Oil and Gas Supply Module
The NEMS Oil and Gas Supply Module (OGSM) constitutes a comprehensive framework
with which to analyze oil and gas supply on a regional basis (Figure 7).
A detailed description of the OGSM is provided in the EIA publication, Model Documentation Report: The Oil and Gas Supply Module (OGSM), DOE/EIA-M063(2008),
(Washington, DC, 2008). The OGSM provides crude oil and natural gas short-term
supply parameters to both the Natural Gas Transmission and Distribution
Module and the Petroleum Market Module. The OGSM simulates the activity
of numerous firms that produce oil and natural gas from domestic fields
throughout the United States.
OGSM encompasses domestic crude oil and natural gas supply by both conventional
and nonconventional recovery techniques. Nonconventional recovery includes
unconventional gas recovery from low permeability formations of sandstone
and shale, and coalbeds.
Primary inputs for the module are varied. One set of key assumptions concerns
estimates of domestic technically recoverable oil and gas resources. Another
factor affecting the projection include the assumed rates of technological
progress, supplemental gas supplies over time, and natural gas import and
export capacities.
Key Assumptions
Domestic Oil and Gas Technically Recoverable Resources
Domestic oil and gas technically recoverable resources1 consist of proved
reserves,2 inferred reserves,3 and undiscovered technically recoverable
resources.4 OGSM resource assumptions are based on estimates of technically
recoverable resources from the United States Geological Survey (USGS) and
the Minerals Management Service (MMS) of the Department of the Interior.5 Supplemental adjustments to the USGS nonconventional gas resources are
made by Advanced Resources International (ARI), an independent consulting
firm. Based on estimates from the Reserves and Production Division of
the EIA Office of Oil and Gas, 16.1 billion barrels6 are added to US.
inferred reserves to reflect a revised assessment of the potential of enhanced
oil recovery to increase the recoverability of remaining in-place resources.
While undiscovered resources for Alaska are based on USGS estimates, estimates
of recoverable resources are obtained on a field-by-field basis from a
variety of sources including trade press. Published estimates in Tables
9.1 and 9.2 reflect the removal of intervening reserve additions between
the date of the latest available assessment and January 1, 2007.
Lower 48 Offshore
Most of the Lower 48 offshore oil and gas production comes from the deepwater
of the Gulf of Mexico (GOM). Production from current producing fields
and industry announced discoveries largely determine the short-term oil
and natural gas production projection.
For currently producing fields, a 20-percent exponential decline is assumed
for production except for natural gas production from fields in shallow
water, which uses a 30-percent exponential decline. Fields that began
production after 2001 are assumed to remain at their peak production level
for 2 years before declining.
The assumed field size and year of initial production of the major announced
deepwater discoveries that were not brought into production by 2007 are
shown in Table 9.3. A field that is announced as an oil field is assumed
to be 100 percent oil and a field that is announced as a gas field is assumed
to be 100 percent gas. If a field is expected to produce both oil and
gas, 70 percent is assumed to be oil and 30 percent is assumed to be gas.
Production is assumed to
- ramp up to a peak level in 2 to 4 years depending on the size of the field,
- remain at the peak level until the ratio of cumulative production to initial
resource reaches 20 percent for oil and 30 percent for natural gas,
- and then decline at an exponential rate of 20-30 percent.
The discovery of new fields (based on MMS’s field size distribution) is
assumed to follow historical patterns. Production from these fields is
assumed to follow the same profile as the announced discoveries (as described
in the previous paragraph).
Oil Shale Liquids Production
Projections for oil shale liquids production
are based on underground mining and surface retorting technology and costs.
The facility parameter values and cost estimates assumed in the projection
are based on information reported for the Paraho Oil Shale Project, with
the costs converted into 2004 dollars.7 Oil shale rock mining costs, however,
are based on current Rocky Mountain underground coal mining costs, which
are representative oil shale rock mining costs. Oil shale facility investment
and operating costs are assumed to decline by 1 percent per year. The construction
of commercial oil shale production facilities is not permitted prior to
2017, based on the current status of petroleum company research, development
and demonstration (RD&D) programs.
Although the petroleum company oil shale RD&D programs are focused on the
in-situ production of oil shale liquids, the underground mining and surface
retorting process shares many similarities with the in-situ process. Moreover,
because the in-situ process is still at the experimental stage, there are
no publicly available estimates as to the in-situ process capital and operating
costs required to produce a barrel of oil shale liquids at a commercial
scale. Consequently, the underground mining and surface retorting costs,
in conjunction with the 1 percent per year cost decline, are intended to
be a surrogate for the in-situ process costs.
