Report#:DOE/EIA-0554(2000)
January 21, 2000 
(Next Release: 
January, 2001)

[Errata as of 4/4/2000]

Introduction

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(2000), (Washington, DC, January 2000).  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 tight gas formations, gas 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, the start date, and threshold price for the Alaskan Natural Gas Transportation System (ANGTS), 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 resources⁹¹ consist of proved reserves,⁹² inferred reserves,⁹³ and undiscovered technically recoverable resources.⁹⁴  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.  Supplemental adjustments to the USGS nonconventional resources are made by Advanced Resources International (ARI), an independent consulting firm, and to the deep resources in the Gulf of Mexico by the National Petroleum Council.⁹⁵ 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 45 and 46 reflect the removal of intervening reserve additions between the dates of the USGS (1/1/94) and MMS (1/1/95) estimates and 1/1/98.

Table 45.  Crude Oil Technically Recoverable Resources

Table 46.  Natural Gas Technically Recoverable Resources

Alaskan Natural Gas

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. This use is expected to delay extraction of gas for market  until the post-2005 period. The estimates for gas from the North Slope that will be transported to lower 48 States markets through ANGTS are dependent on the capacity of this system.  ANGTS is projected to flow gas to market in two phases, and it is assumed that production will be available to fully utilize the capacity in both phases, if constructed. Operational capacity for the first phase is 767 billion cubic feet per year delivered to the U.S./Canadian border. Annual capacity is assumed to increase to 1,150 billion cubic feet upon the completion of the second phase. Operation for each phase is assumed to begin at midyear; thus only half of the capacity is available for the first year of operation, with full capacity available in each year thereafter.  It is assumed that ANGTS will not begin operation until 2005 at the earliest, to support oil recovery in the Prudhoe Bay field.  Each phase of ANGTS is brought on line in OGSM when the appropriate border-crossing price is reached for gas delivered to the lower 48 States. The price for phase one is $4.00 in 1998 dollars per thousand cubic feet.  When this price is reached, ANGTS is brought on line in the following year, with a total flow of 383 billion cubic feet, reaching the full capacity of 767 billion cubic feet in subsequent years.  If a higher threshold price of $5.36, in 1998 dollars per thousand cubic feet is reached, then phase two will begin the following year.  The flow will increase by 192 billion cubic feet, to 959 billion cubic feet, and in each subsequent year the flow will be 1,150 billion cubic feet.  This methodology is applied in all the cases.

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. SNG from the currently operating Great Plains Coal Gasification Plant is assumed to continue through 2008, at 1998 levels through 1999 and 55.68 billion cubic feet per year thereafter.  In all cases, it is assumed that in midyear 2009 the Great Plains facility will stop producing natural gas when the current purchase contract expires and natural gas production is assumed not to be economical. Other supplemental supplies are held at a constant level of 49.14 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 currently only produced in Hawaii.  This production is assumed to continue over the forecast at the average historical level of 2.74 billion cubic feet per year.

Natural Gas Imports and Exports

U.S. natural gas trade with Mexico and natural gas exports from the United States to Canada are determined exogenously to NEMS.  U. S. exports of LNG are also exogenously determined. Canadian production and U.S. import flows from Canada are determined endogenously within the model but are constrained by assumed pipeline capacities. Exogenously specified projections of pipeline import and export values from Canada and Mexico are shown in Table 47.

Table 47.  U.S. Natural Gas Imports and Exports

Canadian consumption and production outside of the Western Canadian Sedimentary Basin (WCSB) are set exogenously in the model and shown in Table 48.  These values are reflective of a recent forecast produced by Canada’s National Energy Board.  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 1.57 billion cubic feet per well and assuming an annual decline of 2.5 percent.

Table 48.  Exogenously Specified Canadian Production and Consumption

Annual U.S. exports of LNG were assumed to be a constant at 67.6 billion cubic feet in each projection year. LNG imports are determined endogenously within the model. The outlook for LNG imports was based on a combination of influences, including available gasification capacity, announced plans by each company, tanker availability, expected utilization rates, projected gas prices and liquefaction capacity, and long-term contracts with a responsible purchaser.  LNG import capacity in 1998 is 359 billion cubic feet.  The outlook for LNG imports also includes an implicit assumption that no major operational or institutional difficulties arise that are not resolved expeditiously.  

