AndreaBozzo/ceres-open-data-index huggingface dataset:
Well Log Analysis in the Cretaceous Gas Sands of Northern Montana

The fact that the responses of Neutron and Density logs in gas-bearing formations differ from those in oil- and water-bearing formations has prompted the acceptance of these logs in many areas as standard for the analysis of clean or shaly gas sands. Using these two logs, along with Gamma Ray and Resistivity logs, the various permeable beds in a well can be accurately evaluated. One approach to gas-sand interpretation, which can be done at the well site, involves a plot of the log data on ordinary graph paper. For each level the difference, apparent porosity from the Neutron log minus apparent porosity from the Density log, is plotted versus the reading of the Gamma Ray log. If there are known water-bearing levels and gas-bearing levels within the beds of interest or within the same geological interval, then a liquid line can be determined on the plot. Gas-bearing levels are identified by the location of the corresponding plotted points relative to the liquid line. A more complete interpretation of the reservoir is provided by the SARABAND computer-oriented technique. Results provided by this analysis include formation porosity, saturation, permeability index, and shale-, clay-, and sand-volume fractions. Experience indicates that good interpretation results are achieved, and that the subsequent completions are therefore improved. Examples will be shown to illustrate the applications of these two techniques in clean and shaly formations of Northern Montana.

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ADVANCED RESERVOIR CHARACTERIZATION AND EVALUATION OF CO2 GRAVITY DRAINAGE IN THE NATURALLY FRACTURED SPRABERRY TREND AREA

The overall goal of this project is to assess the economic feasibility of CO2 flooding the naturally fractured Spraberry Trend Area in West Texas. This objective is being accomplished by conducting research in four areas: 1) extensive characterization of the reservoirs, 2) experimental studies of crude oillbrine/rock (COBR) interaction in the reservoirs, 3) reservoir performance analysis, and, 4) experimental investigations on CO2 gravity drainage in Spraberry whole cores. This report provides results of the second year of the five-year project for each of the four areas.

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FEASIBILITY OF OPTIMIZING RECOVERY AND RESERVES FROM A MATURE AND GEOLOGICAL COMPLEX MULTIPLE TURBIDITE OFFSHORE CALIFORNIA RESERVOIR THROUGH THE DRILLING AND COMPLETION OF A TRILATERAL HORIZONTAL WELL

The main objective of this project is to devise an effective re-development strategy to combat producibility problems related to the Repetto turbidite sequences of the Carpinteria Field. The lack of adequate reservoir characterization, high-water cut production, and scaling problems have in the past contributed to the field's low productivity.

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Increased Oil Production And Reserves Utilizing Secondary/tertiary Recovery Techniques On Small Reservoirs In The Paradox Basin, Utah

The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate buildups or mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels (1 11,300-3 18,000 m3) of oil per field at a 15 to 20 percent recovery rate. At least 200 million barrels (31,800,000 m3) of oil are at risk of being unrecovered in these small fields because of inefficient recovery practices and undrained heterogeneous reservoirs. Five fields (Anasazi, Mule, Blue Hogan, Heron North, and Runway) within the Navajo Nation of southeastern Utah are being evaluated for waterflood or carbon-dioxide (Cod-miscible flood projects based upon geological characterization and reservoir modeling. The results can be applied to other fields in the Paradox basin and the Rocky Mountain region, the Michigan and Illinois basins, and the Midcontinent.

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Reservoir Characterization of the Ordovician Red River Formation in Southwest Williston Basin Bowman CO, ND and Harding CO, SD

This topical report is a compilation of characterizations by different disciplines of the Ordovician-age Red River Formation and the oil reservoirs which it contains in an area in the southwest portion of the Williston Basin which straddles the state line between North Dakota and South Dakota. This area is off the flank from the Cedar Creek anticline, a major feature in the Williston Basin. Oil production was established in the 1950's following exploration activity on the Cedar Creek anticline. Many of the reservoirs were found by exploration aided with 2D seismic and are characterized by relatively small structures. Although there are four major porosity intervals in the Red River, only two have produced significant oil reserves.

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Advanced Reservoir Characterization and Evaluation of c02 Gravity Drainage in the Naturally Fractured Spraberry Trend Area

The overall goal of this project is to assess the economic feasibility of CO2 flooding the naturally fractured Spraberry Trend Area in West Texas. This objective is being accomplished by conducting research in four areas: 1) extensive characterization of the reservoirs, 2) experimental studies of crude oil brine/rock (COBR) interaction in the reservoirs, 3) reservoir performance analysis, and, 4) experimental investigations on CO2 gravity drainage in Spraberry whole cores. This report provides results of the second year of the five-year project for each of the four areas.

