B
Interim Letter Report of the Panel



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B Interim Letter Report of the Panel

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NATIONAL RESEARCH COUNCIL COMMISSION ON GEOSCIENCES, ENVIRONMENT, AND RESOURCES 2101 Constitution Avenue Washington, D.C. 20418 BOARD ON EARTH SCIENCES AND RESOURCES Phone: (202) 334-2744 FAX: (202) 334-1377 February 28, 1995 Mr. Reginal W. Spiller Deputy Assistant Secretary for Gas and Petroleum Technologies U.S. Department of Energy 1000 Independence Ave., S.W. Washington, DC 20585 Dear Mr. Spiller: The National Research Council formed the Panel on the Review of the Oil Recovery Demonstration Program of the Department of Energy to respond to your request to assess the effectiveness of the Reservoir Class Field Demonstration Program 1 and to recommend improvements. The panel has been charged with addressing the following two questions: Has the Field Demonstration Program proven effective in demonstrating the application of new and existing technologies to prolong production in marginal fields? How should this program be modified to improve its effectiveness in meeting this goal? This letter report presents the panel’s findings on the first question concerning the effectiveness of the program. This report reflects a consensus of the panel and is a formal, fully reviewed report of the National Research Council. The second question will be addressed in the panel’s final report, which we hope to complete in November 1995. Members of the panel were selected to provide perspective and expertise in the areas of petroleum geology, geophysics, petroleum and reservoir engineering, and energy policy. A list of panel members is given at the end of this letter report. The panel met for two days in December 1994 and for three days in January 1995 ( Appendix A ) in the course of developing this report. During these meetings, the panel received progress reports from contractors on 12 DOE-supported demonstration projects (see Appendix B ). The contractors also provided the panel with copies of publications and reports and answered questions. In addition, DOE representatives provided briefings on the program, copies of recent quarterly project reports, and other program documents. The panel also read 1   Hereafter referred to as the Field Demonstration Program. The National Research Council is the principal operating agency of the National Academy of Sciences and the National Academy of Engineering to serve government and other organisation.

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and discussed two recent National Research Council reports regarding oil production technologies. 2 The panel’s findings are drawn from these presentations, materials, and discussions. BACKGROUND ON THE FIELD DEMONSTRATION PROGRAM Maintaining a viable domestic supply of oil and natural gas is important to the United States for both economic and strategic reasons. Income generated by the domestic oil and gas industry fuels the economy, creates jobs, and generates federal revenues from bonuses, leases, and royalties from exploration and production on offshore and onshore federal lands. 3 Domestic production also decreases U.S. dependence on imported petroleum products, which currently account for slightly more than 50% of total U.S. oil demand 4 and about 31 % of the merchandise trade deficit. 5 Further decreases in domestic production will exacerbate the trade deficit problem and increase foreign dependence for a resource that provides about 40 % 6 of the total U.S. energy supply. 2   The reports are Advanced Exploratory Research Directions for Extraction and Processing of Oil and Gas, Committee on Applied Research Needs Related to Extraction and Processing of Oil and Gas, Board on Chemical Sciences and Technology, Commission on Physical Sciences, Mathematics, and Applications, National Research Council, 1993, and Letter Report to Thomas C. Wesson, Director, Bartlesville Project Office, U.S. Department of Energy, on the Accelerated Oil Program Plan (Reservoir Characterization and Production Area), A Report to Congress, Committee on Earth Resources, Board on Earth Sciences and Resources, Commission on Geosciences, Environment, and Resources, National Research Council, 15 December 1993. 3   In 1993, revenues to the U.S. Treasury from oil and gas bonuses, leases, and royalties totaled about $3.5 billion (Minerals Management Service, Mineral Revenues 1993). 4   In 1994, domestic field production of crude oil averaged 6.63 million barrels per day (bpd); net imports (i.e., imports minus exports) of crude oil averaged 6.92 million bpd (Energy Information Administration, Monthly Energy Review, January 1995). 5   For 1994, the U.S. merchandise trade deficit totaled $168.4 billion. Imports of petroleum and petroleum products accounted for $51.5 billion of this total (U.S. Department of Commerce, Survey of Current Business, January 1995). 6   In 1993, the latest year for which complete data are available, U.S. energy consumption totaled 83.89 Quadrillion BTU (Quads), of which 33.84 Quads were supplied by petroleum—crude oil, lease condensate, and natural gas plant liquids (Energy Information Administration, Monthly Energy Review, January 1995).

