AndreaBozzo/ceres-open-data-index huggingface dataset:
Acquisition, classification, and evaluation of engineering and geologic information and characteristics of West Virginia petroleum reservoirs amenable to enhanced oil recovery technology, particularly carbon dioxide injection. Final report

Based on available reservoir information, CO2 displacement seems to be the enhanced oil recovery technique most suitable for most West Virginia oil reservoirs. Seventeen reservoirs have been identified as potential candidates for the CO2 displacement process: three Berea, six Big Injun, five Gordon, one Gordon Stray, one Fifth, and one Squaw--Weir sand reservoir. The total volume of oil remaining in these 17 reservoirs is estimated to be more than one billion barrels. The fields are all within a relatively small geographic area and constitute a significant target for enhanced oil recovery technology. There are, however, many difficulties in working with expensive fluids in old fields containing many abandoned wells. Injectivity of liquid CO2 in West Virginia oil reservoirs has been demonstrated to be higher than that for water or natural gas. In connection with raising pressures prior to CO2 injection, waterflooding has been shown to be effective in two reservoirs previously considered impossible to flood. In the single CO2 displacement process completed in West Virginia, the Granny's Creek project, efficiency of recovery was not high: less than one barrel of additional oil per 20 MSCF of CO2 injected. The injected liquid was found far outside the project area, however, indicating a need for effective confinement. The CO2 process has been demonstrated as effective in displacing oil from a previously waterflooded portion of the reservoir. The three ongoing or projected CO2 projects in the state have many common features, which should simplify the complete analysis when they are completed.

Tags: CO2 displacement, Oil, Resource, enhanced oil recovery
Stimulation rationale for shale gas wells: a state-of-the-art report

Despite the large quantities of gas contained in the Devonian Shales, only a small percentage can be produced commercially by current production methods. This limited production derives both from the unique reservoir properties of the Devonian Shales and the lack of stimulation technologies specifically designed for a shale reservoir. Since October 1978 Science Applications, Inc. has been conducting a review and evaluation of various shale well stimulation techniques with the objective of defining a rationale for selecting certain treatments given certain reservoir conditions. Although this review and evaluation is ongoing and much more data will be required before a definitive rationale can be presented, the studies to date do allow for many preliminary observations and recommendations. For the hydraulic type treatments the use of low-residual-fluid treatments is highly recommended. The excellent shale well production which is frequently observed with only moderate wellbore enlargement treatments indicates that attempts to extend fractures to greater distances with massive hydraulic treatments are not warranted. Immediate research efforts should be concentrated upon limiting production damage by fracturing fluids retained in the formation, and upon improving proppant transport and placement so as to maximize fracture conductivity. Recent laboratory, numerical modeling and field studies all indicate that the gas fracturing effects of explosive/propellant type treatments are the predominate production enhancement mechanism and that these effects can be controlled and optimized with properly designed charges. Future research efforts should be focused upon the understanding, prediction and control of wellbore fracturing with tailored-pulse-loading charges.

Tags: Devonian Black Shale, Geology, Natural Gas, Resource, Shale Gas, gas stimulation
Numerical-model developments for stimulation technologies in the Eastern Gas Shales Project

These efforts were directed towards the development of a numerical tensile failure model that could be used to make a parameter sensitivity study of the EGSP wellbore stimulation methods for gas recovery in Devonain shales, calculations were performed using the NTS Multi-Frac Mineback Experiments as the geometry, boundary conditions and material properties of the models. Several major accomplishments were achieved during this task. These include: development of a Crack and Void Strain (CAVS) tensile failure model for one-dimensional fracture analysis using the one-dimensional geometries available in SAI's STEALTH 1-D finite-difference code; modification of the original CAVS tensile failure criteria to improve its representation of multiple fracture development by introducing a logic that adjusts the material's tensile strength (both for crack initiation and crack propagation) according to the degree of cracking that has occurred; adding a submodel to CAVS to allow for cracking propping when a crack is reclosed and to require energy to be expanded during this process; adding a submodel to CAVS to allow for crack pressurization when a crack void strain is in communication with the fluid pressure of the borehole; and performing a parameter sensitivity analysis to determine the effect that the material properties of the rock has on crack development, to include the effects of yielding and compaction. Using the CAVS model and its submodels, a series of STEALTH calculations were then performed to estimate the response of the NTS unaugmented Dynafrac experiment. Pressure, acceleration and stress time histories and snapshot data were obtained and should aid in the evaluation of these experiments. Crack patterns around the borehole were also calculated and should be valuable in a comparison with the fracture patterns observed during mineback