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Improved Recovery Demonstration for Williston Basin Carbonates

The purpose of this project was to demonstrate targeted infill and extension drilling opportunities, better determinations of oil-in-place, and methods for improved completion efficiency. The investigations and demonstrations were focused on Red River and Ratcliffe reservoirs in the Williston Basin within portions of Montana, North Dakota and South Dakota. Both of these formations have been successfully explored with conventional 2-dimensional (2D) seismic. Improved reservoir characterization utilizing 3-dimensional (3D) seismic was investigated for identification of structural and stratigraphic reservoir compartments. These seismic characterizations were integrated with geological and engineering studies. The project tested lateral completion techniques, including high-pressure jetting lance technology and short-radius lateral drilling to enhance completion efficiency. Lateral completions should improve economics for both primary and secondary oil where low permeability is a problem and higher-density drilling of vertical infill wells is limited by drilling cost. New vertical wells were drilled to test bypassed oil in areas that were identified by 3D seismic. These new wells are expected to recover as much or greater oil than was produced by nearby old wells. The project tested water injection through vertical and horizontal wells in reservoirs where application of waterflooding has been limited. A horizontal well was drilled for testing water injection. Injection rates were tested at three times that of a vertical well. This demonstration well shows that water injection with horizontal completions can improve injection rates for economic waterflooding. This report is divided into two sections, part 1 covers the Red River and part 2 covers the Ratcliffe. Each part summarizes integrated reservoir characterizations and outlines methods for targeting by-passed oil reserves in the respective formation and locality.

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Lateral Drilling and Completion Technologies for Shallow-Shelf Carbonates of the Red River and Ratcliffe Formations, Williston Basin

Luff Exploration Company (LEC) focused on involvement in technologies being developed utilizing horizontal drilling concepts to enhance oil- well productivity starting in 1992. Initial efforts were directed toward high-pressure lateral jetting techniques to be applied in existing vertical wells. After involvement in several failed field attempts with jetting  technologies, emphasis shifted to application of emerging technologies for drilling short-radius laterals in existing wellbores and medium-radius technologies in new wells. These lateral drilling technologies were applied in the Mississippi Ratcliffe and Ordovician Red River formations at depths of2590 to 2890 m (8500 to 9500 ft) in Richland Co., MT; Bowman Co., ND; and Harding Co., SD.

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Valley-Fill Sandstones in the Kootenai Formation on the Crow Indian Reservation, South-Central Montana

Subsurface data continues to be collected, organized, and a digital database is being prepared for the project. An ACCESS database and PCArcview is being used to manage and interpret the data. Well data and base map data have been successfully imported into Arcview and customized to meet the needs of this project. Log tops and other data from about ? of the exploration wells in the area have been incorporated into the data base. All of the four 30? X 60? geologic quadrangles have been scanned to produce a digital surface geologic data base for the Crow Reservation and all are nearing completion. Formal technical review prior to publication has been completed for all the quadrangles; Billings, Bridger; Hardin, and Lodge Grass. Final GIS edits are being made before being forwarded to the Bureau's Publications Department. Field investigations were completed during the third quarter, 1997. With the help of a student field assistant from the Crow Tribe, the entire project area was inventoried for the presence of valley-fill deposits in the Kootenai Formation. Field inventory has resulted in the identification of nine exposures of thick valley-fill deposits. These appear to represent at least four major westward-trending valley systems. All the channel localities have been measured and described in detail and paleocurrent data has been collected from all but one locality. In addition, two stratigraphic sections were measured in areas where channels are absent. One channel has bee traced over a distance of about 60 miles and exhibits definite paleostructural control. An abstract describing this channel has been submitted and accepted for presentation at the Williston Basin Symposium in October, 1998.

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ADVANCED UNDERGROUND GAS STORAGE CONCEPTS REFRIGERATED-MINED CAVERN STORAGE

Limited demand and high cost has prevented the construction of hard rock caverns in this country for a number of years. The storage of natural gas in mined caverns may prove technically feasible if the geology of the targeted market area is suitable; and economically feasible if the cost and convenience of service is competitive with alternative available storage methods for peak supply requirements. It is believed that mined cavern storage can provide the advantages of high delivery rates and multiple fill withdrawal cycles in areas where salt cavern storage is not possible. In this research project, PB-KBB merged advanced mining technologies and gas refrigeration techniques to develop conceptual designs and cost estimates to demonstrate the commercialization potential of the storage of refrigerated natural gas in hard rock caverns. Five regions of the U.S.A. were studied for underground storage development and PB-KBB reviewed the literature to determine if the geology of these regions was suitable for sitting hard rock storage caverns. Area gas market conditions in these regions were also studied to determine the need for such storage. Based on an analysis of many factors, a possible site was determined to be in Howard and Montgomery Counties, Maryland. The area has compatible geology and a gas industry infrastructure for the nearby market populous of Baltimore and Washington D.C.

