion, and production are not riskless; an average 15 % failure rate was assumed for production wells. The capital costs for two well pads and production facilities that could accommodate fluid injection were estimated using the QUE$TOR software (IHS Inc. 2013b). Table 8 shows a list of the estimated initial capital investment expenditures. Decommissioning costs amount to about 15 % of the initial investment costs. However, that amount does not become due until 20–25 years out into the future so the present value of decommissioning costs was added to the initial capital investment. For the specified low return case, the investment cost was 120 % of the total shown in Table 8, and for the high return case, the investment cost was 80% of the total shown in Table 8.

Table 8 Initial Investment Cost in Millions of Dollars for a Project to Produce Viscous Oil

Production scenarios are as described in the text. For all scenarios, the same well configurations were used. The initial daily well production for dual lateral horizontal wells was assumed to be 1,500 barrels per day. For the low return scenario, well production was assumed to decline 22 % annually. The well life recovery factor of the in-place oil for the low return scenario was just over 14 %. For the high return scenario, average annual well production was assumed to decline by 12 % per year with a recovery factor of about 26 % of the oil-in-place after 20 years. Field production was smoothed so that there would be reasonably high utilization of the field fluids processing capacity of 51,000 barrels per day.

Annual direct operating cost was computed based on the number of operating production wells and the estimated fluid flow rates. Annual operation cost for each production/injection well-pair was assumed to be 1 million dollars per well-year and 2 dollars per barrel of production fluid flow. Production fluid flow for the years after the initial peak production of 51,000 barrels per day was estimated by assuming produced water would amount to 25 % of the difference between peak production and current production. In the low return case, water cut was 95 % after year 18, and in the high return case, water cut was about 50 % after 20 years. Production was assumed to shut down when annual production revenues were insufficient to meet annual operating costs, which also included production related taxes.

It was assumed that the royalty is taken in kind, and that the royalty rate amounted to 12.5 % of gross production. In addition to the direct costs, annual operating costs include the state ad valorem tax, Alaska severance tax, and State and Federal income taxes. The following summarizes the tax computations. The annual Alaska ad valorem property tax rate in oil production equipment is 2 % of the assessed value. The assessed value is assumed to decline over a 20-year period, but the valuation will in practice have a floor that is equivalent to 20 % of the initial investment. The Alaska state severance tax is 35 % of the net value of the sales received by the operator with carryover provisions in years when losses occur. A 5 dollar per barrel severance tax credit was applied for each barrel of oil produced to reduce the severance tax liability. The production tax credit cannot reduce the liability below zero. The combined Alaska and Federal income tax rate is 39 % of taxable income (Attanasi and Freeman 2011). Table 9 catalogs the computational results that discussed as well as the simulation results for assumed alternative shape parameter values.

Table 9 Catalog of Project Risks and Risked Expected Positive Net Present Values (NPV) for Alternative Discount Rate Assumptions and Shape Sets of Parameters (α, β) of Beta Distributions Used to Model Uncertainty in Investment Cost and Annual After-tax Net Cash Flows