0M a n a g e m e n t Why Change? P e t roleum exploration and production is enjoying a "golden age" in technology. Over the past two decades, finding costs have fallen more than threefold and lifting costs by half or better (EIA, 1998). Three-dimensional seismic has improved exploration success rates by as much as 90% and development success rates by 30% (Bohi, 1997). Yet, at the same time, the re t u rn on net assets by the largest U.S.-based companies in the E&P sector has averaged 7% for both integrated majors and large independents. (Original analysis based on Simpson et al., 1999). This re t u rn is the result of projects selected because they all exceeded the minimum estimated internal rate of re t u rn "hurdle rates," generally set at 15% or more, and were all financed with capital that generally costs in the range of 9-12% or more. This would appear to indicate long-term destruction of shareholder value. The re c e n t period of high oil and gas prices has ameliorated these results but not enough to offset the long-term tre n d .

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

Summary Tax incentives, price supports, and technology advances can all stimulate reserve additions from EOR. This paper estimates incremental EOR reserves and their direct impacts on the treasuries of the incentive-granting government and on the public sector in general as a function of these three policy variables. New Mexico, Oklahoma. and the U.S. as a whole are examined by detailed reservoir-by-reservoir technological and economic analyses. The evaluations rely on methods developed by the Natl. Petroleum Council (NPC) and are conducted for a large. representative sample of the reservoirs in the U.S. The major findings include the following:at oil prices below $28/bbl [$176/m3]. tax incentives result in significant incremental EOR reserves and at lower prices are necessary to make EOR viable;if properly designed. incentives can stimulate enough new projects to yield a net "profit" to both the public sector and the incentive-granting government;incentives granted by one level of government benefit the other level at no cost;incentives to the point of project "payback" are always more cost-effective than incentives for the project life;technology advances resulting from focused public and private R and D synergistically amplify tax-incentive effects, making both highly cost-effective; andthe combination of tax incentives and technology advances can add significantly to the U.S. oil reserves by effectively reducing the oil price required to support many future EOR projects. Introduction The U.S. will abandon in known reservoirs an amount of oil nearly 12 times its current proved reserves. At the end of 1985, the U.S. had produced 139 billion bbl [22.1 X 10-m3] of oil and had proved reserves of approximately 28 billion bbl [4.4 X 10-m3]. Nearly 325 billion bbl [51.7 X 109 m3], or two-thirds of the oil ever discovered in the U.S., will remain in reservoirs because of the absence of technologies that can produce this resource economically (Fig. 1). Of this unrecovered oil, 70% is held in reservoir rock by viscous and capillary forces and cannot be mobilized by conventional recovery techniques. This resource is the target for EOR. At current low oil prices, relatively untested recovery techniques like EOR may not provide adequate financial incentive for operators to justify the cost and risk associated with these methods. The objective of this paper is to investigate the potential of reserve additions by EOR through properly designed tax incentives and focused R and D, either of which could have the same effect as higher oil prices on EOR investment. Both state (New Mexico and Oklahoma) and federal incentives are examined. The tax incentives analyzed in this study include reduced production and corporate income taxes on the state level and the reinstated percentage-depletion allowance on the national level. Advances in EOR technology through R and D include potential improvements in process performance, cost, and predictability over currently implemented methods that are likely to become available over the next decade if R and D is pursued aggressively. The principal dependent variables presented in this paper are incremental EOR reserves and direct revenues and costs to the state and federal governments. No estimates of revenues from indirect economic activities are included. Approach Methodology. In 1984, the NPC mounted a 2-year effort to analyze EOR potential in the U.S. Experts from all pans of industry, university, government. and private nonprofit organizations contributed. This effort resulted in the development of an analytical system that is now called the Tertiary Oil Recovery Information System (TORIS). The Bartlesville Project Office of the U.S. DOE currently maintains and operates TORIS. The system consists of a detailed data base containing rock and fluid properties and production and injection information for nearly 3,500 individual reservoirs, representing about 74% of the oil discovered in the U.S. The system's analytical capability includes screening. process. and economic models for various EOR techniques. This study analyzes gas-miscible (CO2 and N2), thermal (steamdrive and in-situ combustion), and chemical (polymer, alkaline and micellar/polymer flooding) EOR processes. The TORIS screening models examine key reservoir and fluid properties to identify which reservoirs are technically amenable to the respective TORIS processes. Parameters examined with TORIS include oil gravity, insitu oil viscosity, formation depth, net pay thickness, formation temperature, matrix porosity, effective permeability, reservoir pressure, formation-water salinity, and lithology. Ref. 1 gives a more detailed description of the screening criteria. Given the applicability of a specific EOR technique, the process models predict incremental EOR production in each reservoir as a function of critical reservoir and fluid properties, conventional recovery efficiency, and process design at the level of a single pattern. Pattern performance is then scaled up to the entire reservoir in the economic models by use of pattern-development schedules appropriate to the process for individual projects. The economic models estimate the discounted net present value of revenues (oil and gas). investments, operating costs, and state. local, and federal taxes as a function of process design and performance. Projects that meet the minimum real rate of return assumed to stimulate investor interest are carried forward to the final analysis. When two or more EOR techniques are projected to be economically viable for the same reservoir, the model selects for implementation the process with the highest incremental recovery. Finally, the analysis aggregates the results for individual projects to the state or national totals. Separate analyses are conducted to estimate systematically the effects of variations in the level of technology performance and tax treatments across a range of oil prices. All results are reported at real (inflation-adjusted) 1986 oil prices. Costs associated with the application of EOR are adjusted to be consistent with the oil prices used in the analysis on the basis of the energy-related component of these costs. Scope of the Analysis. This study analyzed 97 New Mexico reservoirs (81 % of the state's known oil in place), 129 Oklahoma reservoirs (70%). and more than 3,500 reservoirs for the U.S. as a whole (74%). The results presented include only those reservoirs that were analyzed explicitly; no extrapolations were made to reservoirs not included in the data base. The analyses are presented for three oil prices: $20, $24, and $28/bbl [$126, $151, and $176/m3]. At each oil price, two technology levels, "implemented" and "advanced," are analyzed. The implemented technology reflects the applicability and level of performance of the respective EOR processes used routinely today. The advanced technology is the likely improvement in process performance and applicability that can be achieved within the next decade if a focused R and D program is successfully concluded. The detailed definitions of the two levels of technology were taken from the earlier NPC study.

