Assumptions to the Annual Energy Outlook 2002
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. 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(2002), (Washington, DC, January 2002). 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 enhanced oil recovery and 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 major factors affecting the projection include the assumed rates of technological progress, projections for enhanced oil recovery production, 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 resources96 consist of proved reserves,97 inferred reserves,98 and undiscovered technically recoverable resources.99 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.100 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 47 and 48 reflect the removal of intervening reserve additions between the dates of the USGS (1/1/94) and MMS (1/1/95, 1/1/99) estimates and 1/1/00.
Alaskan Crude Oil and Natural Gas
Alaskan 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. Alaskan 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 projected to be relatively small, and development of these fields is projected to begin as early as 2002 and continue 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. This area was partially reopened for development in 1999. Based on USGS assessment of the opened areas of NPR-A, the area available for development is expected to have resources of 1.7 billion barrels. These resources are assumed not able to be brought into production until after 2010. 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.
The outlook for natural gas production from the North Slope of Alaska is affected strongly by the unique circumstances regarding its transport to market. Unlike virtually all other identified deposits of natural gas in the United States, North Slope gas lacks a means of economic transport to major commercial markets. The lack of viable marketing potential at present has led to the use of Prudhoe Bay gas to maximize crude oil recovery in that field. Recent high natural gas prices raised the potential economic viability of a major Alaskan pipeline from the North Slope into Alberta, Canada. While several routes have been proposed, the model allows for the construction of a more generic pipeline, should the economic stimulus be sufficient. A natural gas pipeline from Alaska into Alberta, Canada is assumed to carry an initial capitalization of 10 billion dollars in 2001 dollars, deliver 4 billion cubic feet per day when first constructed, take four years to construct, and not to be completed before 2008. The wellhead price in Alaska for natural gas to be delivered along such a line, is assumed to be $0.80 per thousand cubic feet in 2000 dollars. A risk premium of $0.35 was assumed above and beyond the expected cost of delivery into Alberta. On average the price in Alberta would need to be maintained for three years at wellhead prices above $3.00 per thousand cubic feet (in 2000 dollars) for construction to commence, depending on the gross domestic product forecast. This translates into a lower-48 average wellhead price of around $3.50 per thousand cubic feet. If the Alaska to Alberta pipeline is build in the model, additional pipeline is added to bring the gas across the border into the United States. For accounting purposes, the model assumes that all of the Alaskan gas will be consumed in the United States. If market prices increase by an additional $0.50 beyond the initial trigger price, then it is assumed that the capacity on the pipeline will be increased by 50 percent.
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 57.3 billion cubic feet per year. Other supplemental supplies are held at a constant level of 48.0 billion cubic feet per year throughout the forecast because this level is consistent with historical data and there is no reason to believe this will change significantly in the context of a reference case forecast. Synthetic natural gas from liquid hydrocarbons is assumed to continue over the forecast at the average historical level of 7.3 billion cubic feet per year.
Natural Gas Imports and Exports
U.S. natural gas trade with Mexico is determined endogenously based on various assumptions about the natural gas market in Mexico. U.S. natural gas exports from the United States to Canada are set exogenously to NEMS at 80 billion cubic feet per year. Canadian production and U.S. import flows from Canada are determined endogenously within the model and are constrained by pipeline capacities.
Canadian consumption and production outside of the Western Canadian Sedimentary Basin (WCSB) are set exogenously in the model and are shown in Table 49. Production in the WCSB is calculated endogenously to the model. In doing so, the natural gas finding rates are set across the forecast period by establishing an initial historical average finding rate of 1.30 billion cubic feet per well and assuming an annual decline of 1.5 percent.
Annual U.S. exports of LNG to Japan are assumed to be a constant at 65.0 billion cubic feet in each year after 2000. LNG imports are determined endogenously within the model. The model provides for the construction of new facilities should gas prices be high enough to make construction economic— the prices needed to trigger new LNG construction vary by region and are slightly above $4.00 (the exact triggers are dependent on a number of variables, such as sources of LNG).
Currently, only two LNG import terminals are in operation: the Distrigas facility in Everett, Massachusetts, and the Trunkline facility in Lake Charles, Louisiana. Maximum sustainable LNG import capacity at these two facilities in 2000 is assumed to be 332 billion cubic feet. Two additional facilities, one at Cove Point, Maryland and the other at Elba Island, Georgia, currently mothballed, are assumed to reopen by 2002, adding an additional 385 billion cubic feet of sustainable capacity. It is assumed that additional expansion at these 4 facilities could add another 274 billion cubic feet of sustainable capacity. A maximum utilization rate of 90 percent is assumed.
