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Lauri A. Burke

Publications and source records attributed to Lauri A. Burke.

At least 19 recordsLinked to original sources
USGS2025

Assessment of undiscovered oil and gas resources in the Lower Cretaceous Hosston and Travis Peak Formations, U.S. Gulf Coast, 2024

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 28 million barrels of oil and 35.8 trillion cubic feet of gas in conventional and continuous accumulations within the Lower Cretaceous Hosston and Travis Peak Formations of the onshore U.S. Gulf Coast region.

Alabama, Arkansas, Georgia, Louisiana, Mississippi↗
USGS2025

Geologic models underpinning the 2024 U.S. Geological Survey assessment of undiscovered oil and gas resources in the Hosston and Travis Peak Formations of the onshore Gulf Coast region, U.S.A.

The Early Cretaceous (Berriasian–Hauterivian) Hosston Formation in Louisiana and eastward is time correlative to the Travis Peak Formation of Texas and southern Arkansas. The formation is a first-order clastic sequence with a regional carbonate transgressive surface as an upper contact. The Hosston and Travis Peak formations contain conventional natural gas and oil accumulations that have been produced for nearly a century. These mature reservoirs contain terrigenous fluvial-deltaic, shore-zone, and paralic deposits across the productive trend; organic-lean mudstone and siltstone lithologies are found outboard of the Lower Cretaceous shelf margin. Producing reservoirs exhibit normal pressure gradients from 0.43 to 0.55 psi/ft (9.7 to 12.4 kpa/m), depths from 4000 to over 20,000 ft (1220 to 6100 m), and temperatures from 150 to 385°F (65 to 196°C). Wells are primarily vertical completions. The number of new field wildcats has been declining since the late 1990s. This paper presents comprehensive geologic models, which include lithofacies maps, structure and isopach maps, burial history models, regional seismic interpretations, and events charts that underpin the recently completed U.S. Geological Survey assessment of undiscovered, technically recoverable hydrocarbons within the Hosston and Travis Peak formations. This study also provides geographic and stratigraphic distributions of Hosston–Travis Peak reservoir properties, including geopressure, reservoir temperature, porosity, permeability, API gravity, and gas-oil ratios. Results indicate estimated undiscovered, technically recoverable mean resources of 28 million barrels of oil and 35.8 trillion cubic ft of gas in conventional and continuous accumulations within the Lower Cretaceous Hosston and Travis Peak formations of the onshore U.S. Gulf Coast region. Quantitative assessment results are detailed in U.S. Geological Survey Fact Sheet 2025–3021 and associated Data Release.

GCAGS Journal↗
USGS2022

Velocity modeling of supercritical pore fluids through porous media under reservoir conditions with applications for petroleum secondary migration and carbon sequestration plumes

Computational methods to characterize secondary migration in porous media traditionally rely on fluid transport equations with assumptions of time invariance, such as flowpath modeling of buoyancy vectors, statistical percolation algorithms, capillary pressure curves, or a form of Darcy’s Law which presumes instantaneous fluid transport. However, in petroleum systems modeling, the timeframe of secondary migration from source to reservoir is important to quantify in relation to other geologic factors such as timing of petroleum generation, fault movement, and seal formation. Additionally, quantifying migration velocities enables an estimation of the distance a plume of geologically sequestered carbon dioxide travels over time, as well as the identification of low-permeability strata appropriate for long-term containment. This study introduces a method to quantify transport velocities of supercritical fluids in low-permeability lithologies for a broad range of rock and fluid properties likely encountered in the sedimentary sequence. A time-dependent form of Darcy’s Law for pressure-driven viscous flow through homogeneous isotropic porous media was used to model flow velocities within a carrier bed. Thermodynamic equations of state were used to determine thermophysical properties of supercritical pore fluids under reservoir pressures ranging from 0–200 MPa (0–29,000 psi) to constrain the momentum equations. Three case studies were examined that (1) estimated fluid flow velocities of methane within the low-permeability Upper Jurassic Haynesville Formation, (2) defined permeability-based flow units to evaluate saline formations for long-term geologic carbon sequestration, and (3) calculated the migration distance of carbon dioxide plumes at the Decatur, Illinois injection and sequestration project.

