[Report#:DOE/EIA-0581(2000)]
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The oil and gas supply module (OGSM) consists of a series of process submodules that project the availability of:
The OGSM regions are shown in Figure 12. Figure 12. Oil and Gas Supply Module Regions The driving assumption of OGSM is that domestic oil and gas exploration and development are undertaken if the discounted present value of the recovered resources at least covers the present value of taxes and the cost of capital, exploration, development, and production. In contrast, international gas trade is determined in part by scenario-dependent, noneconomic factors. Crude oil is transported to refineries, which are simulated in the petroleum market module, for conversion and blending into refined petroleum products. The individual submodules of the oil and gas supply module are solved independently, with feedbacks achieved through NEMS solution iterations (Figure 13). Figure 13. Oil and Gas Supply Module Structure Technological progress is represented in OGSM through annual increases in the finding rates and success rates, as well as annual decreases in costs. For conventional onshore and shallow offshore, this is accomplished in several ways. While the OGSM methodology assumes that increases in cumulative drilling lower the finding rate, the methodology permits this decline to be partially, fully, or more than fully offset by improvements in technology. This “technological stretch” effect is represented by an assumed upwards shift in the finding rate function at the end of each forecast year. Another representation of technology is in the success rates for exploratory wells, which are assumed to increase annually by a given constant percentage due to technological progress. Technology is further represented in this part of the model on the cost side by the existence of time-trend proxy coefficients in the cost equations. These coefficients are intended to capture the beneficial (cost-reducing) effects of technology by putting downward pressure on the drilling, lease equipment, and operating cost projections. For unconventional gas, a series of eleven different “technology groups” are represented by time-dependent adjustments to factors which influence finding rates, success rates, and costs. Lower 48 Onshore and Shallow Offshore Supply Submodule The lower 48 supply submodule projects oil and gas production by conventional recovery methods in onshore and shallow offshore regions and unconventional gas recovery in onshore regions. Unconventional gas is defined as gas produced from nonconventional geologic formations, as opposed to conventional (sandstones) and carbonate rock formations. The three nonconventional geologic formations considered are low-permeability or tight sandstones, gas shales, and coalbed methane. Enhanced oil recovery from onshore regions is handled separately. The lower 48 submodule actually consists of three separate components: onshore lower 48 conventional oil and gas supply, offshore oil and gas supply, and unconventional gas recovery supply. The lower 48 submodule accounts for drilling, reserves estimates, and production capacity—computed independently (for the most part) for each region (6 onshore and 3 offshore) by well class (exploratory and developmental) and fuel category (conventional oil, conventional shallow gas, conventional deep gas, and unconventional gas). Oil and Gas Supply Module Table For conventional onshore and shallow offshore, the procedure is as follows:
For unconventional gas, a play-level model calculates the economic feasibility of individual plays based on locally specific wellhead prices and costs, resource quantity and quality, and the various effects of technology on both resources and costs. In each year, an initial resource characterization determines the expected ultimate recovery (EUR) for the wells drilled in a particular play. Resource profiles are adjusted to reflect assumed technological impacts on the size, availability, and industry knowledge of the resources in the play. Subsequently, prices received from NGTDM and endogenously determined costs adjusted to reflect technological progress are utilized to calculate the economic profitability (or lack thereof) for the play. If the play is profitable, drilling occurs according to an assumed schedule, which is adjusted annually to account for technological improvements, as well as varying economic conditions. This drilling results in reserve additions, the quantities of which are directly related to the EURs for the wells in that play. Given these reserve additions, reserve levels and “expected” production-to-reserves (P/R) ratios are recalculated at both the OGSM and the NGTDM region level. The resultant values are aggregated with similar values from the conventional onshore and shallow offshore submodule. The aggregate P/R ratios and reserve levels are then passed to NGTDM, which determines the prices and production for the following year through market equilibration. Deep Water Offshore Supply Submodule This submodule uses a field-based engineering and economic analysis approach to project reserve additions and production from resources in the deep water offshore Gulf of Mexico Outer Continental Shelf subregion. Two structural components make up the deep water offshore supply submodule, an exogenous price/ supply data generation routine and a endogenous reserves and production timing algorithm. The price/supply data generation methodology employs a rigorous field-based DCF approach. This offline model utilizes key field properties data, algorithms to determine key technology components, and algorithms to determine the exploration, development and production costs, and computes a minimum acceptable supply price (MASP) at which the discounted net present value of an individual prospect equals zero. The MASP and the recoverable resources for the different fields are aggregated by planning region and by resource type to generate resource-specific price-supply curves. In addition to the overall supply price and reserves, costs components for exploration, development drilling, production platform, and operating expenses, as well as exploration and development well requirements, are also carried over to the endogenous component. After the exogenous price/supply curves have been developed, they are transmitted to an endogenous algorithm. This algorithm makes choices for field exploration and development based on relative economics of the project profitability compared with the equilibrium crude oil and natural gas prices determined by the petroleum market module and natural gas transmission and distribution module. Development of economically recoverable resources into proved reserves is constrained by drilling activity. Proved reserves are translated into production based on a P/R ratio. The drilling activity and the P/R ratio are both determined by extrapolating the historical information. Alaska Oil and Gas Submodule This submodule projects the crude oil and natural gas produced in Alaska. The Alaska oil and gas submodule is divided into three sections: new field discoveries, development projects, and producing fields. Oil and gas transportation costs to lower 48 facilities are used in conjunction with the relevant market price of oil or gas to calculate the estimated net price received at the wellhead, sometimes called the “netback price.” A discounted cash flow method is used to determine the economic viability of each project