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Lauri Burke

Publications and source records attributed to Lauri Burke.

9 recordsLinked to original sources
USGS2015

Assessment of undiscovered oil and gas resources in sandstone reservoirs of the Cotton Valley Group, U.S. Gulf Coast, 2015

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered mean volumes of 14 million barrels of conventional oil, 430 billion cubic feet of conventional gas, 34,028 billion cubic feet of continuous gas, and a mean total of 391 million barrels of natural gas liquids in sandstone reservoirs of the Upper Jurassic–Lower Cretaceous Cotton Valley Group in onshore lands and State waters of the U.S. Gulf Coast region.

Cotton Valley Group, Gulf Coast↗
USGS2014

Geopressure gradient maps of Southern Louisiana, state, and vicinity

This series of five maps characterizes the subsurface pressure system of southern Louisiana, including the associated State and Federal waters. These maps were generated using the U.S. Geological Survey’s (USGS) comprehensive geopressure-gradient model (Burke et al., 2012b, 2013) that delineates the regional pressure system spanning the onshore and offshore Gulf of Mexico basin, USA. Previously, the model was used to generate ten regional-scale maps (Burke et al., 2012a): five contour maps characterized the depth to the surface defined by the first occurrence of regional isopressure gradients ranging from 0.60 psi/ft to 1.00 psi/ft, in 0.10-psi/ft increments; and five supporting maps displayed the spatial density of the data used to construct the regional contour maps. Explanation of generalized geopressure gradients and pressure-regime nomenclature is given here. The five contour maps in this series characterize the depth to the surface defined by the first occurrence of isopressure gradients ranging from 0.60 psi/ft to 1.00 psi/ft, in 0.10-psi/ft increments. The geographical extent of this geopressure-gradient model is delineated on the maps, which encompass one of the most densely drilled regions of southern Louisiana and adjacent areas. The boundary of the model represents the area of greatest well density to maintain accurate contouring to the edge of the model. The pressure data were obtained from the IHS database (IHS Energy Group, 2011) and geologic folios (Dodge and Posey, 1981; Bebout and Gutiérrez, 1982; 1983; Eversull, 1984; Foote et al., 1990), which were compiled and digitally archived (Burke et al., 2011). Data quality analysis, linear-pressure interpolation calculations, and contouring algorithms defining the geopressure-gradient model are described by Burke et al. (2012b, 2013). The isopressure-gradient trends depicted on these maps are not intended for detailed interpretation at specific locations.

Louisiana↗
USGS2012

Assessment of undiscovered oil and gas resources in conventional and continuous petroleum systems in the Upper Cretaceous Eagle Ford Group, U.S. Gulf Coast region, 2011

Using a geology-based assessment methodology, the U.S. Geological Survey assessed means of (1) 141 million barrels of oil (MMBO), 502 billion cubic feet of natural gas (BCFG), and 16 million barrels of natural gas liquids (MMBNGL) in the conventional Eagle Ford Updip Sandstone Oil and Gas Assessment Unit (AU); (2) 853 MMBO, 1,707 BCFG, and 34 MMBNGL in the continuous Eagle Ford Shale Oil AU; and (3) 50,219 BCFG and 2,009 MMBNGL in the continuous Eagle Ford Shale Gas AU in onshore lands and State waters of the Gulf Coast.

Gulf Coast Region↗
USGS2012

Migration rates and formation injectivity to determine containment time scales of sequestered carbon dioxide

Supercritical carbon dioxide exhibits highly variable behavior over a range of reservoir pressure and temperature conditions. Because geologic sequestration of supercritical carbon dioxide is targeted for subsurface injection and containment at depths ranging from approximately 3,000 to 13,000 feet, the investigation into the physical properties of this fluid can be restricted to the pressure and temperature conditions likely encountered in the sedimentary strata within this depth interval. A petrophysical based approach was developed to study the widest range of formation properties potentially encountered in sedimentary strata. Fractional porosities were varied from 5 to 95 percent, in 5-percent increments, and permeability values were varied over thirteen orders of magnitude, from 10.0 darcys down to 1.0 picodarcy. Fluid-flow modeling incorporated two constitutive equations from fluid dynamics: hydraulic diffusivity for near-surface applications, and Darcy's Law for deeper formations exhibiting higher pressure gradients. Based on the flow modeling results, first-order approximations of carbon dioxide lateral migration rates were determined. These first-order approximations enable the establishment of a permeability classification system for dividing the subsurface into flow units that provide short, moderate, and long-term containment of carbon dioxide. These results enable a probabilistic determination of how fluids will enter and be contained in a subsurface storage formation, which is a vital step in the calculation of the carbon dioxide storage capacity of a reservoir. Additionally, this research establishes a methodology to calculate the injectivity of a target formation. Because injectivity describes the pressure increase due to the introduction of fluids into a formation, the relevant application of injectivity is to determine the pressure increase, due to an injection volume and flow rate, that will induce fractures in the reservoir rocks. This quantity is defined mathematically as the maximum pressure differential between the hydrostatic gradient and the fracture gradient of the target formation. Injectivity is mathematically related to the maximum pressure differential of the formation, and can be used to determine the upper limit for the pressure increase that an injection target can withstand before fracturing.

