**REPORT TITLE:** Beaufort Sea Basin Petroleum Development Scenarios for
the Federal Outer Continental Shelf. Interim Report.

**STUDY TITLE:** Beaufort Sea Basin Petroleum Development Scenarios for
the Federal Outer Continental Shelf, Interim Report (TR-03).

CONTRACT NUMBER(S): BLM: CT6-61; MMS: 14-12-0001-29002

SPONSORING OCS REGION: Alaska.

APPLICABLE PLANNING AREA(S): Beaufort Sea.

FISCAL YEAR(S) OF PROJECT FUNDING: 1976.

COMPLETION DATE OF REPORT: December 1977.

COST(S): FY 1976: \$126,636; CUMULATIVE PROJECT COST: \$126,636.

PROJECT MANAGER(S): R. Schmidt.

AFFILIATION: Peat, Marwick, Mitchell & Company.

ADDRESS: 601 West 5th Avenue, Anchorage, Alaska 99501.

PRINCIPAL INVESTIGATOR(S)\*: R. Schmidt.

KEY WORDS: Beaufort Sea; Alaska; development scenarios; lease sale;
exploratory drilling; pipeline; oil spill; impacts; Barter Island; Point
Barrow; Camden Bay; Prudhoe Bay; Alaska Region.

ACCESS NUMBER: 29002

**BACKGROUND:** In order to analyze socioeconomic and environmental
impacts associated with Beaufort Sea petroleum exploration, development,
and production, it is necessary to make reasonable and representative
predictions concerning the nature of that potential development. Of
particular interest to socioeconomic studies are manpower, equipment,
and material requirements, and scheduling of petroleum development. This
report was the third of six similar efforts comprising the first year of
the Alaska Outer Continental Shelf (OCS) Socioeconomic Studies Program,
a multi-year research effort which attempts to predict and evaluate the
effects of Alaska OCS petroleum development upon the unique physical,
social, and economic environments within the State.

**OBJECTIVES:** (1) To analyze fifteen development scenario combinations
using several technical, developmental, and operations assumptions; and
(2) To select four scenarios for more detailed analysis on the basis of
broad geographical and reserve level representation, economic
feasibility, and potential for impact.

**DESCRIPTION:** Petroleum development scenarios formulated under the
present analysis encompassed the area between Barter Island and Point
Barrow and extending seaward from the 3-mi limit to the 20-m isobath.
The discovery of oil and gas in any one of three offshore locations
within the confines of the proposed Beaufort Sea Federal OCS lease sale
was postulated. Five levels of discovered reserves for each location
were evaluated for their economic feasibility under different economic
assumptions, followed by a parametric analysis of required market prices
to meet alternate financial objectives. During the parametric analysis,
the following variables were utilized: reserve size; location of
discovery; level of investment; tax status; desired rate of return; and
the tariffs of the transportation systems used to transport oil and gas.
Four scenarios were then selected for more detailed analysis on the
basis of broad geographical and reserve level representation, economic
feasibility, and potential for physical and social impacts. The
petroleum development scenarios drew upon U.S. Geological Survey (USGS)
estimates of the level of petroleum resources in the Beaufort Sea area,
ranging from a low level of resources (with 95% probability of
occurrence) to a very high level (with only a 2% probability of
occurrence). The scenarios generated were designed to explore the full
range of potential oil development activities and reflected the
practical economic constraints and physical characteristics of petroleum
activities appropriate to the area. For the purposes of this study, oil
deposits were arbitrarily distributed into three geographic
concentrations of 60, 30, and 10% of the total reserves. As such, each
concentration, or cluster of fields, was presumed to have an equal
chance of discovery in any one of three general locations, corresponding
to the eastern, central, and western Alaska Beaufort Sea lease area
within the vicinity of Point Barrow, Prudhoe Bay, and Camden Bay,
respectively.

**SIGNIFICANT CONCLUSIONS:** The Beaufort Sea environment presents
several significant constraints to petroleum exploration and
development, the foremost of which is sea ice and its movement.
Selection of offshore structures in the Beaufort Sea OCS lease sale area
will depend upon such factors as environmental constraints, the stage of
petroleum development (e.g., exploration, development, production),
available technology, logistics, costs, environmental legislation, and
resource availability. Five levels of discovered reserves for each of
three locations (offshore of Smith, Prudhoe, and Camden Bays) were
evaluated for their economic feasibility under different economic
assumptions.

