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USGS2015

Introduction to special section: China shale gas and shale oil plays

In the last 10 years, the success of shale gas and shale oil productions as a result of technological advances in horizontal drilling, hydraulic fracturing and nanoscale reservoir characterization have revolutionized the energy landscape in the United States. Resource assessment by the China Ministry of Land and Resources in 2010 and 2012 and by the U.S. Energy Information Administration in 2011 and 2013 indicates China’s shale gas resource is the largest in the world and shale oil resource in China is also potentially significant. Inspired by the success in the United States, China looks forward to replicating the U.S. experience to produce shale gas to power its economy and reduce greenhouse gas emissions. By 2014, China had drilled 400 wells targeting marine, lacustrine, and coastal swamp transitional shales spanning in age from the Precambrian to Cenozoic in the last five years. So far, China is the leading country outside of North America in the viable production of shale gas, with very promising prospects for shale gas and shale oil development, from the Lower Silurian Longmaxi marine shale in Fuling in the southeastern Sichuan Basin. Geological investigations by government and academic institutions as well as exploration and production activities from industry indicate that the tectonic framework, depositional settings, and geomechanical properties of most of the Chinese shales are more complex than many of the producing marine shales in the United States. These differences limit the applicability of geologic analogues from North America for use in Chinese shale oil and gas resource assessments, exploration strategies, reservoir characterization, and determination of optimal hydraulic fracturing techniques. Understanding the unique features of the geology, shale oil and gas resource potential, and reservoir characteristics is crucial for sweet spot identification, hydraulic fracturing optimization, and reservoir performance prediction. Even though China shale gas and shale oil exploration is still in an early stage, limited data are already available. We are pleased to have selected eight high-quality papers from fifteen submitted manuscripts for this timely section on the topic of China shale gas and shale oil plays. These selected papers discuss various subject areas including regional geology, resource potentials, integrated and multidisciplinary characterization of China shale reservoirs (geology, geophysics, geochemistry, and petrophysics) China shale property measurement using new techniques, case studies for marine, lacustrine, and transitional shale deposits in China, and hydraulic fracturing. One paper summarizes the regional geology and different tectonic and depositional settings of the major prospective shale oil and gas plays in China. Four papers concentrate on the geology, geochemistry, reservoir characterization, lithologic heterogeneity, and sweet spot identification in the Silurian Longmaxi marine shale in the Sichuan Basin in southwest China, which is currently the primary focus of shale gas exploration in China. One paper discusses the Ordovician Salgan Shale in the Tarim Basin in northwest China, and two papers focus on the reservoir characterization and hydraulic fracturing of Triassic lacustrine shale in the Ordos Basin in northern China. Each paper discusses a specific area.

Interpretation↗

USGS2022

Comprehensive pressure core analysis for hydrate-bearing sediments from Gulf of Mexico Green Canyon Block 955, including assessments of geomechanical viscous behavior and nuclear magnetic resonance permeability

Quantifying the petrophysical and geomechanical properties of gas hydrate reservoirs is essential for understanding the natural hydrate system and predicting gas production behavior for future resource development. Pressure-core analysis tools were used to characterize methane hydrate–bearing sediments recovered from the Gulf of Mexico Green Canyon Block 955, under an international collaboration with The University of Texas and the National Institute of Advanced Industrial Science and Technology. Pressure-core samples were successfully transferred from Austin, Texas to Sapporo, Japan. Index property measurements (grain size, grain density, hydration number, gas composition, thermal conductivity), along with triaxial compression, consolidation, and permeability tests with a nuclear magnetic resonance (NMR) analyzer were conducted. Compression tests at different strain rates confirmed a strain rate dependence for hydrate-bearing sediment, and an equation for predicting strength as a function of hydrate saturation and strain rate is proposed. Compression and swelling indices were obtained from high-effective stress consolidation tests. Furthermore, secondary compression coefficients for hydrate-bearing sediments were obtained, suggesting that hydrate exhibits creeping behavior on timescales of minutes to hours. A relatively high initial permeability of a few millidarcys was confirmed. In addition, the first NMR signal measurement was performed on a hydrate-bearing pressure core to acquire the NMR transverse or spin-spin ( T 2 ) distribution. Results confirm that the Schlumberger Doll Research model and Timur-Coates model predictions underestimate permeability measured directly via fluid flow. Permeability estimated using specific surface values derived from NMR T 2 distributions is in good agreement with flow test results. Finally, an extended Timur-Coates model was proposed and predicts intrinsic permeability with high accuracy.