Open-File Report↗
USGS2011

Natural gas production and anomalous geothermal gradients of the deep Tuscaloosa Formation

For the largest producing natural gas fields in the onshore Gulf of Mexico Basin, the relation between temperature versus depth was investigated. Prolific natural gas reservoirs with the highest temperatures were found in the Upper Cretaceous downdip Tuscaloosa trend in Louisiana. Temperature and production trends from the deepest field, Judge Digby field, in Pointe Coupe Parish, Louisiana, were investigated to characterize the environment of natural gas in the downdip Tuscaloosa trend. The average production depth in the Judge Digby field is approximately 22,000 ft. Temperatures as high as 400 degrees F are typically found at depth in Judge Digby field and are anomalously low when compared to temperature trends extrapolated to similar depths regionally. At 22,000 ft, the minimum and maximum temperatures for all reservoirs in Gulf Coast producing gas fields are 330 and 550 degrees F, respectively; the average temperature is 430 degrees F. The relatively depressed geothermal gradients in the Judge Digby field may be due to high rates of sediment preservation, which may have delayed the thermal equilibration of the sediment package with respect to the surrounding rock. Analyzing burial history and thermal maturation indicates that the deep Tuscaloosa trend in the Judge Digby field is currently in the gas generation window. Using temperature trends as an exploration tool may have important implications for undiscovered hydrocarbons at greater depths in currently producing reservoirs, and for settings that are geologically analogous to the Judge Digby fiel

Open-File Report↗
USGS2011

Digital signal processing and interpretation of full waveform sonic log for well BP-3-USGS, Great Sand Dunes National Park and Preserve, Alamosa County, Colorado

Along the Great Sand Dunes National Park and Preserve boundary (fig. 1), 10 monitoring wells were drilled by the National Park Service in order to monitor water flow in an unconfined aquifer spanning the park boundary. Adjacent to the National Park Service monitoring well named Boundary Piezometer Well No. 3, or BP-3, the U.S. Geological Survey (USGS) drilled the BP-3-USGS well. This well was drilled from September 14 through 17, 2009, to a total depth of 99.4 meters (m) in order to acquire additional subsurface information. The BP-3-USGS well is located at lat 37 degrees 43'18.06' and long -105 degrees 43'39.30' at a surface elevation of 2,301 m. Approximately 23 m of core was recovered beginning at a depth of 18 m. Drill cuttings were also recovered. The wireline geophysical logs acquired in the well include natural gamma ray, borehole caliper, temperature, full waveform sonic, density, neutron, resistivity, and induction logs. The BP-3-USGS well is now plugged and abandoned. This report details the full waveform digital signal processing methodology and the formation compressional-wave velocities determined for the BP-3-USGS well. These velocity results are compared to several velocities that are commonly encountered in the subsurface. The density log is also discussed in context of these formation velocities.

Scientific Investigations Report↗
USGS2011

Carbon dioxide fluid-flow modeling and injectivity calculations

At present, the literature lacks a geologic-based assessment methodology for numerically estimating injectivity, lateral migration, and subsequent long-term containment of supercritical carbon dioxide that has undergone geologic sequestration into subsurface formations. This study provides a method for and quantification of first-order approximations for the time scale of supercritical carbon dioxide lateral migration over a one-kilometer distance through a representative volume of rock. These calculations provide a quantified foundation for estimating injectivity and geologic storage of carbon dioxide. A geologic-based approach was developed in which subsurface pressure and temperature conditions were held constant while the petrophysical properties of fractional porosity and matrix permeability were varied simultaneously. The Span and Wagner equations of state were used to determine thermophysical properties of carbon dioxide at appropriate reservoir conditions. The fluid-flow calculations assume mass transport through a laterally continuous, homogeneous isotropic formation and were based on two constitutive equations from fluid dynamics: hydraulic diffusivity for near-surface applications, and a modified version of Darcy's Law for deeper formations exhibiting higher pressure gradients. The first-order approximations of the lateral migration time scales, for both hydraulic diffusivity and Darcy flow, can be expressed as a quasi-linear function over a range of porosity and permeability values. This method is applicable to a substantial range of sedimentary formations exhibiting porosities up to 95 percent and permeabilities from 10.0 darcy to 1.0 picodarcy. These results were used to classify subsurface formations into three permeability classifications for the probabilistic calculations of storage efficiency and containment risk of the U.S. Geological Survey geologic carbon sequestration assessment methodology. This methodology is currently in use to determine the total carbon dioxide containment capacity of the onshore and State waters areas of the United States.

Scientific Investigations Report↗
USGS2010

Comprehensive database of wellbore temperatures and drilling mud weight pressures by depth for Judge Digby field, Louisiana

This document serves as the repository for the unprocessed data used in the investigation of temperature and overpressure relations within the deep Tuscaloosa Formation in Judge Digby field. It is a compilation of all the publicly accessible wellbore temperature and pressure data for Judge Digby field, a prolific natural gas field producing from the Upper Cretaceous lower part of the Tuscaloosa Formation in the Gulf Coast region. This natural gas field is in Pointe Coupee Parish in the southern part of onshore Louisiana.

Open-File Report↗