Tags: Devonian Shales, EGSP, Modeling, simulatio, welbore stimulation
Shale Resources and Water Risks

Explore water availability across shale gas and tight oil resources.

Dozens of countries around the world are deciding whether or not to develop their shale gas and tight oil resources. However, extracting these energy sources poses environmental risks, especially to water.

Drilling and hydraulic fracturing requires up to 25 million liters of water per well, meaning shale resources can be hard to develop where freshwater is hard to find.

The risks and impacts specific to surface and groundwater availability have been thinly documented to date. This tool and the associated report:

    Identify priority locations worldwide where freshwater management will be most critical if shale is developed.
    Reveal potential business risks associated with freshwater availability to companies and build the case for corporate water stewardship and early source-water assessment.

Scope

This tool shares information that can create dialog among water users from industry, government, and civil society in river basins worldwide. It does not attempt to identify risks to water quality from shale resource development, nor does it assess the oil and gas industry’s water management practices.

Definitions

    Baseline water stress: The ratio of total water withdrawals to available renewable supply in an area. In high-stress areas, 40 percent or more of the available supply is withdrawn every year. In extremely high-stress areas, that number goes up to 80 percent or higher. A higher percentage means more water users are competing for limited supplies. See the high and extremely high-stress areas highlighted in red and dark red on the maps. For more detailed information, please see Aqueduct’s Global Maps 2.0 metadata document.
    Hydraulic fracturing: A method of extraction for shale gas and tight oil resources. Fluid is pumped at high pressure down a well to create cracks in low-permeability geological formations. Natural gas and oil then flows from the cracks back into the well.
    Shale play: Part of a shale basin that can be commercially extracted.
    Shale gas: Natural gas deposit found in shale reservoirs, which are between ten and many thousands of times less permeable than conventional natural gas reservoirs.
    Tight oil: Oil trapped in fine-grained sedimentary rocks with extremely low permeability, such as shale, sandstone, or carbonate
    Technically recoverable resource: Shale oil or gas deposit that can be extracted with current technology, but does not consider economic viability.



Tags: Baseline water stress, Gas, Geology, Hydraulic fracturing, Oil, Shale, Shale gas, Shale play, Tight oil, Types, Water, Well Data, resources, tools
Rock Creek Carbon Dioxide Pilot Project. Annual report, July 1979-June 1980

The carbon dioxide injection aspect of the project proceeded smoothly except during supply shortages. An actual effective injection of only 31% rather than the estimated 50% has reduced the percent pore volume of carbon dioxide injected into the pattern area to well below the design volume. Therefore, additional carbon dioxide injection may be required to insure a fair evaluation of this displacement mechanism. To date, this pilot has given no evidence to indicate that a miscible carbon dioxide flood will fail to economically recover a significant amount of oil, provided a sufficient volume of carbon dioxide is injected.

Tags: CO2, Carbon Dioxide Injection, Resource
BX in situ oil shale project. Annual technical progress report, March 1, 1979-February 29, 1980 and quarterly technical progress report, December 1, 1979-February 29, 1980

During the year, design, construction and installation of all project equipment was completed, and continuous steam injection began on September 18, 1979 and continued until February 29, 1980. In the five-month period of steam injection, 235,060 barrels of water as steam at an average wellhead pressure of 1199 psig and an average wellhead temperature of 456/sup 0/F were injected into the eight project injection wells. Operation of the project at design temperature and pressure (1000/sup 0/F and 1500 psig) was not possible due to continuing problems with surface equipment. Environmental monitoring at the project site continued during startup and operation.