Texas↗

USGS2022

Permeability of methane hydrate-bearing sandy silts in the deep-water Gulf of Mexico (Green Canyon Block 955)

Permeability is one of the most crucial properties governing fluid flow in methane hydrate reservoirs. This paper presents a comprehensive permeability analysis of hydrate-bearing sandy silt pressure-cored from Green Canyon Block 955 (GC 955) in the deep-water Gulf of Mexico. We developed an experimental protocol to systematically characterize the transport and petrophysical properties in pressure cores. The in situ effective permeability ranges from 0.1 md (1.0 × 10 −16 m 2 ) to 2.4 md (2.4 × 10 −15 m 2 ) in these natural sandy silts cores with hydrate occupying 83%–93% of the pore space. When hydrate dissociates from these cores, the measured intrinsic permeability ( k 0 ) is 0.3 md (3.0 × 10 −16 m 2 ) to 9.3 md (9.3 × 10 −15 m 2 ); these results are affected by fines migration during hydrate dissociation. We analyzed samples reconstituted from these sandy silts and found k 0 to range from ∼12 md (∼1.2 × 10 −14 m 2 ) to ∼41 md (∼4.1 × 10 −14 m 2 ). The water relative permeabilities ( k rw ) of GC 955 pressure cores are large relative to other natural pressure cores from offshore Japan, offshore India, and onshore Alaska. These k rw values are also higher than predicted by current conceptual relative permeability models where hydrate fills the pores or coats the grains of the sediments. This fundamental conundrum requires further study. Our work provides essential parameters to reservoir simulation models seeking to predict hydrate formation in geological systems, evaluate the gas production potential, and explore the best way to produce this energy resource in sandy silt reservoirs.

Louisiana↗

USGS2016

Sedimentary petrology and reservoir quality of the Middle Jurassic Red Glacier Formation, Cook Inlet forearc basin: Initial impressions

The Division of Geological & Geophysical Surveys and Division of Oil & Gas are currently conducting a study of the hydrocarbon potential of Cook Inlet forearc basin (Gillis, 2013, 2014; LePain and others, 2013; Wartes, 2015; Herriott, 2016 [this volume]). The Middle Jurassic Tuxedni Group is recognized as a major source of oil in Tertiary reservoirs (Magoon, 1994), although the potential for Tuxedni reservoirs remains largely unknown. As part of this program, five days of the 2015 field season were spent examining outcrops, largely sandstones, of the Middle Jurassic Red Glacier Formation (Tuxedni Group) approximately 6.4 km northeast of Johnson Glacier on the western side of Cook Inlet (fig. 4-1). Three stratigraphic sections (fig. 4-2) totaling approximately 307 m in thickness were measured and described in detail (LePain and others, 2016 [this volume]). Samples were collected for a variety of analyses including palynology, Rock-Eval pyrolysis, vitrinite reflectance, detrital zircon geochronology, and petrology. This report summarizes our initial impressions of the petrology and reservoir quality of sandstones encountered in these measured sections. Interpretations are based largely on hand-lens observations of hand specimens and are augmented by stereomicroscope observations. Detailed petrographic (point-count) analyses and measurement of petrophysical properties (porosity, permeability, and grain density) are currently in progress.

Alaska↗

USGS2024

Sensitivity testing of marine turbidite age estimates along the Cascadia subduction zone