SEG-AAPG Interpretation↗
USGS2022

Geologic models underpinning the 2018 US Geological Survey assessment of hydrocarbon resources in the Eagle Ford Group and associated Cenomanian–Turonian strata, United States Gulf Coast, Texas

The availability of new geologic and production data has greatly increased since 2010, when the US Geological Survey (USGS) last assessed undiscovered, technically recoverable oil and gas resources in the Cenomanian–Turonian (CT) Eagle Ford Group (EFG) across Texas. This new information facilitated an updated assessment of undiscovered continuous oil and gas resources in the Eagle Ford and associated CT strata. Literature and USGS research data were used to build the geologic models for the assessment units (AUs). The USGS defined six continuous AUs within the EFG: (1) Eagle Ford Marl Continuous Oil, (2) Eagle Ford Marl Continuous Gas, (3) Submarine Plateau-Karnes Trough Continuous Oil, (4) Submarine Plateau-Karnes Trough Continuous Gas, (5) CT Mudstone Continuous Oil, and (6) CT Mudstone Continuous Gas. An additional AU, the CT Slope Continuous Gas AU, was defined but not quantitatively assessed. The boundaries of these AUs were defined by thickness, lithofacies, thermal maturity, regional geology, and the spatial distribution of productive fairways. The resulting total mean estimates for undiscovered, technically recoverable resources for these six AUs are 8.5 billion bbl of oil and 66 trillion ft 3 of gas. These results for both oil and gas resources are within the top five volumes of previously assessed continuous accumulations in the United States and attest to the importance of the EFG and associated CT strata as a significant source of petroleum well into the future.

Texas↗
USGS2021

Multimineral petrophysics of thermally immature Eagle Ford Group and Cretaceous mudstones, U.S. Geological Survey Gulf Coast 1 research wellbore in central Texas

Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma-ray and resistivity log responses are not diagnostic in source rocks. We have developed a deterministic, nonproprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of nonhydrocarbon-bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with Fourier transform infrared spectroscopy core data from the research borehole U.S. Geological Survey Gulf Coast 1 West Woodway. We determined that bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks. Multimineral findings indicate that a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7 wt%) and the highest average carbonate volume (64.1 vol%), making it the optimal target in thermally mature areas for source-rock potential and hydraulic-fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6 vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals that porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87°F/100 ft (16.3°C/km) and is likely influenced by earth surface heating.

Texas↗
USGS2021

Quantitative modeling of secondary migration: Understanding the origin of natural gas charge of the Haynesville Formation in the Sabine Uplift area of Louisiana and Texas

The Upper Jurassic (Kimmeridgian) mudstones of the Haynesville Formation in the Sabine Uplift, Louisiana and Texas, are widely considered to be a self-sourced natural gas reservoir; however, additional sources of gas may have charged the mudstones in the Louisiana portion of the uplift. Secondary migration of hydrocarbons into the Sabine Uplift from downdip, gas-generating Jurassic source rocks in the North Louisiana Salt Basin was quantitively modeled in this study. Jurassic source rocks include the Smackover, Haynesville, and Bossier Formations. Thermodynamic equations of state were used to determine thermophysical properties of supercritical methane and water under reservoir conditions. A time-dependent derivation of Darcy’s Law for pressure-driven laminar fluid flow through porous media was used to model secondary migration at reservoir conditions. This study indicates secondary migration requires approximately 100,000 yr for pore fluids to migrate through 1.0 km of carrier beds having representative petrophysical, fluid, and reservoir properties of the Haynesville Formation. As an example migration pathway, the distance from the middle of the North Louisiana Salt Basin to the center of the Sabine Uplift is approximately 96 mi (155 km). Given migration velocities over this distance, 15.5 m.y. is required for hydrocarbons to migrate from the North Louisiana Salt Basin and charge the Haynesville Formation in the Sabine Uplift. This study also indicates supercritical water is 6 times more thermally conductive than methane under reservoir conditions; however, the relatively small volumes of migrated water likely did not transfer sufficient heat for the metagenesis of methane. Based on this study, a component of natural gas charging the Haynesville Formation of the Sabine Uplift area can reasonably be explained by lateral migration and hydrodynamic flow from thermally mature Jurassic source rocks located in adjacent basins.

Louisiana, Texas↗
USGS2020

Assessment of undiscovered oil and gas resources in the Upper Cretaceous Austin Chalk and Tokio and Eutaw Formations, U.S. Gulf Coast, 2019

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 6.9 billion barrels of oil and 41.5 trillion cubic feet of natural gas in conventional and continuous accumulations in the Upper Cretaceous Austin Chalk and Tokio and Eutaw Formations onshore and in State waters of the U.S. Gulf Coast region.

Alabama, Arkansas, Louisiana, Mississippi, Oklahom↗
USGS2020

Assessment of water and proppant quantities associated with petroleum production from the Eagle Ford Group, Gulf Coast, Texas, 2019

Building on a geology-based assessment of undiscovered, technically recoverable petroleum resources in the Eagle Ford Group in south Texas, the U.S. Geological Survey has estimated the required water and proppant demands and formation water production volumes associated with possible future development of these petroleum resources. The results of the water and proppant assessment are presented here, along with related drilling information and relevant water budget volumes for the region.

