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(2006),
(Washington, DC, 2006). 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, acquire natural gas from foreign producers
for resale in the United States, or sell U.S. gas to foreign consumers.
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. Foreign gas transactions may occur via either
pipeline (Canada or Mexico) or transport ships as liquefied natural gas
(LNG).
Primary inputs for the module are varied. One set of key assumptions concerns
estimates of domestic technically recoverable oil and gas resources. Other
factors 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 resources84 consist of proved
reserves,85 inferred reserves,86 and undiscovered technically recoverable
resources.87 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.88 Supplemental adjustments to the USGS nonconventional resources are made
by Advanced Resources International (ARI), an independent consulting firm.
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
50 and 51 reflect the removal of intervening reserve additions between
the date of the latest available assessment and January 1, 2004.
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 2-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 2003 are
shown in Table 52. 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).
Synthetic Crude from Oil Shale
Projections for synthetic crude (syncrude) from oil shale 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.89 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 2010, pending the implementation of a U.S. Department of Interior
oil shale leasing program. Oil shale syncrude 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 year required to bring a new 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. Syncrude production is not resource constrained,
approximately 400 billion barrels of syncrude resources exist in oil shale
rock with at least 30 gallons per ton of rock.
Alaska Crude Oil
Alaska crude oil production is determined by the estimates of available
resources in undeveloped areas and the time and expense required to begin
production in these areas. Alaska production includes existing producing
fields, fields that have been discovered but are not currently being produced,
and fields that are projected to exist, based upon the region’s geology.
The first category of field includes expansion fields in the Prudhoe Bay
region, accounting for 800 million barrels of oil. These fields are relatively
small, and development of these fields began in 2002 and continues throughout
the forecast. The estimated size of these expansion fields corresponds
to projections made by the State of Alaska and other analysis by EIA.
Fields in the second category include fields in the National Petroleum
Reserve-Alaska, or NPR-A. In 1999, 2002, and 2004, northeastern portions
of the NPR-A were leased by the Federal government for oil and gas exploration
and production. According to a recent USGS assessment90 NPR-A is estimated
to contain a mean resource level of 10.6 billion barrels. These resources
are assumed not be brought into production until 2007. Finally, a total
of roughly 800 million barrels of additional resources are projected to
be developed in other fields yet to be discovered, both on the North Slope
of Alaska and offshore in the Beaufort Sea. These fields are expected
to be smaller than recent finds like the Alpine field. Oil and gas exploration
and production currently are not permitted in the Alaska National Wildlife
Refuge. The AEO2005 projections for Alaska oil and gas production presume
that this prohibition remains in effect throughout the forecast period.
Supplemental Natural Gas
The projection for supplemental gas supply is identified for three separate
categories: synthetic natural gas (SNG) from liquids, SNG from coal, and
other supplemental supplies (propane-air, coke oven gas, refinery gas,
biomass air, air injected for Btu stabilization, and manufactured gas commingled
and distributed with natural gas). SNG from the currently operating Great
Plains Coal Gasification Plant is assumed to continue through the forecast
period, at an average historical level of 52.5 billion cubic feet per year.
Other supplemental supplies are held at a constant level of 18.9 billion
cubic feet per year throughout the forecast because this level is consistent
with historical data and it is not believed to change significantly in
the context of a reference case forecast. Synthetic natural gas from liquid
hydrocarbons in Hawaii is assumed to continue over the forecast at the
average historical level of 2.7 billion cubic feet per year.
Legislation and Regulations
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
is
(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 200 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 200 to 400 and 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.
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 53), 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 for conventional
gas and production levels for unconventional gas in the WCSB are assumed
to be progressively greater in the rapid technology case and lesser in
the slow technology case across the forecast horizon. By 2025, the number
of successful natural gas wells are approximately 12 percent higher and
lower in the rapid and slow technology cases than in the reference case
directly due to differences in assumed technological improvements. Potential
production rates from conventional new discoveries are adjusted upward
and downward by 25 percent in the rapid and slow technology cases, respectively.
The resource base levels for the WCSB were assumed not to vary across
technology cases. The technology parameter on production from unconventional
natural gas wells is adjusted upward and downward by 50 percent under the
rapid and slow technology cases, resulting in production levels approximately
15 percent higher or lower directly due to assumed technological improvements.
Finally, the minimum supply prices deemed necessary to trigger the Alaska
and MacKenzie Delta natural gas pipelines are progressively decreased or
increased over the forecast in the rapid and slow technology cases, respectively,
downward or upward from 0.0 to 12.5 percent by 2025. 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.
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 2005 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 54. Table 55 provides a description
of their treatment under the different technology cases.
Oil and Gas Tables
Oil and Gas Notes |