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The Field Demonstration Program was initiated in 1992 as part of a broad DOE effort to counter the continuing drop in domestic oil production 7 and to slow the abandonment, because of unfavorable economics, of wells in “mature” fields that typically still contain 60% to 70% of the original oil in place. 8 DOE recognized that as major companies reduced their efforts in domestic onshore operations and shifted their emphasis to frontier areas (Alaska and offshore) and international operations, the production of oil from mature fields in the lower 48 states and the continental shelf of the United States would shift to smaller companies and independent producers, which generally lack the internal technical expertise and capital resources to undertake technically or economically risky projects. The objective of the Field Demonstration Program is to encourage the application of new technologies and more effective use of existing technologies to prolong production in marginal fields and to encourage the adoption of these technologies by the small companies, independent producers, and major companies that will comprise the domestic energy industry of the future. DOE anticipates that this program will allow industry to add about 1.5 billion barrels to domestic production by the year 2020. 9 The Field Demonstration Program is organized on the basis of reservoir classes. DOE uses the term class to denote a group of reservoirs with a similar depositional history.10 Depositional history controls the internal variability of porosity and permeability—and thus the flow of hydrocarbons—in the reservoir. DOE believes that by grouping reservoirs into 7   U.S. domestic field production of crude oil declined from 8.60 million barrels per day (bpd) in 1980 to 6.63 million bpd in 1994 (Energy Information Administration, Monthly Energy Review, January 1995). 8   In 1993, for example, there were approximately 452,000 stripper wells (wells that produce less than 10 barrels of oil per day) in the United States which accounted for about 14% of domestic production of crude oil. In the same year, about 17,000 (3.7%) stripper wells were abandoned (Interstate Oil and Gas Compact Commission, Marginal Oil: Fuel for Economic Growth, 1994), presumably due to unfavorable economics. 9   U.S. Department of Energy (Bartlesville Project Office), 1994, Oil Program Implementation Plan FY1996-2000, p. 107. 10   See, for example, U.S. Department of Energy, Program Opportunity Notice (PON), Number DEPS22-94BC14972, Class III Oil Program—Near Term Activities, p. 1-1.

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classes this internal variability can be identified and exploited using improved production strategies to increase the ultimate recovery of hydrocarbons. Twenty-two reservoir classes are recognized by DOE, 16 clastic (sandstone) and six carbonate (limestone and dolomite) classes. Classes 1, 2, and 3 (Fluvial Dominated Delta, Shallow Shelf Carbonate, and Slope and Basin Clastic Reservoirs, respectively) are thought to include the reservoir types with substantial resources from which oil recovery has been least efficient. These classes were selected for demonstration projects during the first four years of the program. Implementation of the program began in fiscal year 1992 (FY92) with the selection of 14 Class 1 (Fluvial Dominated Deltaic Reservoirs) projects (see Appendix B for a list of Class 1 and Class 2 projects). In FY93, 10 Class 2 (Shallow Shelf Carbonate Reservoirs) projects were selected for support. Nine Class 3 (Slope and Basin Clastic Reservoirs) projects were selected in FY95; awards for these projects are currently under negotiation. Projects require a minimum 50% cost share by industry and its partners and are organized into two groups: near-term, which focus on applying currently available but underutilized technologies, and mid-term, which focus on advanced technologies. Both groups of projects include a reservoir characterization element and an emphasis on technology transfer. PROGRAM COMPONENTS Reservoir Class Organization of the Field Demonstration Program on the basis of reservoir class is based on observations that oil recovery responses of reservoirs are closely related to their geologic origins. 11 The geologic origin of a reservoir controls or strongly influences its structure, geometry, and other physical and chemical characteristics, which in turn control oil production performance. Therefore, DOE believes that successful demonstrations of new or existing technologies on a given reservoir in a class should be applicable to other reservoir systems in the same class. 11   See, for example, N. Tyler and R.J. Finley, 1991, Architectural controls on the recovery of hydrocarbons from sandstone reservoirs, in A.D. Miall and N. Tyler, eds., The Three-Dimensional Facies Architecture of Terrigenous Clastic Sediments and its Implication for Hydrocarbon Discovery and Recovery, SEPM Society for Sedimentary Geology, Tulsa, Okla., Concepts in Sedimentology and Paleontology, vol. 3, pp. 1-5.