Texas↗
USGS2020

New method for correcting bottomhole temperatures acquired from wireline logging measurements and calibrated for the onshore Gulf of Mexico Basin, U.S.A.

Bottomhole temperature (BHT) measurements offer a useful way to characterize the subsurface thermal regime as long as they are corrected to represent in situ reservoir temperatures. BHT correction methods calibrated for the domestic onshore Gulf of Mexico basin were established in this study. These corrections are empirically derived and based on newly compiled databases of BHT wireline measurements and, to a lesser extent, drill stem test data. A unified BHT correction for the onshore Gulf Coast region, as well as 12 distinct BHT correction equations for each of the 12 physiographic provinces within the onshore Gulf Coast region, are provided. This study also characterizes the geothermal gradient across the onshore Gulf of Mexico basin, which ranges from 1.89 degrees Fahrenheit per 100 feet in the Sabine Uplift area to 1.39 degrees Fahrenheit per 100 feet in the Southern Louisiana Salt Basin. This report disseminates the slides presented at the 68th annual convention of the Gulf Coast Association of Geological Societies and the Gulf Coast Section of the Society of Economic Paleontologists and Mineralogists that was held September 30–October 2, 2018, in Shreveport, Louisiana.

Alabama, Arkansas, Louisiana, Mississippi, Texas↗
USGS2018

U.S. Geological Survey input-data forms for the assessment of the Upper Jurassic Haynesville Formation, U.S. Gulf Coast, 2016

Introduction In 2016, the U.S. Geological Survey (USGS) completed an updated assessment of undiscovered, technically recoverable oil and gas resources in the Upper Jurassic Haynesville Formation of the onshore U.S. Gulf Coast Province (Paxton and others, 2017). The Haynesville Formation was assessed using both the standard continuous (unconventional) and conventional methodologies established by the USGS for four assessment units (AUs): (1) Haynesville Western Shelf Carbonate Gas and Oil AU, (2) Haynesville Eastern Shelf Sandstone and Carbonate Oil and Gas AU, (3) Haynesville Shale Continuous Gas AU, and (4) Haynesville Shale Peripheral Continuous Gas AU. The revised assessment resulted in total estimated mean resources of 1.1 billion barrels of oil, 195.8 trillion cubic feet of gas, and 866 million barrels of natural gas liquids. The purpose of this report is to provide supplemental documentation of the input parameters used in the USGS 2016 Haynesville Formation assessment.

Open-File Report↗
USGS2018

U.S. Geological Survey input-data forms for the assessment of the Upper Jurassic Bossier Formation, U.S. Gulf Coast, 2016

Introduction In 2016, the U.S. Geological Survey (USGS) completed an updated assessment of undiscovered, technically recoverable oil and gas resources in the Upper Jurassic Bossier Formation of the onshore U.S. Gulf Coast Province (Paxton and others, 2017). The Bossier Formation was assessed using both the standard continuous (unconventional) and conventional methodologies established by the USGS for three assessment units (AUs): (1) Bossier Eastern Shelf Sandstone Gas and Oil AU, (2) Bossier Western Shelf Sandstone Gas AU, and (3) Bossier Shale Continuous Gas AU. A fourth assessment unit, the Upper Jurassic Downdip Continuous Gas AU, was also defined but was not quantitatively assessed because of limited well data within the extent of the AU. The revised assessment resulted in total estimated mean resources of 2.9 billion barrels of oil, 108.6 trillion cubic feet of gas, and 1.1 billion barrels of natural gas liquids. The purpose of this report is to provide supplemental documentation of the input parameters used in the USGS 2016 Bossier Formation assessment.

Open-File Report↗
USGS2018

Assessment of undiscovered oil and gas resources in the Eagle Ford Group and associated Cenomanian–Turonian Strata, U.S. Gulf Coast, Texas, 2018

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 8.5 billion barrels of oil and 66 trillion cubic feet of gas in continuous accumulations in the Upper Cretaceous Eagle Ford Group and associated Cenomanian–Turonian strata in onshore lands of the U.S. Gulf Coast region, Texas.