9 earthquakes ruptured the full Cascadia subduction zone (CSZ) in the past 10 kyr, a hypothesis that relies on concurrent turbidite deposition generated from seismogenic strong ground motion along the ∼1100 km margin. Correlation of marine turbidite deposits is based on petrophysical characteristics and radiocarbon geochronology, the latter of which relies on a series of age corrections and calibrations for marine radiocarbon age and sedimentological parameters. In this work, I isolate several key variables in turbidite age assessment and systematically test how previous assumptions and new calibration curves affect estimated ages, and thus whether geochronologic analyses independently support coeval turbidite deposition. For radiocarbon age calibration, I test the impact of (1) updating global marine reservoir age corrections; (2) updating local marine reservoir age estimates; and (3) selectively applied marine reservoir age excursions. From the calibrated radiocarbon ages, I calculate turbidite age and uncertainty using a Monte Carlo approach with a broad range of sedimentation rates and substratal erosion. By simply updating the global marine radiocarbon calibration, individual radiocarbon ages differ from published estimates by several hundred years. Updates to the local reservoir age corrections are minimal because existing data remain limited yet have potential for great impact on turbidite ages. Of the sedimentological parameters tested, sedimentation rate has the largest impact on estimated turbidite age, with individual ages changing up to 500 yr from published estimates. For radiocarbon samples of turbidites previously inferred to correlate, the individual ages typically show increased scatter and overall uncertainty, even for models that only update the global marine reservoir calibration. These results highlight the major age uncertainty associated with current coseismic turbidite age analyses in Cascadia and how independent constraints on local reservoir corrections and sedimentation rate are critical for accurate turbidite age estimates in the Pacific Northwest.

Bulletin of the Seismological Society of America↗

USGS2026

An integrated mudstone facies classification scheme and revised interpretation of the sedimentologic processes driving carbon burial in the Cenomanian–Turonian Greenhorn Formation, Colorado, U.S.A.

Standardizing facies descriptions has proven key to integrating interpretations of depositional processes and environments from sedimentologic observations with geochemistry data for mudstone lithologies. Because of their fine-grained nature, high degree of compaction, and heterogeneous composition, standardizing methods for mudstone descriptions has proven difficult, but it is critical to formulating meaningful interpretations of the processes that govern the accumulation of organic-rich lithologies and their role in both petroleum systems and the global carbon cycle. In this study, we have developed a modified facies classification scheme for mudstone lithologies that incorporates sedimentologic and compositional observation at the hand-sample and thin-section scales with geochemical measurements, including bulk organic and inorganic geochemistry, to characterize these rocks and their variability more completely for improved interpretations of depositional environments during a low-order sea-level transgression. The facies described in this study are of the Cenomanian–Turonian Greenhorn Formation in the USGS #1 Portland Core drilled in Fremont County, Colorado. Strata of the Greenhorn Formation span Oceanic Anoxic Event 2 (OAE-2) and the preceding interval. Lithologies range from organic-rich argillaceous mudstones with varied sedimentary structures to organic-lean, highly bioturbated limestones. Six facies were identified, each differentiated by varied sedimentary structures and geochemical composition. These facies occur in a predictable stratigraphic stacking pattern that represents a low-order sea-level transgression with interpreted depositional environments ranging from terrigenous-dominated pro-delta and muddy continental shelf at the base of the interval to pelagic offshore marine at the top of the Greenhorn Formation. Though the facies are consistent with previous interpretations of depositional environments at this locale in the Cretaceous Western Interior Seaway during the Greenhorn cyclothem, the sedimentary processes governing the accumulation of organic-rich strata that have defined this interval are significantly revised. Variability in the proximity and intensity of bottom currents driven by storms and geostrophic flows were key to the accumulation of each facies, with significant sediment transport occurring even through deposition in the most oxygen-depleted bottom waters. The methodology and interpretations provided here are now being employed to basin-scale predictions of organic enrichment utilizing calibrated petrophysical methods. The approach and results from this study improve understanding of how organic and inorganic carbon was sequestered during perturbations to the global carbon cycle associated with events such as OAE-2.

Colorado↗

USGS2011

Hydrogeophysical investigations at Hidden Dam, Raymond, California

Self-potential and direct current resistivity surveys are carried out at the Hidden Dam site in Raymond, California to assess present-day seepage patterns and better understand the hydrogeologic mechanisms that likely influence seepage. Numerical modeling is utilized in conjunction with the geophysical measurements to predict variably-saturated flow through typical two-dimensional dam cross-sections as a function of reservoir elevation. Several different flow scenarios are investigated based on the known hydrogeology, as well as information about typical subsurface structures gained from the resistivity survey. The flow models are also used to simulate the bulk electrical resistivity in the subsurface under varying saturation conditions, as well as the self-potential response using petrophysical relationships and electrokinetic coupling equations. The self-potential survey consists of 512 measurements on the downstream area of the dam, and corroborates known seepage areas on the northwest side of the dam. Two direct-current resistivity profiles, each approximately 2,500 ft (762 m) long, indicate a broad sediment channel under the northwest side of the dam, which may be a significant seepage pathway through the foundation. A focusing of seepage in low-topography areas downstream of the dam is confirmed from the numerical flow simulations, which is also consistent with past observations. Little evidence of seepage is identified from the self-potential data on the southeast side of the dam, also consistent with historical records, though one possible area of focused seepage is identified near the outlet works. Integration of the geophysical surveys, numerical modeling, and observation well data provides a framework for better understanding seepage at the site through a combined hydrogeophysical approach.