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The panel plans to examine and comment on the usefulness of reservoir class as the organizing precept for this DOE program in its final report. Demonstration of New or Existing Technologies The decline in oil prices and the reduction of domestic operations by the major oil companies have combined to decrease the application of both new and existing recovery technologies. The abandonment of oil fields, many of which still contain significant amounts of potentially recoverable oil, will preclude later access to these resources owing to the high costs of leasing, drilling, and production. By demonstrating a wide variety of new and existing technologies, the Field Demonstration Program seeks to develop the technical and economic experience necessary to encourage adoption of these technologies by independent operators, small companies, and major companies. Without the economic boost and risk sharing provided by program funding, DOE believes that, under current and projected oil prices, demonstration of these technologies is unlikely to occur in a time frame that can substantially reduce the rate of abandonment of fields containing significant amounts of recoverable oil. Technology Transfer For the Field Demonstration Program to achieve its stated objectives, the technologies developed in these demonstration projects must be transferred to the entire industry. The purpose of technology transfer is to motivate the broader application of cost-effective technologies by disseminating the knowledge, data, and techniques for solving production problems. DOE has made technology transfer a key component of each of the Field Demonstration Program projects. The primary goals of technology transfer are (1) to involve a broad base of participants in projects, including scientists and engineers from different agencies or organizations (industrial companies of all sizes, consultants, universities, state surveys, and other federal government programs), and (2) to have periodic, user-friendly reviews, demonstrations, and updates to all interested industry entities, regulators, and legislators.

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PROGRAM EFFECTIVENESS: PRESENT AND POTENTIAL Demonstrating New and Existing Technologies There is a wide range of technologies being utilized in the projects examined by the panel, including both conventional (existing) and advanced (new) technologies. Program projects targeted mobile oil and (or) immobile oil. 12 Additional mobile oil can be recovered from known fields using properly applied conventional techniques to identify and produce from untapped or uncontacted portions of compartments in the reservoir. Immobile oil can be recovered using techniques that alter the chemistry of the reservoir fluids or the interactions between these fluids and the host rock. A key technical component in most of the projects examined by the committee is reservoir characterization, that is, determination of the shape, size, internal structure, and other physical and chemical properties of the reservoir using invasive and noninvasive techniques. The projects examined by the panel employed a wide range of conventional and advanced technologies to characterize reservoirs. Conventional techniques include core and cuttings analysis, facies mapping, comparative outcrop studies, and conventional well-log analysis. Examples of advanced technologies include 3D and 4D 13 seismic analysis, tomography, advanced logging techniques (e.g., nuclear magnetic resonance logging and borehole imaging), sequence-stratigraphic modeling of flow units, and 3D geologic modeling. The projects examined by the panel also employed a wide range of conventional and advanced technologies for drilling, completion, and production. Examples of advanced technologies employed by the projects include the use of horizontal wells for injection and production, CO2 flooding, and air combustion/gravity drainage. Although many of the projects examined by the panel employed conventional technologies, these technologies were new to the geographic areas in which they were being applied, as illustrated by the following examples: 12   Mobile oil is that oil which can be moved to the well under the force of gravity, the natural pressure of the reservoir, or with the aid of conventional pressure maintenance or displacement technologies (e.g., water flooding). Immobile oil is that oil held in the rock pores by surface tension and capillary forces and is usually produced using chemical or thermal methods. 13   Three spatial dimensions and the fourth dimension of time.

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Uinta Basin (Appendix B, Project #8). Lomax Exploration Company has demonstrated that water injection can be used to increase production and prolong the life of marginal fields in the Uinta Basin. The Lomax program is projected to recover 20% of the original oil in place, versus about 4% for primary recovery without water flooding. Before this project was initiated, most operators in the area did not believe that water flooding would be economically successful. However, this project has served as a model for five other water floods in the area. N.E. Savonburg Field, Kansas (Appendix B, Project #11). The University of Kansas and James Russell Petroleum Company introduced reservoir simulation technology and water treatment processes for water flooding to improve production from a Pennsylvanian reservoir in eastern Kansas. The technology is expected to find application to other reservoirs in this region. Several of the projects reviewed by the panel also utilized advanced technologies, for example: West Hackberry Field (Appendix B, Project #2). Amoco is utilizing double displacement technology for tertiary production from the West Hackberry Field. This process utilizes air injection near the top of a water-invaded oil column. This injection causes combustion of a small amount of the oil in the reservoir, thereby producing flue gases and steam to mobilize the residual oil, which is recovered by gravity drainage. Eugene Island Block 330 Field (Appendix B, Project #5). This Columbia University project has developed an improved time-dependent seismic imaging (4D seismic imaging; see footnote 13) methodology that can be used to monitor changes to the reservoirs during production. In the panel’s judgment, the projects examined employ an appropriate range of both conventional and advanced technologies in the areas of reservoir characterization, drilling, well completion, and production. Although different projects use different subsets of the available technologies, the panel believes that the technologies are used appropriately and are representative of the range of conventional and advanced technologies employed by industry.