Tags: Natural Gas, Resource, Shale Gas, in situ, oil, oil shale, shale
Activities of the Oil Implementation Task Force; Contracts for field projects and supporting research on enhanced oil recovery, July--September 1990

The report contains a general introduction and background to DOE's revised National Energy Strategy Advanced Oil Recovery Program and activities of the Oil Implementation Task Force; a detailed synopsis of the symposium, including technical presentations, comments and suggestions; a section of technical information on deltaic reservoirs; and appendices containing a comprehensive listing of references keyed to general deltaic and geological aspects of reservoirs and those relevant to six selected deltaic plays. Enhanced recovery processes include chemical floodings, gas displacement, thermal recovery, geoscience, and microbial recovery

Tags: Biologic, Oil, Resource, deltatic reservoirs, enhanced oil recovery, microbia
Crude Oil Experimental Density Data

A sample of crude oil referred to as "Buttermilk" has been received from an oil company. The density of the Buttermilk has been experimentally measured at three isotherms (52, 154, and 233 0C) over a wide range of pressures to 275 MPa

Tags: Crude oil, Density, Experimental, High Pressure, High Temperature, Laboratory-scale experiment, Ultra-Deepwater reservoirs
Coal and Shale Adsorption Isotherm Database read-me

A useful document to accompany the "Coal and Shale Adsorption Isotherm Database". Provides explanation of some data and how it was used.

Tags: Adsorption isotherms, CBM, CO2, Coal, Depth, Formation Name, Geology, Geophysical, Modeling, Permeability, Petrophysical, Porosity, Reservoir Properties, Resource, Shale, Stratigraphy, Types of Data, Well Data
Optimizing and Quantifying CO2 Storage Capacity/Resource in Saline Formations and Hydrocarbon Reservoirs

This presentation gives an overview of a DOE project focused on refining the coefficients used to estimate CO2 storage resource in saline formations and understanding the transition of a CO2 EOR project to a storage project. Presented at the 2014 U.S. DOE NETL Carbon Storage R&D Project Review Meeting.

Tags: CCS, CO2 storage capacity, CO2 storage resource, EOR, Geology, Modeling, carbon capture and storage, enhanced oil recovery, hydrocarbon reservoirs, incidental storage, saline formations
Radium Content of Oil- and Gas-Field Produced Waters in the Northern Appalachian Basin (USA)

From the site: "Radium activity data for waters co-produced with oil and gas in New York and Pennsylvania have been compiled from publicly available sources and are presented together with new data for six wells, including one time series. When available, total dissolved solids (TDS), and gross alpha and gross beta particle activities also were compiled.

Data from the 1990s and earlier are from sandstone and limestone oil/gas reservoirs of Cambrian-Mississippian age; however, the recent data are almost exclusively from the Middle Devonian Marcellus Shale. The Marcellus Shale represents a vast resource of natural gas the size and significance of which have only recently been recognized. Exploitation of the Marcellus involves hydraulic fracturing of the shale to release tightly held gas. Analyses of the water produced with the gas commonly show elevated levels of salinity and radium."

Tags: Pennsylvania, Resource, Water, appalachian basin, coordinates, data, gas, marcellus shale, new york, oil, paper, radioactivity, radium, study, water
Optimizing and Quantifying CO2 Storage Capacity/Resource in Saline Formations and Hydrocarbon Reservoirs

This presentation gives an overview of a DOE project focused on refining the coefficients used to estimate CO2 storage resource in saline formations and understanding the transition of a CO2 EOR project to a storage project. Presented at the 2013 U.S. DOE NETL Carbon Storage R&D Project Review Meeting.

Tags: CCS, CO2 storage capacity, CO2 storage resource, EOR, Geology, Modeling, carbon capture and storage, enhanced oil recovery, hydrocarbon reservoirs, incidental storage, saline formations
Statistical Analysis of CO2 EOR Production and Injection Data to Examine Ongoing and Ultimate CO2 EOR Incidental Storage

This presentation gives an overview of the statistical analysis of data from 31 existing CO2 EOR projects. CO2 retention, recovery factor, and utilization factor were analyzed with the goal of better understanding the transition between CO2 storage and CO2 EOR. This work also provides insight into potential future CO2 EOR projects. Presented at the 13th Annual Carbon Capture, Utilization & Storage Conference (2013).

