AndreaBozzo/ceres-open-data-index huggingface dataset:
Scale-up of Miscible Flood Processes for Heterogeneous Reservoirs

The current project is a systematic research effort aimed at quantifying relationships between process mechanisms that can lead to improved recovery from gas injection processes performed in heterogeneous Class 1 and Class 2 reservoirs. It will provide a rational basis for the design of displacement processes that take advantage of crossflow due to capillary, gravity and viscous forces to offset partially the adverse effects of heterogeneity. In effect, the high permeability zones are used to deliver fluid by crossflow to zones that would otherwise be flooded only very slowly.

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CHARACTERIZATION OF NON-DARCY MULTIPHASE FLOW IN PETROLEUM BEARING FORMATION

Slow flow is most common in oil and gas reservoirs and can be adequately described by Darcy's law. Although rapid fluid flow may occur only in certain limited locations, it can affect the productive capacity of in-situ reservoirs significantly. Therefore, for accurate predictability of reservoir productivity, accurate description of deviations from Darcy's law during rapid flow is important.

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The Development of a Laser-Illuminated Infrared Imager for Natural Gas Leak Detection

The general objective of this project is the development of a BAGI imager that has sufficient standoff range and natural gas detection sensitivity to be useful to the natural gas industry. The application of highest interest is the detection of leaks during routine surveys of natural gas distribution systems in residential or industrial areas. This constitutes the most costly leak-sensing operation and, thus, the area of greatest potential cost savings. In order for a van-mounted BAGI imager to be useful for distribution surveys it must have a standoff range sufficient to allow it to image at the maximum expected distance from the road to the residential or industrial service. This is assumed to be ~40 m. The minimum required gas sensitivity is more difficult to specify. Flame-ionization detectors (FIDs) now widely used in the industry exhibit threshold sensitivities to natural gas of approximately 1-4 ppm. The surface concentration of natural gas resulting from a below-ground leak varies widely as a function of position on the surface. Discussions with Pacific Gas and Electric (PG&E) survey teams indicate that the peak surface concentration exhibited by the smallest categorized leak is typically ~100 - 700 ppm. Although this is many times the sensitivity threshold of an FID, the excess sensitivity of the sniffer is necessary because it allows a leak to be detected at some distance from its point of maximum intensity. Leak survey teams exploit this sensitivity to allow them to scan an area with only a finite number of "sniffs". Nonetheless, it is possible that these measurements may still miss a leak. The imager, in contrast, samples all points in its field-of-view. The sensitivity to natural gas (methane) of the BAGI imager under development is approximately 7-10 ppm-m (the units arise because BAGI measures a path-integrated absorption; i.e., a 7 ppm-m sensitivity indicates 7 ppm can be detected for a 1-m plume, 14 ppm is the threshold for a 0.5-m plume, etc). Thus, its point sensitivity is less than that of the sniffer, however, its large area of influence makes it more likely to sample the region of highest concentration. Its threshold sensitivity is expected to be high enough to allow it to detect all required leaks at the maximum concentration point. A second objective of this project is to field-test the sensitivity of BAGI in detecting gas percolating to the surface from realistic buried leak sources and to compare the performance of BAGI to that of an FID. This will be done in both controlled tests and in tests at leaks in distribution systems that have been identified by gas utility companies.

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SCALE-UP OF MISCIBLE FLOOD PROCESSES FOR HETEROGENEOUS RESERVOIRS

Progress is reported for a comprehensive investigation of the scaling behavior of gas injection processes in heterogeneous reservoirs. The interplay of phase behavior, viscous fingering, gravity segregation, capillary imbibition and drainage, and reservoir heterogeneity is examined in a series of simulations and experiments. Compositional and first-contact miscible simulations of viscous fingering and gravity segregation are compared to show that the two techniques can give very different results. Also, analyzed are two-dimensional and three-dimensional flows in which gravity segregation and viscous fingering interact. The simulations show that 2D and 3D flows can differ significantly. A comparison of analytical solutions for three-component two-phase flow with experimental results for oil/water/alcohol systems is reported. While the experiments and theory show reasonable agreement, some differences remain to be explained. The scaling behavior of the interaction of gravity segregation and capillary forces is investigated through simulations and through scaling arguments based on analysis of the differential equations. The simulations show that standard approaches do not agree well with results of low 1FT displacements. The scaling analyses, however, reveal flow regimes where capillary, gravity, or viscous forces dominate the flow.

