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Research about Louisiana, Mississippi, Texas

Source-linked reports with geographic coverage including Louisiana, Mississippi, Texas.

5 recordsLinked to original sources
USGS2025

Estimated ultimate recovery (EUR) Prediction for Eagle Ford Shale using integrated datasets and artificial neural networks

The estimated ultimate recovery (EUR) is an important parameter for forecasting oil and gas production and informing decisions regarding field development strategies. In this study, we combined site-specific geologic, completion, and operational parameters with the predictive capabilities of machine learning (ML) models to predict EURs of the wells for the Eagle Ford Marl Continuous Oil Assessment Unit. We developed an extensive dataset of wells that have produced from the lower and upper Eagle Ford Shale intervals and reduced the model complexity using principal component analysis. We tested the ML models and estimated the sensitivities of ML-predicted EURs to changes in the values of different input variables. The results of applying the optimized ML model to the Eagle Ford suggest that the approach developed in this study could be promising. The ML estimates of the EURs fit the DCA-based values with an R 2 ~ 0.9 and a mean absolute error of ~36 × 10 3 bbl. In the lower Eagle Ford Shale, the EUR estimates were found to be most sensitive to changes in porosity, net thickness of the interval, clay volume, and the API gravity of the oil; and that in the upper Eagle Ford Shale they were most sensitive to changes in the total organic carbon and water saturation, which suggests that it could be important to consider these parameters in assessing these intervals or close analogs.

Louisiana, Mississippi, Texas↗
USGS2021

Exploring basin-scale relations and unsupervised classification to quantify and automate the definition of assessment units in USGS continuous oil and gas resource assessments

The U.S. Geological Survey (USGS) assesses potential for undiscovered, technically recoverable oil and gas resources in priority geologic provinces and quantifies resource volume estimates within subdivisions called assessment units (AUs). AU boundaries are defined by USGS geologists using quantitative and qualitative geologic information. Variables contained in IHS Markit’s well and production databases can quantify and/or function as proxies for many of the qualitative, boundary-defining variables. This research explores a new approach to determine AU boundaries and the potential to automate their definition, using data analytics and machine learning algorithms on key, qualitative variables within the IHS Markit databases. Well and production data from the U.S. onshore Gulf Coast region for the Upper Cretaceous Eagle Ford Group and Austin Chalk are used in this analysis because each is relatively geologically uniform in Texas and both have recently been assessed by the USGS. The Eagle Ford is an example of an in situ continuous oil and gas accumulation, and the overlying Austin Chalk is an example of a combined conventional and continuous resource, sourced from the underlying Eagle Ford. Wellspecific values were extracted or calculated from data in IHS Markit’s well and production databases for depth to top and base of the formations, formation thickness, bottom-hole temperature, temperature gradient, temperature at base of formation, cumulative oil and gas production values, barrels of oil equivalent, oil and gas gravities, mud weights from initial well test, depth pressure ratio, and excess pressure. A raster for each variable was interpolated using the natural neighbor technique from the spatial analyst toolbox in ArcGIS. Rasters were then transformed using minimum-maximum scaling, which rescales the distribution to the range of 0–1. Clustering was completed using the iso cluster unsupervised classification tool on the normalized rasters. Raster cell groupings from two to ten were explored, with initial results demonstrating that four to six classes return the most differentiable groups, with depth to formation, oil gravity, pressure, and temperature variables containing the greatest between-group differences. Modeled clusters have spatial similarities to the geologically defined AUs, with indication that temperature and pressure are the most fundamental to AU definition. Input from geologists will remain crucial for further dividing clusters and defining final AUs, since AUs are defined by both qualitative and quantitative information; however, this research documents promising cluster modeling results for the automation of initial AU definitions.

Louisiana, Mississippi, Texas↗
USGS2018

Correlation of the Tuscaloosa marine shale in Mississippi, Louisiana, and east Texas, U.S.A.