As gas storage facilities become more a marketing tool and less a pipeline operational tool the criteria for using storage will change. A comprehensive Storage Reservoir Performance Model (SRPM) has been developed which can be used as an effective screening tool to characterize the performance potential of gas storage prospects. The purpose of SRPM is to provide an analytical tool for the evaluation of storage reservoir performance under alternative economic, technology and market conditions. The model is capable of evaluating existing gas storage performance for a specific production and injection schedule, which is derived from the working gas volume and peak rate requirements. The model can also evaluate the potential of new storage projects at a level of detail, sufficient to permit an integrated, geology/engineering/economic assessment for a variety of technology and operational scenarios. A basic engineering type curve approach, modified from evaluation methods used in classical well test analysis, predicts both gas injectivity and deliverability in storage reservoirs. The model consists of various modules that are linked together to perform reservoir-level prediction performance calculations for depleted gas reservoirs, aquifers and salt dome caverns. Operating cost algorithms have been developed to predict compression, injection, production and processing costs over time. An economics module permits the evaluation of gas storage capital costs and injection/production costs (rather than development and production costs alone), as well as an income stream based on service charges related to storage (rather than gas sales revenue alone). Various screening criteria were devised and used in bracketing the range of reservoir and non-reservoir properties deemed reasonable for storage project implementation or expansion. A database of reservoir rock and fluid properties was developed for approximately 400 existing and 140 proposed storage sites that were screened using these criteria. The model can be applied to these reservoirs to assess their potential performance under various technology and economic scenarios. Hence, the model is capable of addressing various research and development needs to enhance the performance of gas storage projects to meet market demand. This storage model is an integral part of the Gas Systems Analysis Model (GSAM) developed under the sponsorship of the US Department of Energy. Introduction Recent changes within the natural gas industry, brought about by regulatory changes and market forces, have created a business environment that requires gas producers, marketing companies, and consumers to create and maintain gas supply and delivery systems to meet regional, local, and market-specific requirements. Historically gas storage was an integral part of pipeline operations used to maintain pipeline flow and to meet the specific demands of gas customers. As gas marketers, distributors, and customers assume more and more responsibility to secure gas supplies and transportation capacity, storage becomes increasingly important to them for maintaining supply as well as deliverability at a competitive price. The function of storage has hence changed from strictly an operational facility to a business center (frequently associated with market hubs) that can affect the supply/demand balance and ultimately the price of natural gas. Gas storage facilities were, at first, located only at the demand-ends of the pipelines.

This report was based on the information made available from public files and personal contacts with the operators who conducted the tests reported herein. The Brashear Group LLC makes no warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefidness of any tiormatio~apparatus, producg or process disclosed, or represents that its we would not inilinge privately-awarded rights. References herein to any specific commercial product process, or service by trade name, trademark, mantiacturer, or otherwise does not necessarily constitute or imply its endorsement recommendation or favoring by The Brashear Group LLC or any employee or subcontractor thereof. The views and opinions expressed are those of the authors. Ms. Rhonda Lindsey (Technology Manager fio Drilling and Demonstrations) assisted by Mr. James Barnes (Project Manager), both of the National Petroleum Technology Office of the U.S. Department of Energy, oversaw this project reported in this report and the latter portions of the program it analyses. The project is an independent analysis of twenty-two cost-shared projects carried out by small independents. It was supported under Subcontract No. DE-AC75-98SW43 123-1 between The Brashear Group and RMC Incorporated, under its contract with DOE/Southwestem Power Administration. For the Brashear Group, Walter B. North was the primary analy~personally petiorming the bulk of the data compilation analysis and reporting. He was assisted by Charles P. Thomas, Alan B. Becker (Modern Energy Concepts, Inc.