California↗

USGS2024

Terrebonne Basin northern Gulf of Mexico, 30 July-28 September 2023

In the summer and fall of 2023, the Gulf of Mexico Deepwater Hydrate Coring Expedition (UT-GOM2-2) drilled, cored, made downhole measurements, and analyzed samples from the seafloor to the base of the gas hydrate stability zone in one location (Site H, WR313) in the Terrebonne basin, deepwater Gulf of Mexico. Analyses of data and samples from the expedition will inform biological, geochemical, and geomechanical models to constrain the role of gas hydrates in the carbon cycle and the potential for gas hydrates as an energy resource. Pressure and conventional cores were collected continuously to a depth of 155.1 meters below the seafloor (mbsf). At deeper depths, cores were taken periodically from hydrate-bearing sands and their bounding muds to a total depth of 861.3 mbsf. 162.6 m of conventional core and 54.8 m of pressure core were obtained. Twelve temperature measurements were made between 27.1 and 144.5 mbsf to determine the geothermal gradient. At the seafloor, more than 4 m of sandy silt of unknown origin was encountered. Beneath this sand, to a depth of ~200 mbsf, the section was composed of interbedded mud and biogenic carbonate ooze. The biogenic ooze correlated to low density and high porosity intervals observed in the previously acquired logging while drilling (LWD) data and as measured. Calcareous nannofossil biostratigraphy constrains the entire record to the Pleistocene (< 0.91 million years) with a pronounced increase in sedimentation rate with depth. Beneath 200 mbsf, the section was predominantly composed of mud with two thicker, hydrate-bearing coarse-grained intervals, which are commonly known as the Blue and Orange sands. The dissolved gas concentration was quantified from pressure cores. In the shallow section, dissolved methane concentration increased below the sulfate-methane transition zone (SMTZ) and reaches saturation (the limit of solubility for methane) at 147 mbsf. Gas expansion was very common in conventional and depressurized pressure (conventionalized) cores below the SMTZ. At deeper depths, the methane concentration within muds bounding the Blue and Orange reservoirs was generally found to be less than saturation. The dissolved and hydrate gas composition is consistent with a microbial source, containing greater than 99.99% methane and only trace concentrations of ethane, propane, and butane. The methane to ethane ratio (C 1 /C 2 ) and the methane to ethane plus propane (C 1 /(C 2 +C 3 )) decrease with depth down to at least 678 mbsf, mainly driven by the increase in ethane with depth. It is unclear if this trend continues through the Orange sand interval. The δ 13 C isotopic signature of methane ranges between -69.9 and -78.5 ‰ Vienna Pee Dee Belemnite (VPDB). Pressure core recovery of all sandy intervals was poor. However, pressure core logs of the Orange sand show intervals of low density and high velocity, which are indicative of high hydrate saturation. One core from within the Orange sand was composed of interbedded graded sandy silt and mud. The sandy silts from this core are composed of mainly quartz and feldspar with some lithics. Most of the recovered pressure core samples are maintained at near in-situ pressure and temperature (within the hydrate stability field) at the University of Texas Pressure Core Center awaiting analysis. In the shallow section, samples will be used to determine the flux of organic carbon through the basin system, find the rate at which that carbon was consumed, and understand the microbial population responsible for these processes. In the deeper section, samples from in and around the hydrate reservoirs will be used to determine the petrophysical properties of the reservoir and bounding seals in these systems.

Gulf of Mexico, Terrebonne Basin↗

USGS2007

Executive Summary — Assessment of undiscovered oil and gas resources of the San Joaquin Basin Province of California, 2003

In 2003, the U.S. Geological Survey (USGS) completed an assessment of the oil and gas resource potential of the San Joaquin Basin Province of California (fig. 1.1). The assessment is based on the geologic elements of each Total Petroleum System defined in the province, including hydrocarbon source rocks (source-rock type and maturation and hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined five total petroleum systems and ten assessment units within these systems. Undiscovered oil and gas resources were quantitatively estimated for the ten assessment units (table 1.1). In addition, the potential was estimated for further growth of reserves in existing oil fields of the San Joaquin Basin.