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ADVANCED UNDERGROUND GAS STORAGE CONCEPTS REFRIGERATED-MINED CAVERN STORAGE

Limited demand and high cost has prevented the construction of hard rock caverns in this country for a number of years. The storage of natural gas in mined caverns may prove technically feasible if the geology of the targeted market area is suitable; and economically feasible if the cost and convenience of service is competitive with alternative available storage methods for peak supply requirements. It is believed that mined cavern storage can provide the advantages of high delivery rates and multiple fill withdrawal cycles in areas where salt cavern storage is not possible. In this research project, PB-KBB merged advanced mining technologies and gas refrigeration techniques to develop conceptual designs and cost estimates to demonstrate the commercialization potential of the storage of refrigerated natural gas in hard rock caverns. Five regions of the U.S.A. were studied for underground storage development and PB-KBB reviewed the literature to determine if the geology of these regions was suitable for sitting hard rock storage caverns. Area gas market conditions in these regions were also studied to determine the need for such storage. Based on an analysis of many factors, a possible site was determined to be in Howard and Montgomery Counties, Maryland. The area has compatible geology and a gas industry infrastructure for the nearby market populous of Baltimore and Washington D.C.. As Gas temperature is lowered, the compressibility of the gas reaches an optimum value. The compressibility of the gas, and the resultant gas density, is a function of temperature and pressure. This relationship can be used to commercial advantage by reducing the size of a storage cavern for a given working volume of natural gas. This study looks at this relationship and the potential for commercialization of the process in a storage application. A conceptual process design, and cavern design were developed for various operating conditions. Potential site locations were considered and a typical plant layout was developed. In addition a geomechanical review of the proposed cavern design was performed, evaluating the stability of the mine rooms and shafts, and the effects of the refrigerated gas temperatures on the stability of the cavern. Capital and operating cost estimates were also developed for the various temperature cases considered. The cost estimates developed were used to perform a comparative market analysis of this type of gas storage system to other systems that are commercially used in the region of the study.

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Application of Reservoir Characterization and Advanced Technology to Improve Recovery and Economics in a Lower Quality Shallow Shelf San Andres Reservoir

West Welch Unit is one of four large waterflood units in the Welch Field in the northwestern portion of Dawson County, Texas. The Welch Field was discovered in the early 1940's and produces oil under a solution gas drive mechanism from the San Andres formation at approximately 4800 ft. The field has been under waterflood for 30 years and a significant portion has been infill-drilled on 20-ac density. A 1982-86 pilot CO2 injection project in the offsetting South Welch Unit yielded positive results. Recent installation of a CO2 pipeline near the field allowed the phased development of a miscible CO2 injection project at the South Welch Unit. The reservoir quality at the West Welch Unit is poorer than other San Andres reservoirs due to its relative position to sea level during deposition. Because of the proximity of a CO2 source and the CO2 operating experience that would be available from the South Welch Unit, West Welch Unit is an ideal location for demonstrating methods for enhancing economics of IOR projects in lower quality SSC reservoirs. This Class 2 project concentrates on the efficient design of a miscible CO2 project based on detailed reservoir characterization from advanced petrophysics, 3-D seismic interpretations and cross wellbore tomography interpretations. During this quarter, interpretation and integration of the crosswell seismic data continued, development of the south expansion area was completed and CO2 injection was expanded into last row of injectors.

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Design and Development of Gas-Liquid Cylindrical Cyclone Compact Separators for Three-Phase Flow

The objective of this five-year project (October, 1997 - September, 2002) is to expand the current research activities of Tulsa University Separation Technology Projects (TUSTP) to multiphase oil/water/gas separation. This project will be executed in two phases. Phase I (1997 - 2000) will focus on the investigations of the complex multiphase hydrodynamic flow behavior in a three-phase Gas-Liquid Cylindrical Cyclone (GLCC) Separator. The activities of this phase will include the development of a mechanistic model, a computational fluid dynamics (CFD) simulator, and detailed experimentation on the three phase GLCC. The experimental and CFD simulation results will be suitably integrated with the mechanistic model. In Phase II (2000 - 2002), the developed GLCC separator will be tested under high pressure and real crudes conditions. This is crucial for validating the GLCC design for field application and facilitating easy and rapid technology deployment. Design criteria for industrial applications will be developed based on these results and will be incorporated into the mechanistic model by TUSTP.