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Managing Coal Bed Methane Produced Water for Beneficial Uses, Initially Using The San Juan and Raton Basins as a Model

This report gives much of the progress of the second year (but essentially first year funding only) of the Managing Coal Bed Methane Produced Water for Beneficial Uses, Initially Using the San Juan and Raton Basins as a Model. The work is divided into two manor sections work that was accomplished last year and work that is planned this year with the fairly recent arrival of out second year's funding.

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Identifying Oil Exploration Leads using Integrated Remote Sensing and Seismic Data Analysis, Lake Sakakawea, Fort Berthold Indian Reservation, Williston Basin

The Fort Berthold Indian Reservation, inhabited by the Arikara, Mandan and Hidatsa Tribes (now united to form the Three Affiliated Tribes) covers a total area of 1530 mi2 (980,000 acres). The Reservation is located approximately 15 miles east of the depocenter of the Williston basin, and to the southeast of a major structural feature and petroleum producing province, the Nesson anticline. Several published studies document the widespread existence of mature source rocks, favorable reservoir/caprock combinations, and production throughout the Reservation and surrounding areas indicating high potential for undiscovered oil and gas resources. This technical assessment was performed to better define the oil exploration opportunity, and stimulate exploration and development activities for the benefit of the Tribes. The need for this assessment is underscored by the fact that, despite its considerable potential, there is currently no meaningful production on the Reservation, and only 2% of it is currently leased.

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Play Analysis of Major Oil Reservoirs in the New Mexico Part of the Permian Basin: Enhanced Production Through Advanced Technologies

Approximately 300 reservoirs in the New Mexico part of the Permian Basin have cumulative production of more than 1 million bbls oil (MMBO). These 300 reservoirs had produced a total of 4.5 billion bbls oil at the end of 2000. The reservoirs have been grouped into 17 plays based on geologic parameters, including reservoir stratigraphy, lithology, depositional environment, tectonic setting, and trapping mechanism. There are 10 Permian plays that have a cumulative production of 3506 MMBO, two Pennsylvanian plays with a cumulative production of 424 MMBO, three Siluro-Devonian plays with a cumulative production of 440 MMBO, and two Ordovician plays with a cumulative production of 86 MMBO. During 2000, 40 MMBO were produced from the Permian plays, the Pennsylvanian plays yielded 6.4 MMBO, the Silurian-Devonian plays yielded 1.4 MMBO, and the Ordovician plays gave up 0.35 MMBO.

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Identifying Oil Exploration Leads using Integrated Remote Sensing and Seismic Data Analysis, Lake Sakakawea, Fort Berthold Indian Reservation, Williston Basin

The Fort Berthold Indian Reservation, inhabited by the Arikara, Mandan and Hidatsa Tribes (now united to form the Three Affiliated Tribes) covers a total area of 1530 mi2 (980,000 acres). The Reservation is located approximately 15 miles east of the depocenter of the Williston basin, and to the southeast of a major structural feature and petroleum producing province, the Nesson anticline. Several published studies document the widespread existence of mature source rocks, favorable reservoir/caprock combinations, and production throughout the Reservation and surrounding areas indicating high potential for undiscovered oil and gas resources. This technical assessment was performed to better define the oil exploration opportunity, and stimulate exploration and development activities for the benefit of the Tribes. The need for this assessment is underscored by the fact that, despite its considerable potential, there is currently no meaningful production on the Reservation, and only 2% of it is currently leased. Of particular interest (and the focus of this study) is the area under the Lake Sakakawea (formed as result of the Garrison Dam). This ?reservoir taking? area, which has never been drilled, encompasses an area of 150,000 acres, and represents the largest contiguous acreage block under control of the Tribes. Furthermore, these lands are Tribal (non-allotted), hence leasing requirements are relatively simple.