California↗

USGS1984

Computer analysis of digital well logs

A comprehensive system of computer programs has been developed by the U.S. Geological Survey for analyzing digital well logs. The programs are operational on a minicomputer in a research well-logging truck, making it possible to analyze and replot the logs while at the field site. The minicomputer also serves as a controller of digitizers, counters, and recorders during acquisition of well logs. The analytical programs are coordinated with the data acquisition programs in a flexible system that allows the operator to make changes quickly and easily in program variables such as calibration coefficients, measurement units, and plotting scales. The programs are designed to analyze the following well-logging measurements: natural gamma-ray, neutron-neutron, dual-detector density with caliper, magnetic susceptibility, single-point resistance, self potential, resistivity (normal and Wenner configurations), induced polarization, temperature, sonic delta-t, and sonic amplitude. The computer programs are designed to make basic corrections for depth displacements, tool response characteristics, hole diameter, and borehole fluid effects (when applicable). Corrected well-log measurements are output to magnetic tape or plotter with measurement units transformed to petrophysical and chemical units of interest, such as grade of uranium mineralization in percent eU3O8, neutron porosity index in percent, and sonic velocity in kilometers per second.

Circular↗

USGS2005

Petroleum systems and geologic assessment of oil and gas in the Southwestern Wyoming Province: Wyoming, Colorado and Utah

The U.S. Geological Survey (USGS) completed an assessment of the undiscovered oil and gas potential of the Southwestern Wyoming Province of southwestern Wyoming, northwestern Colorado, and northeastern Utah (fig. 1). The USGS Southwestern Wyoming Province for this assessment included the Green River Basin, Moxa arch, Hoback Basin, Sandy Bend arch, Rock Springs uplift, Great Divide Basin, Wamsutter arch, Washakie Basin, Cherokee ridge, and the Sand Wash Basin. The assessment of the Southwestern Wyoming Province is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation, and migration), reservoir rocks (sequence stratigraphy, petrophysical properties), and hydrocarbon traps (trap types, formation, and timing). Using this geologic framework, the USGS defined 9 total petroleum systems (TPS) and 23 assessment units (AU) within these TPSs, and quantitatively estimated the undiscovered oil and gas resources within 21 of the 23 AUs.

Colorado, Utah, Wyoming↗

USGS2006

Petroleum systems and geologic assessment of undiscovered oil and gas, Cotton Valley Group and Travis Peak-Hosston Formations, East Texas Basin and Louisiana-Mississippi Salt Basins Provinces of the Northern Gulf Coast Region

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The USGS recently completed an assessment of undiscovered oil and gas potential of the Cotton Valley Group and Travis Peak and Hosston Formations in the East Texas Basin and Louisiana-Mississippi Salt Basins Provinces in the Gulf Coast Region (USGS Provinces 5048 and 5049). The Cotton Valley Group and Travis Peak and Hosston Formations are important because of their potential for natural gas resources. This assessment is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). The USGS used this geologic framework to define one total petroleum system and eight assessment units. Seven assessment units were quantitatively assessed for undiscovered oil and gas resources.

Alabama, Arkansas. Florida, Georgia, Louisiana, Mi↗

USGS2014

Petroleum systems and assessment of undiscovered oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas: USGS Province 58

This publication provides research results and related data in support of the U.S. Geological Survey assessment of the undiscovered oil and gas resource potential of the Anadarko Basin Province of western Oklahoma and Kansas, northern Texas, and southeastern Colorado. This province area includes the Las Animas arch of southeastern Colorado, part of the Palo Duro Basin of Texas, and the Anadarko Basin. Results of the geologic analysis and resource assessment are based on the geologic elements of each defined total petroleum system, including hydrocarbon source rocks (source-rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphic and petrophysical properties), hydrocarbon traps (trapping mechanisms and timing), and seals. Using this geologic framework, the U.S. Geological Survey defined 2 total petroleum systems, the Woodford Composite total petroleum system and Pennsylvanian Composite total petroleum system and 12 included assessment units, and quantitatively estimated the undiscovered oil and gas resources within these conventional and continuous (unconventional) AUs. The 13 chapters included in U.S. Geological Survey Digital Data Series DDS–69–EE cover topics that range from the oil and gas resource assessment results (chapter 1 and 5–7), to geological, geochemical, and geophysical research across the province (chapters 3–11), tabular data and graphs in support of the assessment (chapter 12), and data releases of zmap-format grid files that were used to build petroleum system models and a standalone three-dimensional geologic model (chapter 13).