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Prolonging the Lives of Marginal Fields A number of the technologies utilized by projects in this DOE program have the potential to prolong the lives of marginal oil fields by increasing the rate of production and (or) the total amount of recovered oil. Examples of such technologies are indicated in Appendix C. Based on reviews of 12 of the 24 Class 1 and Class 2 projects in this program (Appendix B), the panel judges that many of the projects will eventually be successful in demonstrating improved oil production. However, most projects are at an early stage of development and have not had sufficient time to demonstrate commercial success, except for the Uinta Basin project (Appendix B, Project #8), which was briefly described in the previous section. Other projects that are likely to be successful in demonstrating prolonged production include the following: Bluebell Field (Appendix B, Project #14). Reservoir modeling by the Utah Geological Survey (UGS) has demonstrated that much of the production at Bluebell Field is from fractures, and the UGS showed that fractures can be identified using advanced logging tools (i.e., formation microscanning imaging logs). This project will likely lead to changes in completion practices to reduce completions in unproductive zones and thereby to increase production and prolong the life of this field. Welch and South Cowden Fields (Appendix B, Projects 20 and 21). CO2 floods are important for prolonging production in many carbonate reservoirs. However, the economics of CO2 flooding are poor for many fields. DOE-supported projects in the Welch and South Cowden Fields show promise for prolonging production using more effective CO2 flooding technologies. In the Welch Field, the OXY consortium is utilizing cyclic CO2 flooding to increase production and lower cost. In the South Cowden Field, the Phillips consortium is attempting to demonstrate CO2 injection via horizontal wells to significantly decrease the cost of CO2 flooding. West Hackberry Field (Appendix B, Project #2). The Amoco air injection program at West Hackberry Field has promise of recovering residual oil in steeply dipping formations commonly associated with salt domes. If successful, this technique could find widespread application in the Gulf Coast region. The panel judges the likelihood of future success of these technologies in prolonging the life of marginal fields to be high. This judgment is based both on examination of the 12 projects indicated in Appendix B and on previous studies which show that the types of

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approaches and technologies being applied here have been used elsewhere to increase oil production in marginal fields. 14 Technology Transfer The primary goal of technology transfer is to spread the use of technologies and approaches that are developed and applied during the demonstration projects to other fields within the same plays, 15 more broadly to fields within the same classes of reservoirs, and to fields in other classes where applicable. Various methods of accomplishing this goal are employed by the projects. Collectively, the funded projects are using conventional procedures in transferring project information to the other potential users. These include the following: publications, including refereed papers, proceedings of professional meetings, trade journals, newsletters, and the popular press; databases (printed and electronic formats), technical progress reports, electronic bulletin boards, open-file reports, and videos; technical meeting presentations, including displays, oral presentations, and poster papers; workshops, project site visits, short courses, and special topical meetings (e.g., geologic reservoir characterization, reservoir engineering, seismic interpretation); and 14   For example, the Bureau of Economic Geology (BEG), University of Texas at Austin has demonstrated that integrated geological and engineering characterization can lead to significant increases in oil production from marginal fields. See Integrated Characterization of Permian Basin Reservoirs, University Lands, West Texas, BEG Report of Investigations No. 203, 136 pp., 1991, and Analysis of Production Response to Advanced Characterization of University Lands Reservoirs, BEG, 1992, 16 pp. 15   A play is a set of oil and gas accumulations that share similar geologic, geographic, and temporal properties, including source rocks, migration pathways, trapping mechanisms, and hydrocarbon types.

