AndreaBozzo/ceres-open-data-index huggingface dataset:
Figure 7a

A 2-C method to obtain the fast principal direction and time lag between the slow and fast principal time series.  Illustrated are the cross correlograms between the two recorded components as they are rotated in 5 increments from -90 degrees to 90 degrees (horizontal axis). The vertical axis is the time lag, with a zero time lag corresponding to a value of 4 s on the plot. When the geophone axes are aligned with the principal directions, the waveform should display a maximum similarity (although they will be time shifted). The correct angle and time lag is give by the largest correlation value. As with the Alford rotation there is an ambiguity since there are multiple maxima. The maxima should be identified and the (angle, time lag) pair that yields the fast waveform leading the slow waveform is the correct choice.

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Figure 6

North-south line (inline) 22 showing location of 9-C VSP well. The reflector at the top of the gas producing interval, a red trough at 1.28 s, marks the change from the low-velocity Waltman Shale to the high-velocity LFU. (a) The east-west azimuth source-receiver data volume shows a bright Top LFU reflector package, while (b) the north-south azimuth source -receiver data volume shows dim Top LFU reflectors.

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Figure 4

Relative amplitude preserved: (a) E/W azimuths, north-south dip line 70, with prestack time migration with a minimum migration-function for this area. "Unusual geometry" (source-receiver azimuths perpendicular to line direction). (b) North/south azimuths, north-south dip line 70, with prestack time migration with the same minimum migration-function for the area. "Conventional geometry" (source-receiver azimuths parallel to line direction). In each section, the limited azimuths were selected and input to prestack time migration. The stacking velocities were picked after migration with a minimum velocity function. The Top LFU (about 1.3 s) in the center of this plot (b) is less easily mapped than in (a), which is consistent with the possibility of east-west fractures.

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Figure 3

1980 x 1980 ft azimuth bin gather no. 4. Filter 4-8-40-80 Hz. One velocity function applied to all azimuth gathers. This velocity function was picked on a velscan that lumped all azimuths together ("azimuth-blind velocities"). This figure shows that the move out velocity, reflection coefficient, and the AVO response vary by azimuth. Each trace shown here is a four-to-six fold stacked trace.

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Figure 6

S-wave and P-wave anisotropy at line tie. Reflectors with greatest azimuthal difference in P-wave AVO gradient (Z, MB) are found at tops of intervals with greatest S-wave anisotropy (Z-TN1, MB-DG4). Reflectors with little azimuthal difference in AVO gradient (TGR, TN1) are associated with intervals showing only background levels of S-wave anisotropy (TGR-Z, TN1-MB).

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

Subsurface data is being collected, organized, and a digital database is being prepared for the project. An ACCESS database and PC-Arcview 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 the Billings and Bridger Quadrangles; and are underway for the Hardin and Lodge Grass Quadrangles. Field investigations were completed during the last quarter. 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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TORIS ONSHORE EXPLORATION SYSTEM for Management and Operating Contract for the Department of Energy's National Oil and Related Programs

The purpose of this documentation is to provide a detailed description of the models and methods used to assess future exploration and development of the domestic onshore undiscovered oil resource. The methodology was designed to be consistent with methods used in the Total Oil Recovery Information System (TORIS). This documentation provides details on data acquisition, analytical assumptions, data evaluation techniques, engineering analysis, economic evaluation, and timing algorithms used in these models to assess future oil exploration activities. The goal is to provide an overview of the full analytical system as developed and currently implemented by TORIS. The report outlines the general approach and data sources used in describing the resource remaining in undiscovered reservoirs nationwide. The analysis relies on the quantification of undiscovered resources developed by the U.S. Geologic Survey (USGS). The current description of the remaining undiscovered resource is defined by their assessment published in 1995 (1995 National Assessment of United States Oil and Gas Resources Results, Methodology, and Supporting Data). Reservoir properties are based on data gathered from existing oil reservoirs within individual plays. A database? of existing oil reservoirs was created by merging the existing TORIS database with databases created by NRG associates (NRG, 1993). Procedures have been established to allow easy updates to the system as new data become available. The incorporation of new or expanded assessments or new play characterization, can be readily handled in the existing structure. The modeling procedures include a comprehensive assessment method for determining the relative economics of various prospects based on future financial conditions, the nature of the undiscovered resource, prevailing risk factors, and the available technologies. The model evaluates the economics of exploration and development from the perspective of an operator making an investment decision. The individual accumulation is the unit of analysis for these models. The evaluation of each accumulation considers the full cost of developmental drilling and production. An accumulation, by definition, is the collection of all pools within a field within a given geologic play. The exploration evaluation considers both the size and frequency of undiscovered  accumulations in order to determine the order of discovery within a play. Investment efficiency is used as the criteria in determining the order in which plays are explored. A timing model determines the development timing of each newly discovered accumulation on a sunk exploration cost basis constrained by capital and regional rig availability.