Oil shale production facilities are assumed to be built when the net present
value of the discounted cash flow exceeds zero. The discounted cash flow
calculation uses a calculated discount rate that takes into consideration
the financial risk associated with building oil shale facilities. Oil shale
facilities take 5 years to construct, with an additional 5 years required
to bring an in-situ facility into full production. An assumed technology
penetration rate specifies that 5 years must pass from the time the first
facility begins construction before the second facility can begin construction.
Subsequent facilities are permitted to begin construction 3 years, 2 years,
and then every year after a prior facility begins construction. Oil shale
liquids production is not resource constrained, because approximately 400
billion barrels of petroleum liquids exist in oil shale rock with at least
30 gallons per ton of rock.
Because the in-situ process is still at the experimental stage, and because
the underground mining and surface retorting process is unlikely to be
environmentally acceptable, the oil shale liquids production projections
should be considered highly uncertain.
Alaska Crude Oil Production
Projected Alaska oil production includes both existing producing fields
and undiscovered fields that are expected to exist, based upon the region’s
geology. The existing fields category includes the expansion fields around
the Prudhoe Bay and Alpine Fields for which companies have already announced
development schedules. The initial production from these fields occurs
in the first few years of the projection, with the projected oil production
and the date of commencement based on the most current petroleum company
announcements. Alaska crude oil production from the undiscovered fields
is determined by the estimates of available resources in undeveloped areas
and the net present value of the cash flow calculated for these undiscovered
fields based on the expected capital and operating costs, and on the projected
oil prices. Based on the latest U.S. Geological Survey resource assessments,
the remaining North Slope fields are expected to be primarily small and
mid-size oil fields that are smaller than the Alpine Field.
Oil and gas exploration and production currently are not permitted in the
Alaska National Wildlife Refuge. The projections for Alaska oil and gas
production assume that this prohibition remains in effect throughout the
projection period.
The greatest uncertainty associated with the Alaska oil projections is
whether the heavy oil deposits located on the North Slope, which exceed
20 billion barrels of oil-in-place, will be producible in the foreseeable
future at recovery rates exceeding a few percent.
Legislation and Regulations
The Outer Continental Shelf Deep Water Royalty Act (Public Law 104-58)
gave the Secretary of Interior the authority to suspend royalty requirements
on new production from qualifying leases and required that royalty payments
be waived automatically on new leases sold in the 5 years following its
November 28, 1995, enactment. The volume of production on which no royalties
were due for the 5 years was assumed to be 17.5 million barrels of oil
equivalent (BOE) in water depths of 200 to 400 meters, 52.5 million BOE
in water depths of 400 to 800 meters, and 87.5 million BOE in water depths
greater than 800 meters. In any year during which the arithmetic average
of the closing prices on the New York Mercantile Exchange for light sweet
crude oil exceeded $28 per barrel or for natural gas exceeded $3.50 per
million Btu, any production of crude oil or natural gas was subject to
royalties at the lease stipulated royalty rate. Although automatic relief
expired on November 28, 2000, the act provided the MMS the authority to
include royalty suspensions as a feature of leases sold in the future.
In September 2000, the MMS issued a set of proposed rules and regulations
that provide a framework for continuing deep water royalty relief on a
lease by lease basis. In the model it is assumed that relief will be granted
roughly the same levels as provided during the first 5 years of the act.
Section 345 of the Energy Policy Act of 2005 provides royalty relief for
oil and gas production in water depths greater than 400 meters in the Gulf
of Mexico from any oil or gas lease sale occurring within 5 years after
enactment. The minimum volume of production with suspended royalty payments
are:
(1) 5,000,000 barrels of oil equivalent (BOE) for each lease in water depths
of 400 to 800 meters;
(2) 9,000,000 BOE for each lease in water depths of 800 to 1,600 meters;
(3) 12,000,000 BOE for each lease in water depths of 1,600 to 2,000 meters;
and
(4) 16,000,000 BOE for each lease in water depths greater than 2,000 meters.
The water depth categories specified in Section 345 were adjusted to be
consistent with the depth categories in the Offshore Oil and Gas Supply
Submodule. The suspension volumes are 5,000,000 BOE for leases in water
depths 400 to 800 meters; 9,000,000 BOE for leases in water depths of 800
to 1,600 meters; 12,000,000 BOE for leases in water depth of 1,600 to 2,400
meters; and 16,000,000 for leases in water depths greater than 2,400 meters.
Examination of the resources available at 2,000 to 2,400 meters showed
that the differences between the depths used in the model and those specified
in the bill would not materially affect the model result.