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Oil Reservoir Characterization and CO2 Injection Monitoring in the Permian Basin with Cross-Well Electromagnetic Imaging

The goal of the project was to build on the previous development of resistivity logging tools to develop cross-well imaging hardware and software, to calibrate and field test the transmitter and receiver systems, and to use the cross-well imaging tool for monitoring carbon dioxide (CO2) injection. Three development phases and thirteen specific tasks were written into the contract and the culmination included a complete reservoir simulation and field management analysis, based on cross-well imaging with the system. The main objective was to develop a cross-well electromagnetic system to provide the formation resistivity distribution between steel-cased wells and apply it in the Permian Basin.

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Chapter 1. Introduction, Goals, Conclusions, Project Data, Production History, Previous Work, Acknowledgements

This report contains the results of research conducted by the Rome Trough Consortium, a partnership of three state geological surveys, several energy industry companies and the U.S. Department of Energy. The Consortium was headed by the Kentucky Geological Survey, University of Kentucky, Lexington, Ky. Research was also conducted by the Ohio Department of Natural Resources, Division of Geological Survey in Columbus, Ohio and the West Virginia Geological and Economic Survey in Morgantown, W. Va.. Members of the consortium are listed in Table 1-1. This consortium was formed to gain a better understanding of the geology and deep hydrocarbon potential of the Rome Trough, a Cambrian-age depositional basin located in eastern Kentucky, northern West Virginia, and southeastern-most Ohio. The Consortium was initiated in January 1999, and research lasted 2 years, with a final project review and core workshop on January 24, 2001 at the Kentucky Geological Survey in Lexington, Ky. At this meeting members decided to continue research on core material that arrived near the end of the project. This report documents all research done through mid-2002. Significant new research resulted from the extra time allowed to continue this work.

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Chapter 2. Regional Structure and Tectonics

The Rome Trough is an Early to Middle Cambrian age extensional graben that extends from northern Tennessee, northeastward through central and eastern Kentucky, West Virginia, into southwestern Pennsylvania (Woodward, 1961; McGuire and Howell, 1963; Drahovzal and Noger, 1995), and possibly into southern New York (Wagner, 1976). It is a portion of the eastern North American interior rift system that formed in conjunction with the opening of the Iapetus-Theic Ocean (Harris, 1978; Thomas, 1991). Although there is evidence of reactivation as recent as the post-Pliocene (VanArsdale and Sergeant, 1992), the majority of the extension (normal fault movement) within the Trough occurred during the Middle to Late Cambrian Period.

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Chapter 3. Regional Stratigraphy and Depositional History

A main goal of this project was regional stratigraphic correlation in the 3 state study area using a consistent set of formation picks and names. Historically subsurface Cambrian stratigraphy in Ohio, Kentucky, and West Virginia was a confusing mixture of formation names extrapolated from outcrop sections, which were often far removed from the Appalachian Basin. In addition, drillers? terminology had been mixed with formal stratigraphic names. The results of this study have improved stratigraphic correlations and relationships in the 3 states, but we are not proposing new stratigraphic names at this time. Much of the confusing terminology is used in Ohio, where Janssens (1973) applied the Rome and Conasauga Formations to rocks which are not equivalent to those formations elsewhere in the basin. This problem and recommended usage is discussed more fully in Chapter 4.

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Chapter 5. Digital Well Log Data, Computer Lithology Modeling and Sandstone Mapping

One of the major accomplishments of this project is the creation and compilation of digitized Wireline logs for 157 deep wells in the project. Through a joint effort on the part of all the consortium members, digital logs were either donated, or paper logs were digitized to create this database of LAS-format (log ASCII standard) log data. We gratefully acknowledge the contributions of log data by Columbia Natural Resources, Equitable Resources, and Hay Exploration for the project. A database table is included in the project database that contains details on the digitized curves available for each well.