Colorado, Kansas, Oklahoma, Texas↗

USGS2006

Petroleum Systems and Geologic Assessment of Undiscovered Oil and Gas, Navarro and Taylor Groups, Western Gulf Province, Texas

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The USGS recently completed an assessment of undiscovered oil and gas potential of the Late Cretaceous Navarro and Taylor Groups in the Western Gulf Province in Texas (USGS Province 5047). The Navarro and Taylor Groups have moderate potential for undiscovered oil resources and good potential for undiscovered gas resources. This assessment is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). The USGS used this geologic framework to define one total petroleum system and five assessment units. Five assessment units were quantitatively assessed for undiscovered oil and gas resources.

Data Series↗

USGS2006

Chapter 1: Executive Summary - 2003 Assessment of Undiscovered Oil and Gas Resources in the Upper Cretaceous Navarro and Taylor Groups, Western Gulf Province, Gulf Coast Region, Texas

The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered oil and gas potential of the Upper Cretaceous Navarro and Taylor Groups in the Western Gulf Province of the Gulf Coast region (fig. 1) as part of a national oil and gas assessment effort (USGS Navarro and Taylor Groups Assessment Team, 2004). The assessment of the petroleum potential of the Navarro and Taylor Groups was based on the general geologic elements used to define a total petroleum system (TPS), including hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined five assessment units (AU) in the Navarro and Taylor Groups as parts of a single TPS, the Smackover-Austin-Eagle Ford Composite TPS: Travis Volcanic Mounds Oil AU, Uvalde Volcanic Mounds Gas and Oil AU, Navarro-Taylor Updip Oil and Gas AU, Navarro-Taylor Downdip Gas and Oil AU, and Navarro-Taylor Slope-Basin Gas AU (table 1).

Data Series↗

USGS2007

Geologic Assessment of Undiscovered Oil and Gas Resources of the Black Warrior Basin Province, Alabama and Mississippi

Introduction The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The USGS recently completed an assessment of undiscovered oil and gas potential of the Cambrian-Ordovician carbonate rocks, the Chattanooga and Floyd Shales, and the Pottsville Formation coals in the Black Warrior Basin Province in northeastern Mississippi and northwestern Alabama in the Gulf Coast Region. The Cambrian-Ordovician carbonate rocks, the Chattanooga and Floyd Shales, and the Pottsville Formation coals are important because of their potential for natural gas resources. This assessment is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). The USGS used this geologic framework to define two total petroleum systems and three assessment units. All three assessment units were quantitatively assessed for undiscovered oil and gas resources.

Data Series↗

USGS2007

Petroleum systems and geologic assessment of oil and gas in the Wind River Basin Province, Wyoming

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered oil and gas potential of the Wind River Basin Province which encompasses about 4.7 million acres in central Wyoming. The assessment is based on the geologic elements of each total petroleum system (TPS) defined in the province, including hydrocarbon source rocks (source-rock maturation, hydrocarbon generation, and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined three TPSs: (1) Phosphoria TPS, (2) Cretaceous-Tertiary TPS, and (3) Waltman TPS. Within these systems, 12 Assessment Units (AU) were defined and undiscovered oil and gas resources were quantitatively estimated within 10 of the 12 AUs.

Wyoming↗

USGS2007

Petroleum systems and geologic assessment of undiscovered oil and gas, Hanna, Laramie, and Shirley Basins Province, Wyoming

INTRODUCTION The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered oil and gas potential of the Hanna, Laramie, and Shirley Basins Province in Wyoming and northeastern Colorado. The assessment is based on the geologic elements of each total petroleum system (TPS) defined in the province, including hydrocarbon source rocks (source-rock maturation, hydrocarbon generation, and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined three TPSs and seven assessment units (AUs) within them; undiscovered resources for three of the seven AUs were quantitatively assessed.

Colorado, Wyoming↗