The Minerals Management Service published its final rule on the “Oil and
Gas and Sulphur Operations in the Outer Continental Shelf–Relief or Reduction
in Royalty Rates–Deep Gas Provisions” on January 26, 2004, effective March
1, 2004. The rule grants royalty relief for natural gas production from
wells drilled to 15,000 feet or deeper on leases issued before January
1, 2001, in the shallow waters (less than 200 meters) of the Gulf of Mexico.
Production of gas from the completed deep well must begin before 5 years
after the effective date of the final rule. The minimum volume of production
with suspended royalty payments is 15 billion cubic feet for wells drilled
to at least 15,000 feet and 25 billion cubic feet for wells drilled to
more than 18,000 feet. In addition, unsuccessful wells drilled to a depth
of at least 18,000 feet would receive a royalty credit for 5 billion cubic
feet of natural gas. The ruling also grants royalty suspension for volumes
of not less than 35 billion cubic feet from ultra-deep wells on leases
issued before January 1, 2001.
Section 354 of the Energy Policy Act of 2005 established a competitive
program to provide grants for cost-shared projects to enhance oil and natural
gas recovery through CO2 injection, while at the same time sequestering
CO2 produced from the combustion of fossil fuels in power plants and large
industrial processes.
From 1982 through 2008, Congress did not appropriate funds needed by the
Minerals Management Service (MMS) to conduct leasing activities on portions
of the Federal Outer Continental Shelf (OCS) and thus effectively prohibited
leasing. Further, a separate Executive ban in effect since 1990 prohibited
leasing through 2012 on the OCS, with the exception of the Western Gulf
of Mexico and portions of the Central and Eastern Gulf of Mexico. When
combined these actions prohibited drilling in most offshore regions, including
areas along the Atlantic and Pacific coasts, the eastern Gulf of Mexico,
and portions of the central Gulf of Mexico. In 2006, the Gulf of Mexico
Energy Security Act imposed yet a third ban on drilling through 2022 on
tracts in the Eastern Gulf of Mexico that are within 125 miles of Florida,
east of a dividing line known as the Military Mission Line, and in the
Central Gulf of Mexico within 100 miles of Florida.
On July 14, 2008, President Bush lifted the Executive ban and urged Congress
to remove the Congressional ban. On September 30, 2008, Congress allowed
the Congressional ban to expire. Although the ban through 2022 on areas
in the Eastern and Central Gulf of Mexico remains in place, the lifting
of the Executive and Congressional bans removed regulatory obstacles to
development of the Atlantic and Pacific OCS.
Oil and Gas Supply Alternative Cases
Rapid and Slow Technology Cases
Two alternative cases were created to assess the sensitivity of the projections
to changes in the assumed rates of progress in oil and natural gas supply
technologies. To create these cases a number of parameters representing
technological penetration in the reference case were adjusted to reflect
a more rapid and a slower penetration rate. In the reference case, the
underlying assumption is that technology will continue to penetrate at
historically observed rates. Since technologies are represented somewhat
differently in different submodules of the Oil and Gas Supply Module, the
approach for representing rapid and slow technology penetration varied
as well. For instance, the effects of technological progress on conventional
oil and natural gas parameters in the reference case, such as finding rates,
drilling, lease equipment and operating costs, and success rates, were
adjusted upward and downward by 50 percent (Table 9.4), for the rapid and
slow technology cases, respectively. The approach taken in unconventional
natural gas is discussed below.
In the Canadian supply submodule, successful natural gas wells drilled
for conventional and tight formations in the Western Canadian Sedimentary
Basin (WCSB) are assumed to be 10 percent higher or lower in the rapid
and slow technology cases, respectively, than they would be otherwise.
For the other unconventional sources (coalbed and shale gas), the assumed
undiscovered resource levels are progressively increased or decreased (in
the rapid and slow cases, respectively) over the forecast period to a level
reaching 15 percent by 2030. In addition, the otherwise projected production
levels for these unconventional sources are increased or decreased (in
the rapid and slow cases, respectively) progressively over the forecast
period to a level reaching 25 percent by 2030. Finally, the minimum supply
prices deemed necessary to trigger the Alaska and MacKenzie Delta natural
gas pipelines are progressively decreased or increased over the projection
in the rapid and slow technology cases, respectively, downward or upward
from 0.0 to 12.5 percent by 2030. All other parameters in the model were
kept at their reference case values, including technology parameters for
other modules, parameters affecting foreign oil supply, and assumptions
about imports and exports of LNG and natural gas trade between the United
States and Mexico. Production costs in the MacKenzie Delta vary across
the projection period based on the estimated change in drilling costs in
the lower 48 states, indirectly capturing the impact of different assumptions
about technological improvement.