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Argonne's Modeling Capabilities for Developing Candidate Deep Well Cements - Development of Berlinite-Based Deep Well Cement Report 3

In the earlier reports to the Sponsor, we modeled the solubility of less than sparsely soluble oxides and predicted possibility of forming deep well cements using reaction between aluminum oxide and phosphoric acid solution. Based on these theoretical results, we conducted experimental investigations and have now demonstrated that aluminum phosphate (berlinite) cement can be formed for wells at temperature ³ 300 °F (150 °C). The slurry consists of calcined alumina (corundum) and phosphoric acid solution in which aluminum hydroxide is used to accelerate the reaction. Depending on the content of the hydroxide, the pumping time can be varied between 5-7 hours. Initially, the slurry is very thin and gives a very small Bc and hence can be pumped very easily. The hardening occurs when the temperature reaches 300 °F (150 °C). The resulting hard product has a compressive strength of »700 psi. The X-ray diffraction pattern indicates that the resulting hard product consists of alumina and berlinite.

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Chapter 8. Conclusions and Exploration Recommendations

The Rome Formation and Maryville Limestone of the Conasauga Group contain sandstones commonly showing 6-10% porosity. Porosity development does not appear to be a risk in the high sandstone percentage areas. Two areas have the best probability for encountering porous sandstones, as shown on the sandstone percentage maps made in this study. For the Rome Formation, the structural shelf between the Kentucky River Fault System and the Irvine-Paint Creek Fault System has the highest sandstone percentages mapped. Sandstones increase toward the north against the Kentucky River Fault. This trend narrows east of the Isonville Fault, into Carter and Boyd Counties, but is still prospective. South of the Irvine-Paint Creek Fault System and in the deeper part of the Trough in West Virginia, sand quantity decreases dramatically. Reservoir risk is much higher in these areas due to lack of reservoir. Evidence for deeper water sandstones has not been seen in this study, but they cannot be ruled out.

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Real Time Half Duplex Communications Wireless Gauge with Downhole Power Monitors Deep Well Gas Production

Monitoring and control of the processes required to produce hydrocarbons constitutes an ongoing industry concern, which is partly because of the expenses and risks associated with the execution of those processes, as well as environmental and safety factors. The ability to provide wireless monitoring of wellbore parameters also has increased completion reliability and decreased completion costs. In an effort to address these issues, Tubel Technologies was funded by the U.S. Department of Energy's National Energy Technology Laboratory to develop a new real-time downhole wireless pressure and temperature gauge for the optimization of natural gas production. This system utilizes the production tubing as the medium for the transmission of the information from downhole to the surface.

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Seismic and Rockphysics Diagnostics of Multiscale Reservoir Textures

As part of our study on “Relationships between seismic properties and rock microstructure”, we have continued our work on analyzing well logs and microstructural constraints on seismic signatures. We report results of three studies in this report. The first one deals with fractures and faults that provide the primary control on the underground fluid flow through low permeability massive carbonate rocks. Fault cores often represent lower transmissibility whereas the surrounding damaged rocks and main slip surfaces are high transmissibility elements. We determined the physical properties of fault rocks collected in and around the fault cores of large normal faults in central Italy. After studying the P- and S-wave velocity variation during cycles of confining pressure, we conclude that a rigid pore frame characterizes the fault gouge whereas the fractured limestone comprises pores with a larger aspect ratio. The second study was to characterize the seismic properties of brine as its temperature decreases from 25 ºC to – 21ºC. The purpose was to understand how the  transmitted wave changes with the onset of freezing. The main practical reason for this experiment was to use partially frozen brine as an analogue for a mixture of methane hydrate and water present in the pore space of a gas hydrate reservoir. In the third study we analyzed variations in dynamic moduli in various carbonate reservoirs. The investigations include log and laboratory data from velocity, porosity, permeability, and attenuation measurements.