at the netback price. Alaskan oil and gas supplies are modeled on the basis of discrete projects, in contrast to the onshore lower 48 conventional oil and gas supplies, which are modeled on an aggregate level. The continuation of the exploration and development of multiyear projects, as well as the discovery of new fields, is dependent on profitability. Production is determined on the basis of assumed drilling schedules and production profiles for new fields and developmental projects, historical production patterns, and announced plans for currently producing fields. Enhanced Oil Recovery (EOR) Supply Submodule The enhanced oil recovery supply submodule (EORSS) is designed to project regional oil production in the onshore lower 48 States extracted by use of advanced tertiary recovery techniques, in excess of the oil recovered by primary and secondary techniques. The model represents the two principal technologies separately — thermal methods and miscible/immiscible (or gas) methods. EORSS employs a reservoir-based, field-level engineering, rather than statistical, computational methodology. However, the basic process for both EOR and the other sources of crude oil and natural gas consists of essentially the same stages. The physical stages of the supply process involve the conversion of unproven resources into proved reserves, and then the proved reserves are extracted as flows of production. The significant differences between the methodology of EORSS and the other submodules of OGSM concern the conversion of unproven resources to proved reserves, the extraction of proved reserves for production, and the determination of supply activities. EORSS uses discovery factors that convert a specified fraction of unproven resources into proved reserves. These factors depend on the expected profitability of EOR investment opportunities. Greater expected financial returns motivate the conversion of larger fractions of the resource base into proved reserves. This is consistent with the principle that funds are directed toward projects with relatively higher returns. Given the role of the discovery factors in the supply process, the implicit working assumption is that EOR investment opportunities with positive expected profit will attract sufficient financial development capital. The exploitation of economic EOR resources without an explicit budget constraint is consistent with the view that EOR investment does not compete directly with other oil and gas opportunities. This assumption is considered acceptable because EOR extraction is unlike the other oil and gas production processes, and its product differs sufficiently from the less heavy oil most often yielded by conventional projects. For each forecast year, the remaining EOR proved reserves that continue to be economic are determined for each OGSM region. Production from a given stock of proved reserves is determined by the application of an assumed production-to-reserves ratio. The methodology used for determining end-of-year proved reserves for thermal production in the West Coast OGSM region is more detailed than that used for the thermal and gas EOR in the other OGSM regions because it is a much larger EOR producing region, with more extensive field-specific data available. Foreign Natural Gas Supply Submodule The foreign natural gas supply submodule establishes proved reserves in the Western Canadian Sedimentary Basin (WCSB), natural gas trade via pipeline with Mexico, as well as liquefied natural gas (LNG) trade. The receiving regions for foreign gas supplies correspond to those of the natural gas integrating framework established for NGTDM. Within NGTDM, pipeline natural gas imports flow from two sources: Canada and Mexico. U.S. natural gas trade with Canada is represented by seven entry/exit points, and trade with Mexico is represented by three entry/exit points (Figure 14). Figure 14. Foreign Natural Gas Trade via Pipeline and Liquefied Natural Gas Terminals OGSM provides NGTDM with the beginning-of-year natural gas proved reserves from the WCSB and an associated expected production-to-reserve ratio. NGTDM uses this information to establish a short-term supply curve for the region. Along with exogenously specified forecasts for exports of gas to Canada, other Canadian supplies, and Canadian consumption, this supply curve is used to determine the wellhead gas production and price in the WCSB and the level and price of imports from Canada at the seven border crossings. Based on the WCSB gas wellhead price, OGSM forecasts drilling activity in the WCSB using an econometrically derived equation, along with the associated reserve additions. The finding rate is set at an historical average level and assumed to decline throughout the forecast. The reserve additions are added to the beginning-of-year proved reserves from the current forecast year, after the forecasted production levels are subtracted, to establish the beginning-of-year proved reserves for the next forecast year. Mexican gas trade is a highly complex issue. A range of noneconomic factors influences, if not determines, flows of gas between the United States and Mexico. The uncertainty is so great that not only is the magnitude of flow for any future year in doubt, but also the direction of flow. Reasonable scenarios have been developed and defended in which Mexico may be either a net importer or exporter of hundreds of billions of cubic feet of gas by 2020. The vast uncertainty and the importance of noneconomic factors in future Mexican gas trade with the United States suggest that these flows should be handled on a scenario basis. Such a scenario can be introduced into the Mexican gas submodule as a user-specified path of future Mexican imports and exports. Otherwise, the analysis uses a prespecified default outlook for Mexican trade, drawn from an assessment of current and expected industry and market circumstances, as indicated in industry announcements or articles and reports in relevant publications. The outlook, regardless of its source, is fixed and is not responsive to energy price changes. The volume of LNG imports into the United States is projected at four LNG terminals. Imported LNG costs compete with the purchase price of gas prevailing in the vicinity of the import terminal. This is a significant element in evaluating the competitiveness of LNG supplies, since LNG terminals vary greatly in their proximity to domestic producing areas. Terminals close to major consuming markets and far from competing producing areas may provide a sufficient economic advantage to make LNG a competitive gas supply source in some markets. In addition to costs, extensive operational assumptions are required to determine LNG imports. Dominant general factors affecting the outlook include expected developments with respect to the use of existing capacity, expansion at existing sites, and construction at additional locations. The LNG forecast also requires the specification of a combination of factors: available gasification capacity, schedules for and lags between constructing and opening a facility, tanker availability, expected utilization rates, and worldwide liquefaction capacity. For inactive terminals, it is necessary to determine the length of time required to restart operations, normally between 12 and 18 months. These considerations are taken into account when the economic viability of LNG supplies is determined. The model accounts for LNG exports to Japan from Alaska using an exogenously-specified forecast. |