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ADVANCED OIL RECOVERY TECHNOLOGIES FOR IMPROVED RECOVERY FROM SLOPE BASIN CLASTIC RESERVOIRS, NASH DRAW BRUSHY CANYON POOL, EDDY COUNTY, NM

The overall objective of this project is to demonstrate that a development program based on advanced reservoir management methods can significantly improve oil recovery at the Nash Draw Pool (NDP). The plan includes developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced reservoir management methods. Specific goals are: (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the U.S. oil and gas industry.

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BIBLIOGRAPHY, GEOPHYSICAL DATA LOCATIONS, AND WELL CORE LISTINGS FOR THE MISSISSIPPI INTERIOR SALT BASIN

The Northeastern Gulf of Mexico remains an underexplored region containing numerous sedimentary basins with a host of siliciclastic and carbonate formations having a high potential for hydrocarbon accumulations. To date, however, comprehensive basin analysis and petroleum system modeling studies have not been performed on any of the basins in this region. Of these basins, the Mississippi Interior Salt Basin has been selected for study because it is the most petroliferous basin in the Northeastern Gulf of Mexico and continues to have substantial potential for new reservoirs in Jurassic and Cretaceous strata.

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Increased Oil Production and Reserves from Improved Completion Techniques in the Bluebell Field, Uinta Basin, Utah

The Bluebell field is productive from the Tertiary lower Green River and Colton (Wasatch) Formations of the Uinta Basin, Utah. The productive interval consists of thousands of feet of interbedded fractured clastic and carbonate beds deposited in the ancestral Lake Uinta. Wells in the Bluebell field are typically completed by perforating 40 or more beds over 1000 to 3000 vertical ft (300-900 m), then stimulating the entire interval with hydrochloric acid. This technique is often referred to as the "shot gun" completion. Completion techniques used in the Bluebell field were discussed in detail in the Second Annual Report (Curtice, 1996). The shotgun technique is believed to leave many potentially productive beds damaged and/or untreated, while allowing water-bearing and low-pressure (thief) zones to communicate with the wellbore. A two-year characterization study involved detailed examination of outcrop, core, well logs, surface and subsurface fractures, produced oil-field waters, engineering parameters of the two demonstration wells, and analysis of past completion techniques and effectiveness. The study was intended to improve the geologic characterization of the producing formations and thereby develop completion techniques specific to the producing beds or facies instead of a shot gun approach to stimulating all the beds. The characterization did not identify predictable-facies or predictable-fracture trends within the vertical stratigraphic column as originally hoped. Advanced logging techniques can identify productive beds in individual wells. A field demonstration program was developed to use cased-hole advanced logging techniques in two wells and recompletion the wells at two different scales based on the logging. The first well was going to be completed at the interval scale using a multiple stage completion technique (about 500 ft [150 m] per stage). The second well will be recompleted at the bed-scale using bridge plug and packer to isolate three or more beds for stimulation. These recompletion will show which logs are most effective in identifying productive beds and what scale of completion is most cost effective. The third demonstration will be the logging and completion of a new well using the logs and completion scale or technique, most effective in the previous demonstrations.

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Improved Oil Recovery in Mississippian Carbonate Reservoirs of Kansas-Near Term-Class 2

The Kansas Class 2 project was a demonstration project in an Osagian and Meramecian (Mississippian) shallow shelf carbonate reservoir in west central Kansas. Cumulative production from Mississippian carbonate reservoirs located beneath a regional sub-Pennsylvanian unconformity is over 1 billion barrels distributed over a large number of small to medium size reservoirs. Small independent producers operate many of these reservoirs. Extremely high water cuts and low recovery factors place continued operations at or near their economic limits.