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Q AS A LITHOLOGICAL/HYDROCARBON INDICATOR: FROM FULL WAVEFORM SONIC TO 3D SURFACE SEISMIC

The objective of this project is to develop a method to exploit viscoelastic rock and fluid properties to greatly enhance the sensitivity of surface seismic measurements to the presence of hydrocarbon saturation. To reach the objective, Southwest Research Institute scientists will use well log, lithology, production, and 3D seismic data from an oil reservoir located on the Waggoner Ranch in north central Texas. The project will provide a methodology for processing and interpreting surface/subsurface data to determine reservoir properties and for applying that information to predict hydrocarbon locations and volume estimates in complex geological environments.

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MULTICOMPONENT SEISMIC ANALYSIS AND CALIBRATION TO IMPROVE RECOVERY FROM ALGAL MOUNDS: APPLICATION TO THE ROADRUNNER/TOWAOC AREA OF THE PARADOX BASIN, UTE MOUNTAIN UTE RESERVATION, COLORADO

This report describes the results made in fulfillment of contract DE-FG26-02NT15451, ?Multicomponent Seismic Analysis and Calibration to Improve Recovery from Algal Mounds: Application to the Roadrunner/Towaoc Area of the Paradox Basin, Ute Mountain Ute Reservation, Colorado?, for the Third Biennial Report covering the time period May 1, 2003 through October 31, 2003.

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Play Analysis of Major Oil Reservoirs in the New Mexico Part of the Permian Basin: Enhanced Production Through Advanced Technologies

Approximately 300 reservoirs in the New Mexico part of the Permian Basin have cumulative production of more than 1 million bbls oil (MMBO). These 300 reservoirs had produced a total of 4.5 billion bbls oil at the end of 2000. The reservoirs have been grouped into 17 plays based on geologic parameters, including reservoir stratigraphy, lithology, depositional environment, tectonic setting, and trapping mechanism. There are 10 Permian plays that have a cumulative production of 3506 MMBO, two Pennsylvanian plays with a cumulative production of 424 MMBO, three Siluro-Devonian plays with a cumulative production of 440 MMBO, and two Ordovician plays with a cumulative production of 86 MMBO. During 2000, 40 MMBO were produced from the Permian plays, the Pennsylvanian plays yielded 6.4 MMBO, the Silurian-Devonian plays yielded 1.4 MMBO, and the Ordovician plays gave up 0.35 MMBO. Most production in the basin has been obtained from reservoirs located on the Northwest Shelf and on the Central Basin Platform. There are 13 plays productive from shelf, platform and ramp settings. These 13 plays have produced a cumulative total of 4231 MMBO and 39 MMBO during 2000 from 249 reservoirs. In contrast there are four plays that are productive from reservoirs deposited in basinal settings. These four plays have 50 reservoirs with more than 1 MMBO production and produced a cumulative total of 226 MMBO; 9.0 MMBO were produced from the basinal plays during 2000. A wide variety of advanced management techniques have been applied in the Permian Basin in order to enhance or stimulate production from already discovered reservoirs. Waterfloods have increased recovery and produced substantial volumes of oil in both shelf and basinal reservoirs. Pressure maintenance projects have increased production in solution gas drive reservoirs. In some cases, horizontal drilling has been successfully applied to produce oil not in communication with vertical wells in horizontally compartmentalized reservoirs or to produce oil that was unswept by waterfloods in old, mature reservoirs. Other old reservoirs have benefited from completions in bypassed pay that remained unproduced behind casing. Yet other reservoirs did not attain full field development for years after discovery because development was undertaken on the basis of misconceptions regarding trapping mechanism. In yet other cases, exploratory objectives were overlooked in favor of drilling targets in other stratigraphic units. It appears that advanced reservoir management techniques have been successful in many plays but not always widely applied, leaving potentially productive oil in the ground.

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The PCOR Partnership Decision Support System

The Plains CO2 Reduction (PCOR) Partnership has put into place a Web-based decision support system (DSS) to assist its research team in developing and assessing a wide range of sequestration opportunities for the PCOR Partnership region. The DSS is a central repository for the characterization information that is being collected through the project tasks. It allows the PCOR Partnership to browse, query, analyze, and download data regarding CO2 sequestration in the PCOR Partnership region. Outputs from the DSS will be used in the PCOR Partnership model during the identification of CO2 sequestration opportunities.

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