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Simultaneous Injection Pilot Project: Phase 1 - Feasibility Study

This project, a feasibility evaluation, is the first of two phases. The second phase will involve field pilot studies. Phase I consists of six tasks. Task 1 assesses the historical applications of the technology including their success and the geological settings in which they were used. Task 2 is an industry needs assessment in which the industry is interviewed about the potential of this tool in various oil field applications. During this task, oil operators will also be asked to nominate field trial sites for consideration. Task 3 will not only inventory the existing and proposed state and federal regulations that could affect the use of this technology, but also include governmental interpretations of the technology. Task 4 will use the information collected in tasks 1, 2, and 3 to pinpoint which rock, fluid, and reservoir conditions are most suited to existing downhole separation technology. In Task 5 the contractors and industry partners (to be identified later) will prioritize nationwide oil industry needs, determine the optimum number of field trial sites needed, and rank the proposed pilot sites. In Task 6, the Phase II field pilot trials are designed. The Phase II design document will include the locations and details of the trials, the goals of the trials, and the importance of this new knowledge to the U.S. oil industry.

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Natural Gas and Oil Technology Partnership

Hardware provided to convert borehole sources and receivers to single-well use. In May 1997, two projects were combined to form a broad, comprehensive project to address single-well seismic imaging. Initial field test of single-well data acquisition system conducted at Bayou Choctaw, LA, November 1997. Follow-on work designed with SIC input. Modeling of salt dome reflections carried out. Modeling of borehole effects continuing. Tube wave attenuator field tested.

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DESIGN AND IMPLEMENTATION OF A CO2 FLOOD UTILIZING ADVANCED RESERVOIR CHARACTERIZATION AND HORIZONTAL INJECTION WELLS IN A SHALLOW SHELF CARBONATE APPROACHING WATERFLOOD DEPLETION

The first project objective is to utilize reservoir characterization and advanced technologies to optimize the design of a carbon dioxide (CO2) project for the South Cowden Unit (SCU) located in Ector County, Texas. The SCU is a mature, relatively small, shallow shelf carbonate unit nearing waterflood depletion. The second project objective is to demonstrate the performance and economic viability of the project in the field. All work during the second quarter falls within the demonstration project.

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Area Balance and Strain in an Extensional Fault System: Strategies for Improved Oil Recovery in Fractured Chalk, Gilbertown Field, Southwestern Alabama- Year 2

Gilbertown Field is the oldest oil field in Alabama and has produced oil from fractured chalk of the Cretaceous Selma Group and glauconitic sandstone of the Eutaw Formation. Nearly all of Gilbertown Field is still in primary recovery, although waterflooding has been attempted locally. The objective of this project is to analyze the geologic structure and burial history of Mesozoic and Tertiary strata in Gilbertown Field and adjacent areas in order to suggest ways in which oil recovery can be improved. Indeed, the decline of oil production to marginally economic levels in recent years has made this type of analysis timely and practical. Key technical advancements being sought include understanding the relationship of requisite strain to production in Gilbertown reservoirs, incorporation of synsedimentary growth factors into models of area balance, quantification of the relationship between requisite strain and bed curvature, determination o the timing of hydrocarbon generation, and identification of the avenues and mechanisms of fluid transport.

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First Measurements of P- and S-Wave Speed on Pure Methane Gas Hydrate

Methane hydrate (ideally CH4?5.75H2O) has been found in ocean margin sediments, deep inland seas and permafrost regions around the world. As part of an ongoing effort to characterize the physical properties of this widely occurring but poorly understood material, we have developed a means of measuring P- and S- wave velocities through pure methane hydrate at in-situ pressure and temperature conditions.

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Alaska Heavy Oil Workshop

A successful cooperative effort, involving the U.S. Department of Energy Office of Fossil Energy @OE/FE), oil producers (i.e., ARC0 Alaska, Inc., British Petroleum), service companies, and the State of Alaska, culminated in a two-day workshop in Girdwood, Alaska. The purposes of the workshop were to provide a forum to address the challenges associated with recovery of heavy oil in the Arctic environment, to investigate potential solutions, and to develop near- and long-term strategies and actions for heavy oil recovery. Over 70 attendees participated in the workshop, including representatives of the oil industry, service companies, federal and state government representatives, industry organizations, environmental groups, academia, and other interested parties.

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Environmental Research -  Area of Review (AQR) Assistance to the State

Develop and implement a project that: tests and refines existing Area of Review (AOR) variance methodologies; provides assistance in developing an AOR strategy for producing properties; provides data for underground injection well AORs; and develops a cooperative approach to environmental compliance. A steering committee chaired by the state mc Director will be formed. That steering committee will include representatives from both the private sector as well as appropriate regulatory agencies. The task includes the acquisition and maintenance of any data required to perform AORs. The task also includes the development and implementation of an AOR variance strategy.

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