Currently, only two LNG import terminals are in operation: the Distrigas facility in Everett, Massachusetts, and the Trunkline facility in Lake Charles, Louisiana.  A third facility at Elba Island, Georgia, currently mothballed, is assumed to reopen in 2002, adding an additional 118 billion cubic feet capacity.  The other existing import terminal, at Cove Point, Maryland, is not expected to reopen for tanker imports in the projection period.

Offshore Royalty Relief

The Outer Continental Shelf Deep Water Royalty Act (Public Law 104-58) gives the Secretary of Interior the authority to suspend royalty requirements on new production from qualifying leases and requires that royalty payments be waived on new leases sold in the 5 years following November 28, 1997.  The volume of production on which no royalties are due is 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 exceeds $28 per barrel or natural gas exceeds $3.50 per million Btu, any production of crude oil or natural gas will be subject to royalties at the lease stipulated royalty rate. 

Climate Change Action Plan

The natural gas production forecasts incorporate the expected results of the Climate Change Action Plan (CCAP)— Action Item 35, entitled Launch Coalbed Methane Outreach Program.  Under Action Item 35, the Department of Energy (DOE) and the Environmental Protection Agency (EPA) created a program to raise the awareness among key coal companies and State agencies of the potential for cost-effective methane emissions reduction.  

Estimates of the production resulting from this program through 2020 have been obtained from EPA.  These production projections are presented in Table 49.

Table 49.  Production from Mines Reached by CCAP Action Item 35

The annual production increases resulting (linear interpolations for interim year) from CCAP Action Item 35 are added to baseline forecasts of coalbed methane (CBM) production from the OGSM.  The additional production is allocated regionally based on sharing factors derived from analysis in the EPA report, Opportunities to Reduce Anthropogenic Methane Emissions in the United States.⁹⁶

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 reference case such as, finding rates, drilling, lease equipment and operating costs, and success rates, were adjusted upward and downward by a third (Table 50), for the rapid and slow technology cases, respectively.  The approaches taken in the representation of Canadian natural gas, enhanced oil recovery, and unconventional natural gas are discussed below.  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.

Table 50.  Assumed Annual Rates of Technological Progress on Costs, Finding Rates, and Success Rates for Conventional Sources

Canadian Gas

For consistency purposes, from 2000 forward Canadian consumption and key supply results were adjusted to stimulate assumed impacts of rapid and slow oil and gas technology penetration on Canadian markets.  The exogenously specified Canadian consumption forecast was increased or decreased by a fraction (0.0020 for rapid, 0.0030 for slow) times the forecast year minus 1999, for the rapid and slow cases, respectively.  As a result, by 2020 Canadian consumption was 4.2 percent higher in the rapid technology case and 6.3 percent lower in the slow technology case.  On the supply side, the forecast for wells drilled and the associated average finding rate in the Western Canadian Sedimentary basin (WCSB) were adjusted as well.  Using a similar structure as used in adjusting consumption,  the forcasted wells were increased or decreased by 0.008 times the forcast year minus 1999, for the rapid and slow cases, respectively.  However, since the forecasted wells are function of the wellhead price and the previous year’s production level in Canada, the original valuse that are adjusted are already different in the technology cases from the reference case.  Finally, the decline in the finding rate in the WCSB (set at 2.5 percent per year in the reference case) was set at 0.5 and 3.5 percent in the rapid and slow technology cases, respectively, from 2000 forward.

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.

Table 51.  Assumed Rates of Technological Progress on Enhanced Oil Recovery Techniques

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).

Table 52.  Assumed Rates of Technological Progress for Gas Miscible EOR Methods

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 eleven 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 2000 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 eleven technology groups are presented below.  Their treatment under the different technology cases are described in Table 53.

Table 53.  Assumed Rates of Technological Progress for Unconventional Gas Recovery

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.