Tags: CCS, CO2 storage, EOR, Geology, Modeling, carbon capture and storage, data analysis, enhanced oil recovery, incidental storage
Workflow Optimization Using Python Programming, a Tool Kit for Every Geoscientist

This presentation gives an overview of using Python programming to optimize CO2 storage simulations conducted with Computer Modelling Group (CMG) software. Solutions to two problems are discussed. First, spatially representing data from CMG simulation results (e.g., plume outlines) is addressed. Second, a streamlined process for optimizing well placement in the simulation model is given. Presented at the 2014 Rocky Mountain Section AAPG Annual Meeting.    

Tags: 3-D simulation, CCS, CO2 storage, Geology, Modeling, Python, carbon capture and storage, geocellular modeling, geologic modeling, programming, scripting
Coal and Shale Adsorption Isotherm Database

This database contains a host of adsorption isotherms for methane, carbon dioxide, and in some cases, nitrogen for various coal and shale basins throughout North America. This database also includes various rock properties, location data, and other parameters associated with these data.

Tags: Adsorption isotherms, CCUS, CH4, CO2, Carbon Sequestration, Coal, Coal Bed Methane, Data, Depth, Formation Name, Gases, Geochemistry, Geology, Geophysics, Identifiers, Name, Operator, Permeability, Petrophysical, Petrophysics, Porosity, Resource, Rock Properties, Shale, Shale Gas, Stratigraphy, Well Data, Well Number
Supporting technology for enhanced oil recovery: Sixth amendment and extension to Annex IV enhanced oil recovery thermal processes

This report contains the results of efforts under the six tasks of the Sixth Amendment and Extension of Annex 4, Enhanced Oil Recovery Thermal Processes of the Venezuela/USA Agreement. The report is presented in sections (for each of the 6 tasks) and each section contains one or more reports prepared by various individuals or groups describing the results of efforts under each of the tasks. A statement of each task, taken from the agreement, is presented on the first page of each section. The tasks are numbered 44 through 49. Tasks are: DOE-SUPRI-laboratory research on steam foam, CAT-SCAN, and in-situ combustion; INTEVEP-laboratory research and field projects on steam foam; DOE-NIPER-laboratory research and field projects light oil steam flooding; INTEVEP-laboratory research and field studies on wellbore heat losses; DOE-LLNL-laboratory research and field projects on electromagnetic induction tomography; INTEVEP-laoboratory research on mechanistic studies.

Tags: Oil, Resource, electromagnetic induction tomography, enhanced oil recovery, light oil stream flooding, wellbore heat losses
Target reservoirs for CO2 miscible flooding. Task Two: summary of available reservoir and geological data. Volume 1. Permian basin geological and reservoir data; Part 1. Permian basin reservoir  Final report

The stated objective of this study is to build a solid engineering foundation to serve as the basis for field mini- and pilot tests in both high and low oil saturation carbonate reservoirs for the purpose of extending the technology base in carbon dioxide miscible flooding. The six tasks in this study are as follows: summary of available CO2 field test data: summary of existing reservoir and geological data; selection of target reservoirs; selection of specific reservoirs for CO2 injection tests; selection of specific sites for test wells in carbonate reservoirs; and drilling and coring activities. The report for Task Two summarizes existing reservoir and geological data on carbonate reservoirs located in west Texas, southeast New Mexico, and the Rocky Mountain states. It is contained in two volumes, each with several parts. The present volume, in four parts, is a summary of reservoir data for fields in the Permian basin of west Texas and southeast New Mexico.