**STUDY RESULTS:** Physical and environmental conditions that may
present constraints to offshore petroleum development include sea ice,
subsea permafrost, bathymetry, waves and storm surges, and climatic
extremes. Foremost of these is sea ice and its movement. A short,
ice-free (or open water) season limits time during which conventional
drilling structures and service vessels can operate. Offshore platforms
and subsea pipelines will have to be protected from the stresses of
moving ice. The significance of Beaufort Sea bathymetry to petroleum
development is that the characteristically broad expanses of shallow
water favor the utilization of man-made islands, and does not favor the
utilization of semi-submersible drilling rigs or concrete production
platforms. Waves and storm surges are particularly important with
respect to the design of artificial islands. Offshore drilling
structures and technology that may be available in the Beaufort Sea OCS
lease sale area include artificial islands, reinforced ice platforms,
ballasted barges, ice strengthened drillships, and gravity structures.
Selection of offshore structure type will depend upon such factors as
environmental constraints, the stage of petroleum development (e.g.,
exploration, production), technology available, logistics, costs,
environmental legislation, and resource availability. Other technology
options include land-based directional drilling, and offshore tunneling
and chamber systems. The 15 scenarios evaluated were comprised of a
number of components, each of which was linked to the others. Ultimate
recovery of the reserves occurred at the point where the operating costs
exceeded the value of the oil produced. The assumed recovery schedule
indicated that oil production will rise to a maximum flow rate by the
beginning of the second year and will remain at that level for six
years, after which it will fall off exponentially. Given the
hypothetical discovery sites, most exploratory drilling will take place
within the land-fast ice zone on temporary islands constructed of
gravel, sand, reinforced soil, or ice, as well as from drillships and
mobile rigs which will remain inoperative, or frozen in, during the
winter. The required year-round base charge payment will adversely
affect the economics of their use. Offshore wells will be directionally
drilled to an average depth of 3,050 m and will incorporate a
thermocasing string in order to maintain the integrity of the well hole.
Location of the petroleum fluids processing facilities was presumed to
be on the production platforms. Offshore platforms are to be connected
to the shore by pipelines which pass through the fast ice zone, and are
to be buried within trenches deep enough to afford protection from ice
scour. Onshore, hot oil pipelines will probably be run above ground
except in areas with stable soils and at major river crossings.
Probabilities of oil spills were developed for three separate activities
and included platform blowouts, platform spills, and pipeline spills.
The probability of a well blowout resulting in oil release during
Beaufort Sea drilling operations was projected as 0.01% per well, based
upon Canadian studies. Empirical evidence from Gulf of Mexico experience
was utilized to predict the occurrence of platform spills, indicating an
occurrence rate of 0.0175 spills per year per platform, averaging 2,500
bbl each loss. Further, of these spills, 75% were predicted to occur
with accidents (fire or injury). Potential for pipeline spills (leaks)
were deemed much more likely onshore than offshore. Three major economic
concepts were employed throughout the analysis: all unit costs and
prices are stated in terms of 1975-1976 dollars; comparisons regarding
economic feasibility are all referenced to a single point in time (i.e.,
start of production); and many of the variables are not fixed uniquely
by assumption, but rather are given a range of values. Exploration costs
are limited to three major cost components: purchase of offshore tracts;
construction of exploratory platforms; and drilling of exploratory
wells. Transportation costs are divided into oil transport costs,
consisting of pipeline tariff and tanker costs, and gas transport costs.
Assuming 3.5 billion barrel \[Bbbl\], 2.3 Bbbl, and 1.4 Bbbl oil
reserves, the central region consistently delivered oil and gas at
higher percent returns than eastern and western regions. In the detailed
analysis, the first scenario corresponded to low-level estimates of
reserves and entailed concurrent exploration offshore from Smith,
Prudhoe, and Camden Bays, with insufficient resources to justify either
oil or gas development. The exploration phase covered a period of only
four years, resulting in discouraging results and subsequent
termination. The western region included 12 tracts, approximately 60
miles east of Barrow and 140 miles west of Prudhoe Bay. The central
region encompassed seven tracts, approximately 25 miles from the
trans-Alaska pipeline terminus. The eastern exploration region was
located offshore from the Arctic National Wildlife Range in Camden Bay,
approximately 90 miles east of Prudhoe Bay. The second scenario
corresponded to the most likely estimate of recoverable reserves and was
located in the Prudhoe Bay area. Based on the projections, exploration
lasted for five years and development of the field required an
additional 5 years. Oil production commenced in the tenth year and very
quickly reached a maximum annual oil output of 70 million bbl. Gas
production began in year 12 with an annual output in excess of 100
billion cubic feet (Bcf). Although the flow rates of gas remained
stable, the oil output began to decline rapidly after the sixteenth
year. Operations were shut down during the thirtieth year. The third
scenario evaluated corresponded to high level estimates of reserves in
the eastern Beaufort Sea OCS area. Based on the projections, an
estimated 2.3 Bbbl oil and 5.8 trillion cubic feet (Tcf) of gas were
discovered offshore from Camden Bay. Exploratory and development phases
involved two sequential five-year periods following the lease sale.
Production began in the eleventh year and continued during the next six
years, at which time unit costs began to exceed unit revenues and the
operations were discontinued. Gas production began in the thirteenth
year, remained stable over the 20-year production period at roughly 300
Bcf per year. The fourth scenario corresponded to the two percent
probability level (i.e., the \"bonanza\" level scenario) wherein the
discovery encompassed 3.5 Bbbl of oil and 8.8 Tcf of gas offshore from
Smith Bay in the western Beaufort region. Based on the projections, the
exploration phase lasted for five years and was followed by an intensive
five-year period of field development. By the twelfth year, oil was
delivered at an annual rate of 350 million bbl. Gas production began a
year later at a steady annual rate of 450 Bcf. By the eighteenth year,
oil production started to decline and operations were terminated during
the thirtieth year. Manpower requirements in the four scenarios follow
very similar patterns from the time of lease award to the start of
production. The level of manpower moved through two distinct cycles,
corresponding to the phases of exploration and field development. The
peak of the development cycle was significantly larger than that of the
exploratory cycle, primarily as a result of the large amounts of labor
required for pipeline installation during field development. During the
exploration phase, total manpower requirements were directly related to
the number of tracts explored, whereas during the development phase,
requirements are directly related to the number of production wells
drilled and miles of pipeline laid.

**STUDY PRODUCT(S):** Peat, Marwick, Mitchell & Company, URSA,
Crittenden, Cassetta, Cannon/Hellmuth, Obata & Kassabaum, Inc., and
Dames & Moore. 1977. Beaufort Sea Basin Petroleum Development Scenarios
for the Federal Outer Continental Shelf. Interim Report. An interim
report for the U.S. Department of the Interior, Bureau of Land
Management Alaska OCS Office, Anchorage, AK. Social and Economic Studies
Program Technical Report No. 3. Contract No. 14-12-0001-29002. xxxii +
388 pp.

\*P.I.\'s affiliation may be different than that listed for Project
Manager(s).