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable unconventional petroleum resources in the Upper Cretaceous marine shale of the Tuscaloosa Group (Tuscaloosa marine shale; TMS) in 2018. As part of the geologic characterization in preparation for the assessment, a series of wireline log cross sections were constructed to illustrate TMS thickness trends and aid in the delineation of the assessment unit (AU). Lithostratigraphic units were correlated based on gamma ray, spontaneous potential, and resistivity log responses and generally follow the classic stratigraphic nomenclature first proposed in the 1960s. Correlated stratigraphic units include (from youngest to oldest) the Austin Group, Eagle Ford Shale, upper Tuscaloosa, Tuscaloosa marine shale, lower Tuscaloosa, and Lower Cretaceous. A high resistivity zone (HRZ) in the basal Tuscaloosa marine shale was delineated where resistivity was greater than 5 ohm-meters and high resistivity sections were separated by less than 20 feet of low resistivity shale. The HRZ was identified regionally and might indicate petroleum accumulations in the TMS. Third-party biostratigraphic data from wells in Mississippi and Louisiana were integrated into the well control, which aided wireline log correlation. Cross sections depict east-west thinning of the TMS onto the Sabine uplift and north-south thickening of the TMS off of the Lower Cretaceous shelf margin. The western boundary of the USGS-defined Tuscaloosa Marine Shale Continuous Oil AU was drawn in western Louisiana near the Texas-Louisiana state border based on stratigraphic thinning of the Upper Cretaceous section onto the structural high of the Sabine uplift as projected downdip.

Louisiana, Mississippi, Texas↗
USGS2003

Potential for deep basin-centered gas accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A.

The potential of Lower Cretaceous sandstones of the Travis Peak Formation in the northern Gulf Coast Basin to harbor a basin-centered gas accumulation was evaluated by examining (1) the depositional and diagenetic history and reservoir properties of Travis Peak sandstones, (2) the presence and quality of source rocks for generating gas, (3) the burial and thermal history of source rocks and time of gas generation and migration relative to tectonic development of Travis Peak traps, (4) gas and water recoveries from drill-stem and formation tests, (5) the distribution of abnormal pressures based on shut-in-pressure data, and (6) the presence or absence of gas-water contacts associated with gas accumulations in Travis Peak sandstones. The Travis Peak Formation (and correlative Hosston Formation) is a basinward-thickening wedge of terrigenous clastic sedimentary rocks that underlies the northern Gulf Coast Basin from eastern Texas across northern Louisiana to southern Mississippi. Clastic influx was focused in two main fluvial-deltaic depocenters—one located in northeastern Texas and the other in southeastern Mississippi and northeastern Louisiana. Across the main hydrocarbon-productive trend in eastern Texas and northern Louisiana, the Travis Peak Formation is about 2,000 ft thick. Most Travis Peak hydrocarbon production in eastern Texas comes from drilling depths between 6,000 and 10,000 ft. Significant decrease in porosity and permeability occurs through that depth interval. Above 8,000-ft drilling depth in eastern Texas, Travis Peak sandstone matrix permeabilities often are significantly higher than the 0.1-millidarcy (mD) cutoff that characterizes tight-gas reservoirs. Below 8,000 ft, matrix permeability of Travis Peak sandstones is low because of pervasive quartz cementation, but abundant natural fractures impart significant fracture permeability. Although pressure data within the middle and lower Travis Peak Formation are limited in eastern Texas, overpressured reservoirs caused by thermal generation of gas, typical of basin-centered gas accumulations, are not common in the Travis Peak Formation. Significant overpressure was found in only one Travis Peak sandstone reservoir in 1 of 24 oil and gas fields examined across eastern Texas and northern Louisiana. The presence of gas-water contacts is perhaps the most definitive criterion indicating that a gas accumulation is conventional rather than a “sweet spot” within a basin-centered gas accumulation. Hydrocarbon-water contacts within Travis Peak sandstone reservoirs were documented in 17 fields and probably occur in considerably more fields across the productive Travis Peak trend in eastern Texas and northern Louisiana. All known hydrocarbon-water contacts in Travis Peak reservoirs in eastern Texas, however, occur within sandstones in the upper 500 ft of the formation. Although no gas-water contacts have been reported within the lower three-fourths of the Travis Peak Formation in northeastern Texas, gas production from that interval is limited. The best available data suggest that most middle and lower Travis Peak sandstones are water bearing in northeastern Texas. Insufficient hydrocarbon charge relative to permeability of Travis Peak reservoirs might be responsible for lack of overpressure and basin-centered gas within the Travis Peak Formation. Shales interbedded with Travis Peak sandstones in eastern Texas are primarily oxidized flood-plain deposits with insufficient organic-carbon content to be significant sources of oil and gas. The most likely source rocks for hydrocarbons in Travis Peak reservoirs are two stratigraphically lower units, the Jurassic-age Bossier Shale of the Cotton Valley Group, and laminated, lime mudstones of the Jurassic Smackover Formation. Hydrocarbon charge, therefore, might be sufficient for development of conventional gas accumulations, but it is insufficient for development of basin-centered gas as a result of the absence of proximal source rocks and a lack of effective migration pathways from stratigraphically or geographically distant source rocks.

Louisiana, Mississippi, Texas↗