Tags: Brine reservoirs, CO2, Resource, carbonate reservoirs, permian
Ra Content of Oil- and Gas-Field Produced Waters in the Northern Appalachian Basin

Radium activity data for waters co-produced with oil and gas in New York and Pennsylvania have been compiled from publicly available sources and are presented together with new data for six wells, including one time series. When available, total dissolved solids (TDS), and gross alpha and gross beta particle activities also were compiled. Data from the 1990s and earlier are from sandstone and limestone oil/gas reservoirs of Cambrian-Mississippian age; however, the recent data are almost exclusively from the Middle Devonian Marcellus Shale. The Marcellus Shale represents a vast resource of natural gas the size and significance of which have only recently been recognized. Exploitation of the Marcellus involves hydraulic fracturing of the shale to release tightly held gas. Analyses of the water produced with the gas commonly show elevated levels of salinity and radium. Similarities and differences in radium data from reservoirs of different ages and lithologies are discussed. The range of radium activities for samples from the Marcellus Shale (less than detection to 18,000 picocuries per liter (pCi/L)) overlaps the range for non-Marcellus reservoirs (less than detection to 6,700 pCi/L), and the median values are 2,460 pCi/L and 734 pCi/L, respectively. A positive correlation between the logs of TDS and radium activity can be demonstrated for the entire dataset, and controlling for this TDS dependence, Marcellus shale produced water samples contain statistically more radium than non-Marcellus samples. The radium isotopic ratio, Ra-228/Ra-226, in samples from the Marcellus Shale is generally less than 0.3, distinctly lower than the median values from other reservoirs. This ratio may serve as an indicator of the provenance or reservoir source of radium in samples of uncertain origin.

Tags: Appalachian Basin, Flowback, Fluids, Geochemistry, Oil and Gas, Pennsylvania, Ra, Radiu, Well Water
Eastern Gas Shales Project outgassing analysis. Special report

Two methods are used on the Eastern Gas Shales Project to measure the gas volume of encapsulated shale samples. The direct method measures pressure and volume and is initiated almost immediately upon encapsulation of the sample. A second method measures pressure, volume, and composition, and is initiated after pressure is allowed to build up over several weeks. A combination of the two methods has been used on selected samples, and yields more data as it allows extrapolation to account for gas lost prior to encapsulation. The stratigraphic horizons, characterized by dark shales with high organic and high carbon content and a relatively high gamma ray intensity of 200+ API units also have high gas contents (relative to other units within the same well). The Lower Huron, Rhinestreet, and Marcellus Shales are high in gas content relative to other stratigraphic units at the same sites. The difference in gas content of the same stratigraphic horizon between well sites appears to be controlled by the thermal maturity. Kinetic studies have shown that, in some samples, significant amounts of gas are released after the time when the gas volume would be initially measured. Additional work needs to be performed to determine why the rates and volume of gas released vary between samples.

Tags: EGSP, Eastern Gas Shales Project, Geology, Lithology, Physical Properties, gas volume, outgassing, shale
Weeks Island S sand reservoir B gravity stable miscible CO2 displacement. First annual report

The ''S'' sand Reservoir B CO2 pilot was designed to demonstrate the feasibility of a downward CO2 displacement in a steeply dipping, high temperature and high pressure Gulf Coast reservoir. Research results show that CO2 injection is not a miscible process at the S Sand Reservoir B (SRB) conditions but a CO2-crude oil vaporization process. Vaporization means that the CO2 strips and replaces hydrocarbon components from the crude. The stripping is enhanced with repeated contacts with fresh CO2. Results of experiments indicate that CO2 diluted with five to ten percent of plant gas (primarily methane) would result in a miscible-like displacement process. It also appears that based on slim tube experiments alone, undiluted CO2 might be the most efficient material for the SRB field test. Under SRB reservoir conditions, CO2 not diluted with light hydrocarbons is more dense than the reservoir oil. Fortunately, process mechanisms can work to the benefit of displacement stability. Upon mixing SRB oil and CO2, two phases are formed. The CO2 rich vapor phase is less dense than the liquid phase. Based on a zero dimensional analysis and the phase behavior study results, the vertical displacement by CO2 PG or CO2 alone should be gravity stable at the expected flood conditions. A mixture of five percent by volume of plant gas and 95 percent CO2 is the recommended injection system for this field test. This dilution should allow gravity forces to augment the vaporization process. 

Tags: CO2, CO2 injection, Resource, crude oil vaporization, sand reservoir