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personal commitments by investigators to informally communicate results to colleagues. Each of the projects reviewed by the panel contains a technology transfer plan, and the contractors appear to recognize the importance of the plan to the overall success of their projects. However, there is considerable variation in the procedures being used in each project. Because the projects are at an early stage of development, the overall effectiveness of technology transfer is difficult to evaluate. At present, however, these efforts appear to be satisfactory. In the panel’s judgment, the effectiveness of technology transfer could be improved by the organization of regional workshops implemented by DOE. At such workshops, the results of individual demonstration projects would be presented to industry active in the same producing basin or in other similar basins nationwide. The panel plans to investigate and report on possible mechanisms for such exchange in its final report. FINDINGS AND FUTURE WORK Based on information reviewed to date, it is the judgment of the panel that the DOE Field Demonstration Program is proving effective in demonstrating the application of new and existing technologies to prolong the lives of marginal fields. However, it is too early to determine whether this program will be ultimately successful in reducing the rate of abandonment of marginal wells or slowing the decline of domestic oil production. The panel will attempt to address the likelihood of success in its final report. In the panel’s view, the emphasis on reservoir characterization and technology transfer is appropriate and needs continuing attention by DOE to ensure that effective levels of both are maintained throughout the program. The effectiveness of the program is enhanced by the large number and variety of participants, the geographic diversity of the projects, and the requirements for a 50% match, which ensures a commitment to obtaining results that lead to the practical outcomes that benefit both industry and the nation, namely increased domestic oil production. The panel has determined that review of additional projects is necessary to obtain a more representative sample of the program and will accomplish this in its future meetings.

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On the basis of discussions with DOE managers and contractors during the first two meetings, the panel has determined that four topics need focused attention as it continues its work to address the second charge of the study: (1) proposal review and project selection process, (2) length of the contracting process, (3) reservoir class as the organizing precept for the program, and (4) effectiveness of the technology transfer process. Discussions and recommendations regarding these topics will be included among those presented in the final report. Sincerely, Charles G. Groat, Chair Panel on the Review of the Oil Recovery Demonstration Program of the Department of Energy Other Members of the Panel: Arthur Cheng, Massachusetts Institute of Technology James A. Drahovzal, Kentucky Geological Survey George J. Hirasaki, Rice University Neil F. Hurley, Marathon Oil Company Randi S. Martinsen, University of Wyoming Charles S. Matthews, retired Arthur Saller, Unocal Corporation Robert J. Weimer, Colorado School of Mines W. Frank West, PACO Minerals, Dallas

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APPENDIX A List of Presenters Panel on the Review of the Oil Recovery Demonstration Program of the Department of Energy Meeting #1: December 13-14, 1994 (Houston, Texas) Edith Allison, U.S. Department of Energy: Overview of the Reservoir Class Oil Recovery Program Noel Tyler, Bureau of Economic Geology, The University of Texas at Austin: History of the Reservoir Class Program and the Definition of Classes Mark Holtz and Lee McRae, Bureau of Economic Geology, The University of Texas at Austin: Revitalizing Mature Oil Plays in Frio Reservoirs of South Texas Scott Hickman, Hickman and Associates; Archie Taylor, OXY USA; and Jim Justice, Advanced Research Technology: Application of Reservoir Characterization and Advanced Technology to Improve Recovery and Economics in Lower-Quality Shallow-Shelf San Andres Reservoirs Charles Mankin, Oklahoma Geological Survey: Identification and Evaluation of Fluvial-Dominated Deltaic Reservoirs Larry Hallenbeck and Don Wier, Phillips Petroleum Company: Design and Implementation of a CO2 Flood Utilizing Advanced Reservoir Characterization and Horizontal Injection Wells in a Shallow-Shelf Carbonate Approaching Waterflood Depletion—Class II Sami Bou-Mikael, Texaco E&P: Post Waterflood CO2 Miscible Flood in Light Oil Fluvial-Dominated Deltaic Reservoirs Travis Gillham, Ed Turek, and Reza Fassihi, Amoco Production Company: West Hackberry Tertiary Project