The Unconventional Gas Recovery Supply Submodule (UGRSS) relies on Technology
Impacts and Timing functions to capture the effects of technological progress
on costs and productivity in the development of gas from deposits of coalbed
methane, gas shales, and tight sands. The numerous research and technology
initiatives are combined into 11 specific “technology groups,” that encompass
the full spectrum of key disciplines — geology, engineering, operations,
and the environment. The technology groups utilized for the Annual Energy
Outlook 2009 are characterized for three distinct technology cases — Slow
Technological Progress, Reference Case, and Rapid Technological Progress
— that capture three different futures for technology progress. The 11
technology groups are listed in Table 9.5. Table 9.6 provides a description
of their treatment under the different technology cases.
Limited OCS Access Case
The executive ban on exploratory and developmental drilling in the lower
48, federal Outer Continental Shelf (OCS), that had been in place since
1990, was lifted in July 2008. The Congressional ban that had been in place
since 1982 was allowed to expire in September 2008. The AEO2009 reference
case assumes that there will be no restrictions on drilling in the Atlantic
and Pacific offshore throughout the projection period. However, under the
Gulf of Mexico Energy Security Act of 2006, the majority of the Eastern
Gulf of Mexico and a small portion of the Central Gulf of Mexico will be
available for leasing after 2022. The OCS limited access case is based
on the AEO2009 reference case, with resource assumptions reduced by the
resources that had been under Presidential and Congressional moratoria
in the Atlantic, Pacific, and Eastern and Central of Mexico. With the OCS
limited access case assumptions, technically recoverable resources in the
OCS decrease to 75 billion barrels of oil and 380 trillion cubic feet of
natural gas compared to the AEO2009 reference case levels of 93 billion
barrels of oil and 456 trillion cubic feet of natural gas.
Arctic National Wildlife Refuge (ANWR) Case
The Arctic National Wildlife Refuge (ANWR) case assumes that Congressional
legislation opening the Federal 1002 Area to Federal oil and gas leasing
would be enacted in 2009.
The ANWR case is solely focused on the potential for ANWR to produce crude
oil. The ANWR case assumes that any gas found within ANWR would be re-injected
into ANWR oil reservoirs to maintain reservoir pressure and that any Alaskan
gas pipeline built during the projection period would rely on the natural
gas reserves and resources found within the State lands located in the
Central North Slope.
The ANWR case assumes that the opening of the Federal 1002 Area would also
open the Native lands and State offshore region to oil exploration. The
Federal, State, and Native lands are referred to collectively as the ANWR
Coastal Plain. The ANWR case assumes that the size of the oil fields discovered
within the coastal plain is based on the mean U.S. Geological Survey (USGS)
estimate of 10.4 billion barrels of technically recoverable crude oil8 that the USGS9 estimated for the Federal, State, and Native lands in or
adjacent to ANWR.
The ANWR case assumes first production from the ANWR area would occur 10
years after the 2009 enactment of legislation opening ANWR to oil and gas
leasing. So first ANWR oil production would occur in 2019, based on the
following timeline:
- 2 to 3 years to obtain U.S. Bureau of Land Management (BLM) leases.
- 2 to 3 years to drill a single exploratory well, due to the limited winter
drilling season.
- 1 to 2 years to develop a production development plan and obtain BLM approval
for that plan.
- 3 to 4 years to construct the necessary infrastructure and to drill and
complete development wells.
The 10-year timeline for developing ANWR petroleum resources assumes that
there are no protracted legal battles regarding the leasing and development
of ANWR oil resources.
The ANWR case assumes that much of the oil resources in ANWR, like the
other oil resources on Alaska’s North Slope, could be profitably developed
given the current levels of technology and at current and projected oil
prices. This analysis also assumes that new fields in ANWR will begin development
2 years after a prior ANWR field begins oil production.
The ANWR case uses the USGS mean oil resource estimate of potential field
sizes in the coastal plain area. Because the larger fields are generally
easier to find and cheaper to develop, the ANWR case assumes that the largest
oil fields are developed first. Based on the 2-year time lag assumption
between the development of successive oil fields and the USGS field size
distribution, the ANWR case assumes the following oil field development
schedule:
Potential production from ANWR fields is based on the size of the field
discovered and the production profiles of other fields of the same size
in Alaska with similar geological characteristics. In general, fields
are assumed to take 3 to 4 years to reach peak production, maintain peak
production for 3 to 4 years, and then decline until they are no longer
profitable and are closed.
Oil and Gas Supply Module Notes |