Louisiana, Texas↗
USGS2018

Methodology for correcting bottomhole temperatures acquired from wireline logging measurements in the onshore U.S. Gulf of Mexico Basin to characterize the thermal regime of total petroleum systems

Characterization of the subsurface thermal regime is critical for understanding many facets of the petroleum system, from thermal maturation of organic-rich source rocks to thermal preservation and non-degradation of hydrocarbon accumulations. On a broad scale, paleo-heatflow has been mapped for the North American continent (Blackwell and Richards, 2004) as well as the contiguous United States (Blackwell et al., 2011). However, in situ reservoir temperature is a fundamental property (Cooper and Jones, 1959) that is difficult to accurately measure in the subsurface (Deming, 1989). Previous work has described the thermal regime of the offshore U.S. Gulf of Mexico Basin (Waples et al., 2004; Forrest et al., 2005; Nagihara and Jones, 2005; Husson et al., 2008); however, due to the lack of an applicable bottomhole temperature (BHT) correction method, virgin rock temperatures of the onshore portion of the basin remains largely uncharacterized in a regional or subregional context. The abundance of BHT measurements offers a useful way to characterize the subsurface thermal environment, provided that they are corrected to reflect the reservoir temperature. This study develops BHT correction methods that are specifically calibrated for the onshore U.S. Gulf of Mexico Basin. These BHT corrections are empirically derived and are based on a newly compiled database of temperatures obtained from BHT wireline measurements and, to a lesser extent, from drill stem test (DST) data. The results of this investigation provide a unified BHT correction methodology for the onshore U.S. Gulf of Mexico Basin as well as provide 12 distinct BHT correction equations for each of the 12 physiographic provinces within the onshore Gulf Coast region. This study also characterizes the geothermal gradient regime across the onshore U.S. Gulf Coast, which ranges from 1.89ºF/100 ft in Sabine Uplift area to 1.39ºF/100 ft in the Southern Louisiana Salt Basin.

Gulf of Mexico Basin↗
USGS2013

Regional maps of subsurface geopressure gradients of the onshore and offshore Gulf of Mexico basin

The U.S. Geological Survey created a comprehensive geopressure-gradient model of the regional pressure system spanning the onshore and offshore Gulf of Mexico basin, USA. This model was used to generate ten maps that included (1) five contour maps characterizing 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; and (2) five supporting maps illustrating the spatial density of the data used to construct the contour maps. These contour maps of isopressure-gradients at various increments enable the identification and quantification of the occurrence, magnitude, location, and depth of the subsurface pressure system, which allows for the broad characterization of regions exhibiting overpressured, underpressured, and normally pressured strata. Identification of overpressured regions is critical for exploration and evaluation of potential undiscovered hydrocarbon accumulations based on petroleum-generation pressure signatures and pressure-retention properties of reservoir seals. Characterization of normally pressured regions is essential for field development decisions such as determining the dominant production drive mechanisms, evaluating well placement and drainage patterns, and deciding on well stimulation methods such as hydraulic fracturing. Identification of underpressured regions is essential for evaluating the feasibility of geological sequestration and long-term containment of fluids such as supercritical carbon dioxide for alternative disposal methods of greenhouse gases. This study is the first, quantitative investigation of the regional pressure systems of one of the most important petroleum provinces in the United States. Although this methodology was developed for pressure studies in the Gulf of Mexico basin, it is applicable to any basin worldwide.

Open-File Report↗
USGS2012

Distribution of regional pressure in the onshore and offshore Gulf of Mexico basin, USA

The U.S. Geological Survey (USGS) has created a comprehensive geopressure-gradient model of the regional pressure system spanning the onshore and offshore portions of the Gulf of Mexico, USA. The model was used to generate ten maps: five contour maps (Maps 1A - 5A) 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, and five supporting maps (Maps 1B - 5B) display the spatial density of the data used to construct the isopressure-gradient maps. The boundary of the geopressure-gradient model represents the maximum extent of the calculated pressure-gradient data. The regional investigation, however, encompassed an area defined by the USGS Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System Boundary, and the availability of offshore data. A description of the geopressure-gradient model, including related mathematical derivations, the data-quality control methodology, linear pressure interpolation calculations, and contouring algorithms is provided by Burke et al. (in press [a]; in press [b]); these references, as well as a summary of the geopressure-gradient model, are supplied in the online documentation .

Gulf of Mexico↗
USGS2012

Regional map of the 0.70 psi/ft pressure gradient and development of the regional geopressure-gradient model for the onshore and offshore Gulf of Mexico basin, USA

Characterization of the regional pressure system in the Gulf of Mexico basin is critical for assessing the occurrence of undiscovered petroleum resources, evaluating areas with potential pressure-related production, identifying potential pressure-related geohazard issues, evaluating hydrocarbon reservoir-seal integrity, and determining the feasibility of geological sequestration and long-term containment of fluids.

Gulf of Mexico↗