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February 28, 1995 Meeting #2: January 17-19, 1995 (Washington, DC) Reginal W. Spiller, U.S. Department of Energy: DOE Perspectives on the Fossil Energy Programs Roger Anderson and Lana Billsaud, Lamont Doherty Earth Observatory, Columbia University; Larry Cathles, Cornell University; and Peter B. Flemings, Pennsylvania State University: Dynamic Enhanced Recovery Technologies M. Lee Allison, Utah Geological Survey: Developing Improved Completion Techniques in the Bluebell Field, Plus Aspects of Class II and III Projects John Lomax, Lomax Exploration Company; and Miland D. Deo, University of Utah: Green River Formation Water Flood Demonstration Project Don W. Green, Tony Walton, and Paul Willhite, University of Kansas: Improvement of Oil Recovery in Fluvial-Dominated Deltaic Reservoirs in Kansas (Class I), and Improved Oil Recovery in Lower Meramecian (Mississippian) Carbonate Reservoirs of Kansas (Near-Term, Class II)

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February 28, 1995 APPENDIX B List of Class 1 and Class 2 Projects Project Number Reservoir and (or) Basin Name Contractor Reservoir Class 1* Mattoon Oil Field (Illinois) American Oil Recovery, Inc. 1 2† West Hackberry Field (Louisiana) Amoco Production Company 1 3* Black Warrior Basin (Alabama) Anderman/Smith Operating Company 1 4† Frio Formation (Texas) Texas Bureau of Economic Geology 1 5‡ Eugene Island Block 330 Field (Gulf of Mexico) Columbia University 1 6 Sooner-Unit Field (Colorado) Diversified Operating Corporation 1 7 North Blowhorn Creek Field, Black Warrior Basin (Alabama) Hughes Eastern Corporation 1 8‡ Green River Formation, Uinta Basin (Utah) Lomax Exploration Company 1 9 Badger Basin Field (Wyoming) Sierra Energy Company 1 10† Port Neches Field (Texas) Texaco Exploration and Production,Inc. 1 11‡ N.E. Savonburg & Stewart Fields (Kansas) University of Kansas Center for Research 1 12† Fluvial-Dominated Deltaic Reservoirs in Oklahoma Oklahoma Geological Survey 1

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Project Number Reservoir and (or) Basin Name Contractor Reservoir Class 13 Glenn Pool Field (Oklahoma) University of Tulsa 1 14‡ Bluebell Field, Uinta Basin (Utah) Utah Geological Survey 1 15 Anadarko Basin (Nebraska) Sensor (formerly Beard) 2 16 Clearfork Reservoir (Texas) Fina Oil and Chemical Company 2 17 Foster and South Cowden Fields, Grayburg/San Andres Formations (Texas) Laguna Petroleum Company 2 18 Williston Basin Carbonates Luff Exploration Company 2 19 Crystal Field, Dundee Reservoir (Michigan) Michigan Technological University 2 20† Welch Field, San Andres Formation (Texas) Oxy USA, Inc. 2 21† South Cowden Field, Grayburg/San Andres Formations (Texas) Phillips Petroleum Company 2 22 Central Vacuum Unit (New Mexico) Texaco Exploration & Production, Inc. 2 23‡ Schaben and Bindley Fields (Kansas) University of Kansas Center for Research 2 24‡ Paradox Basin (Utah) Utah Geological Survey 2 * Project has been terminated. † Presentations were made to the committee by the contractor at the December 1994 meeting. ‡ Presentations were made to the committee by the contractor at the January 1995 meeting.

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APPENDIX C Examples of Technologies that Could Prolong the Lives of Marginal Fields Waterflooding Green River Formation, Uinta Basin (Lomax Exploration Company) N.E. Savonburg and Stewart Fields (University of Kansas Center for Research) Glenn Pool Field (University of Tulsa) Infill Drilling/Waterflooding Sooner-Unit Field (Diversified Operating Corporation) Williston Basin Carbonates (Luff Exploration Company) Foster and South Cowden Fields (Laguna Petroleum Company) Clearfork Reservoir (Fina Oil and Chemical Company) Well Completion Practices Bluebell Field, Uinta Basin (Utah Geological Survey) Horizontal Wells Crystal Field, Dundee Reservoir (Michigan Technological University) South Cowden Field (Phillips Petroleum Company) Biological Treatments Black Warrior Basin (Hughes Eastern) Green River Formation, Uinta Basin (Lomax Exploration Company) CO2 Injection Port Neches Field (Texaco Exploration and Production Company) West Welch Field (OXY USA, Inc.) South Cowden Field (Phillips Petroleum Company) Paradox Basin (Utah Geological Survey) Central Vacuum Unit (Texaco Exploration and Production Company) Air Injection West Hackberry Field (Amoco Production Company)

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