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Figure 5

Amplitude variation with offset (AVO), or changes in P-wave reflectivity with incidence angle. (a) Typical cases with no change in Poisson's ratio at interface. Note negative gradient for positive intercept, and vice-versa. (b) Decreasing Poisson's ratio leads to more negative gradients. This is the case for reflections from the top of a gas reservoir. (c) Increasing Poisson's ratio causes more positive gradients. This is the case for reflections from the bottom of a gas reservoir

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GEOLOGIC AND ENGINEERING CHARECTERIZATION OF GERALDINE FORD FIELD, REEVES AND CULBERSON COUNTIES TEXAS  ANALYSIS OF RESERVOIR FLUIDS

On June 14, 1977, separator gas and liquid samples were collected from the subject well and forwarded to our Dallas laboratory for use in a special study. This report presents the complete results of that study. The hydrocarbon analyses of the separator gas and liquid samples were conducted by routine gas chromatography and low temperature fractional distillation, respectively. These measured compositions were used in conjunction with the recorded gas-liquid ratio of 200 standard cubic feet of gas per barrel of stock tank liquid to calculate a well stream composition. These compositions are presented on page two of the report. This information was reported to a representative of Continental Oil Company and we were subsequently instructed to recombine the separator products in the laboratory and use the resulting reservoir fluid to complete the special study. A portion of the recombined fluid was placed in a high pressure visual cell and thermally expanded to the reservoir temperature of 83?P. The fluid was subjected to a constant composition expansion and exhibited an observed saturation pressure of 441 psig. A summation of the various volumetric data collected from this test is presented on page three. The viscosity of the original reservoir fluid was then determined at 83?F., through a series of pressures beginning well above saturation pressure to atmospheric pressure. These values showed a variation from a minimum at saturation pressure of 1.25 centipoises to a maximum at atmospheric pressure of 2.61 centipoises. These values are listed on page four and graphically represented on page five.

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NITROGEN REMOVAL FROM LOW QUALITY NATURAL GAS

The long-term objective of this project is to determine the technical and economical feasibility of a N2 removal concept based on complexation of molecular N2 with novel complexing agents. Successful development of a selective, reversible, and stable reagent with an appropriate combination of capacity and N2 absorption/desorption characteristics will allow selective separation of N2 from LQNG.

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ADVANCED RESERVOIR CHARACTERIZATION IN THE ANTELOPE SHALE TO ESTABLISH THE VIABILITY OF C02 ENHANCED OIL RECOVERY IN CALIFORNIA'S MONTEREY FORMATION SILICEOUS SHALES

The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir.  Characterization studies will be used to determine the technical feasibility of implementing a CO2 enhanced oil recovery project in the Antelope Shale in Buena Vista Hills Field.

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ADVANCED RESERVOIR CHARECTERIZATION IN THE ANTELOPE SHALE TO ESTABLISH THE VIABILITY OF CO2 ENHANCED OIL RECOVERY IN CALIFORNIA'S MONTEREY FORMATION SILICEOUS SHALES

The Buena Vista Hills Field is located about 25 miles southwest of Bakersfield, in the San Joaquin Valley (SJV), California. The Antelope Shale zone was discovered at the Buena Vista Hills in 1952, and has since been under primary production. Little research was done to improve the completion techniques during the development phase in the 1950s, so most of the wells are completed with about 1000 feet of slotted liner. The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a C02 enhanced oil recovery project in the Antelope Shale in Buena Vista Hills Field. The proposed pilot consists of four existing producers on 20 acre spacing with a new 10 acre infill well (6532) drilled as the pilot CO, injector. Most of the reservoir  characterization during Phase I of the project will be performed using data collected in the pilot pattern wells. This is the second annual report of the project. It covers the period February 7, 1997 to February 6, 1998. During this period the following tasks have been completed: laboratory wettability; specific permeability; mercury porosimetry; acoustic anisotropy; rock mechanics analysis; core description; fracture analysis; digital image analysis; mineralogical analysis; hydraulic flow unit analysis; petrographic and confocal thin section analysis; oil geochemical fingerprinting; production logging; carbon/oxygen logging; complex lithologic log analysis; NMR T2 processing; dipole shear wave anisotropy logging; shear wave vertical seismic profile processing; structural mapping, and regional tectonic synthesis. Crosswell seismic was run in the pilot wells and attenuation imaging is proceeding. Both the 3D earth model and C02 coreflooding are close to completion. Lastly a potential target interval has been identified and plans are underway to hydraulically fracture and complete the 6532 well. Noteworthy technological successes for this reporting period include: 1) First (ever) high resolution, crosswell reflection images of SJV sediments; 2) first successful application of the TomoSeis acquisition system in siliceous shales; 3) first detailed reservoir characterization of SJV siliceous shales; 4) first mineral based saturation algorithm for SJV siliceous shales, and 5) first C02 coreflood experiments for siliceous shale. Preliminary results from the C02 coreflood experiments (2500 psi) suggest that significant oil is being produced from the siliceous shale. This stage of the experiment is in its 5th week, and oil recovery continues.

