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DOE/EIA-0554(2001) Report
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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(2001), (Washington, DC, January 2001). 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, 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 adjustments to the deep resources in the Gulf of Mexico are made based on estimates in a report to 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 52 and 53 reflect the removal of intervening reserve additions between the dates of the USGS (1/1/94) and MMS (1/1/95) estimates and 1/1/99. Table 52. Crude Oil Technically Recoverable Resources Table 53. 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-2009 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 2009 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 $4.06 in 1999 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 $5.44, in 1999 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. Although other options have been proposed for Alaska North Slope gas, including gas-to-liquids (GTL), liquefied natural gas (LNG), and transportation to the lower-48 via pipeline systems other than ANGTS, these options are not at present included in the NEMS. 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 2009, at an average historical level of 57.3 billion cubic feet per year. In all cases, it is assumed that in 2010 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 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 6.8 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 and are constrained by pipeline capacities. Exogenously specified projections of pipeline import and export values from Canada and Mexico are shown in Table 54. Table 54. 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 are shown in Table 55. 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 1.8 percent. Table 55. Exogenously Specified Canadian Production and Consumption Annual U.S. exports of LNG are assumed to be a constant at 64.5 billion cubic feet in each year after 2000. 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. 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. Maximum sustainable LNG import capacity at these two facilities in 1999 is assumed to be 352 billion cubic feet. Two additional facilities, one at Cove Point, Maryland and the other at Elba Island, Georgia, currently mothballed, are assumed to reopen in 2003, adding an additional 529 billion cubic feet of sustainable capacity. It is further assumed that according to announced plans, Elba Island will receive one to two shipments (less than 5 bcf) to test the facility prior to fully reactivating it. 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. Launch Coalbed Methane Outreach Program The natural gas production forecasts incorporate the expected results of the Launch Coalbed Methane Outreach Program (LCMOP). Under the LCMOP, 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 56. Table 56. Production from Mines Reached by the LCMOP The annual production increases resulting (linear interpolations for interim year) from the LCMOP 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 High and Low Resources Cases To demonstrate the sensitivity of the underlying oil and gas resource base on the AEO2001 results, high and low resource cases were created by simply adjusting the oil and gas resource base a percentage across all regions. As in the other AEO2001 cases, resources in areas restricted from exploration and development are not included in the resource base. For conventional onshore and offshore resources, both the undiscovered technically recoverable resource and the inferred reserve estimates were adjusted plus or minus 20 percent. Even more uncertainty surrounds the estimates for unconventional gas resources, so the unproved resource estimates for unconventional gas recovery was adjusted plus or minus 40 percent in the high and low resource cases. Thus, the assumed level of technically recoverable natural gas resources are 1,583 trillion cubic feet in the high resource case and 979 trillion cubic feet in the low resource case compared to 1,281 trillion cubic feet in the reference case. Technically recoverable crude oil resources are 165 billion barrels in the high resource case, 144 billion barrels in the reference case, and 122 billion barrels in the low resource case. The recoverable volumes for these cases were specified to exhibit significant variation in this key assumption without exceeding a reasonable range. Results of the high and low resource cases should not be construed as extreme cases that are expected to bound most, if not all, feasible projections. 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 57), 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 1.8 percent per year in the reference case) was set at 0.9 and 2.7 percent in the rapid and slow technology cases, respectively, from 2000 forward. 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 58. Table 58. 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 59). Table 59. 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 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 2001 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 60. Table 60. 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.
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