Offshore Royalty Relief
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.
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 25 percent (Table 50), for the rapid and slow technology cases, respectively. The approaches taken in the representation of enhanced oil recovery and unconventional natural gas are discussed below. In the Canadian supply submodule, the decline in the finding rate in the WCSB (set at 1.5 percent per year in the reference case) was adjusted for the technology cases, with a greater differential the further out in the forecast. In the rapid technoogy case the finding rate declines initially (similar to the reference case) and then increases to 2020, with an average annual increase of 0.2 percent per year. In the slow technology case the decline averages 3.2 percent per year. Similarly the forecasted wells for the WCSB were increased and decreased for the rapid and slow technology cases, respectively, with a greater differential the further out in the forecast. By 2020, the forcasted wells were adjusted up or down by 6.25 percent in the two cases. 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.
Enhanced Oil Recovery
Two impacts of technological improvements are modeled to determine the economics for development of inferred enhanced oil recovery (EOR) reserves: (1) an overall reduction in the costs of drilling, completion and equipping production wells due to incremental improvements in drilling equipment and procedures, reservoir characterization, completion methods, and operation refinement; and (2) the field-specific penetration of horizontal well technology, which represents a quantum improvement in recovery efficiency. The specific parameters for modeling the slow, reference, and rapid technology cases are shown in Table 51.
The remaining undiscovered recoverable resource determined to be technically amenable to gas miscible EOR methods is set for each region at the beginning of the forecast assuming current technology. This value is assumed to increase over the forecast period with advancements in technology (Table 52).
Unconventional Gas
The Unconventional Gas Recovery Supply Submodule (UGRSS) relies on the 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 2002 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 presented below. Their treatment under the different technology cases are described in Table 53.
Unconventional Gas Recovery Technology Groups
1. Basin Assessments: Basin assessments increase the available resource base by a) accelerating the time that hypothetical plays in currently unassessed areas become available for development and b) increasing the play probability for hypothetical plays - that portion of a given area that is likely to be productive.
2. Play Specific, Extended Reservoir Characterizations: Extended reservoir characterizations increase the pace of new development by accelerating the pace of development for emerging plays, where projects are assumed to require extra years for full development compared to plays currently under development.
3. Advanced Well Performance Diagnostics and Remediation: Well performance diagnostics and remediation expand the resource base by increasing reserve growth for already existing reserves.
4. Advanced Exploration and Natural Fracture Detection R&D: Exploration and natural fracture detection R&D increases the success of development by a) improving exploration/development drilling success rates for all plays and b) improving the ability to find the best prospects and areas.
5. Geology Technology Modelling and Matching: Geology/technology modelling and matching matches the “best available technology” to a given play with the result that the expected ultimate recovery (EUR) per well is increased.
6. More Effective, Lower Damage Well Completion and Stimulation Technology: Improved drilling and completion technology improves fracture length and conductivity, resulting in increased EUR’s per well.
7. Targeted Drilling and Hydraulic Fracturing R&D: Targeted drilling and hydraulic fracturing R&D results in more efficient drilling and stimulation which lowers well drilling and stimulation costs.
8. New Practices and Technology for Gas and Water Treatment: New practices and technology for gas and water treatment result in more efficient gas separation and water disposal which lowers water and gas treatment operation and maintenance (O&M) costs.
9. Advanced Well Completion Technologies such as Cavitation, Horizontal Drilling, and Multi-lateral Wells: R&D in advanced well completion technologies a) defines applicable plays, thereby accelerating the date such technologies are available and b) introduces an improved version of the particular technology, which increases EUR per well.
10. Other Unconventional Gas Technologies, such as Enhanced Coalbed Methane and Enhanced Gas Shales Recovery: Other unconventional gas technologies introduce dramatically new recovery methods that a) increase EUR per well and b) become available at dates accelerated by increased R&D with c) increased operation and maintenance (O&M) costs (in the case of Coalbed Methane) for the incremental gas produced.
11. Mitigation of Environmental Constraints: Environmental mitigation removes development constraints in environmentally sensitive basins, resulting in an increase in basin areas available for development.
URL: http://www.eia.doe.gov/oiaf/aeo/assumption/oil_gas.html