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MAGNETIC AND GRAVITY ANOMALY MAPS OF WEST VIRGINIA

The magnetic and gravity maps of West Virginia show anomalies or disturbances in the Earth's magnetic and gravity fields. These maps are part of a series of geologic, geochemical, structural, and geophysical maps compiled at the scale of 1:1,000,000 for mutual comparison and are produced in cooperation with the West Virginia Geological and Economic Survey. All maps of the series present the mineral resources and pertinent background earth science information of West Virginia. Because the magnetic and gravity anomaly maps are produced at a small scale, they show only anomalous features that are larger than 20 square miles. Smaller anomalous features appear on anomaly maps previously published at the scale of 1:250,000 (U.S. Geological Survey, 1974a,b, 1976, 1978; Kulander and Dean, 1987).

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HIGH POTENTIAL RECOVERY - GAS REPRESSURIZATION

This report presents the background and results of a program initiated by the U.S.. Department of Energy to assess the feasibility of gas repressurization to improve the economic recovery of petroleum by small, independent oil production companies. The work was performed under prime contract DE-AC22-94PC91008 by BDM-Oklahoma, Inc., as part of Work Authorization A03 Extraction Research, Improved Recovery Processes, Task 8 "High Potential Recovery-Gas Repressurization." Workshops were conducted around the United States to present the program to independent producers and to inform them of a solicitation for proposals to conduct cost-shared projects to demonstrate gas repressurization technologies. A solicitation was conducted, and four subcontracts were awarded to demonstrate the use of natural gas and flue gas to improve oil recovery by small independent producers. This report also includes the four final reports from the field demonstration projects. Two of the demonstration projects, one using flue gas and the other involving natural gas from a deeper coal zone, were both technical and economic successes. The two major lessons learned from the projects are the importance of (1) adequate infrastructure (piping, wells, compressors, etc.) and (2) adequate planning including testing compatibility between injected gases and fluids, and reservoir gases, fluids, and rocks.

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Figure 6

Fracture permeability measured within one low-permeability formation (The Mesaverde Formation of Colorado) varies directly with the pore pressure in the system, following a path predicted by the Walsh model. Permeability could be reduced to essentially zero if the reservoir pressure in the vicinity of the wellbore was drawn down during absolute open flow (AOF) production tests, whereas it increased to greater-than-matrix values during injection of fluids at pressures greater than formation values.

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Recovery of Bypassed Oil in the Dundee Formation Using Horizontal Drains

This Class II field project has demonstrated that economic quantities of hydrocarbons can be produced from abandoned or nearly abandoned fields in the Dundee Formation of Central Michigan using horizontal drilling technology. The site selected for the demonstration horizontal well was Crystal Field, a nearly abandoned Dundee oil field in Montcalm County, Michigan. This field had produced over 8 million barrels of oil, mostly in the 1930's and 1940's. At the height of development, Crystal Field produced from 193 wells, but by 1995, only seven producing wells remained, each producing less than 10 bbls/day. A horizontal well, the TOW 1-3, drilled as a field demonstration pilot was successful, producing at rate of 100 bbls of oil per day with a zero water cut. Although the well is capable of producing at a of 500  bbls/day, the production rate is being kept low deliberately to try to prevent premature water coning.

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