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At least 37 records · Page 2Linked to original sources
USGS2018

A revised Triassic stratigraphic framework for the Arctic Alaska Basin

The Triassic Shublik Formation and the Triassic–Jurassic Otuk Formation are partially age-equivalent lithostratigraphic units that were deposited in the Arctic Alaska Basin (AAB). The Shublik Formation represents proximal deposition within the basin, with episodic siliciclastic input, whereas the Otuk Formation was deposited in the distal part of the basin, with significant intervals of mudstone and chert. Both the Shublik and Otuk Formations have significant intervals of organic-rich mudstone, and the Shublik is a major source rock for northern Alaska hydrocarbon accumulations such as Prudhoe Bay. The revised stratigraphic framework presented herein, based on the integration of lithostratigraphy and biostratigraphy, correlates intervals within these two formations, as well as the Ivishak Formation and the Karen Creek and Sag River Sandstones (which underlie and overlie the Shublik). This stratigraphic framework provides a basis for comparison of proximal and distal parts of the AAB through the Triassic, thus allowing for a more robust understanding of the spatial and temporal variability of lithology and organic richness within this basin. Five transgressive–regressive sequences are defined in the Shublik, based on lithostratigraphy and better age constraints provided by the revised stratigraphic framework. These sequences are age-correlative and recognized in other Arctic basins, implying that they have regional, and perhaps global, significance.

Alaska↗
USGS2022

State of stress in areas of active unconventional oil and gas development in North America

In this paper, we present comprehensive data on stress orientation and relative magnitude in areas throughout North America where unconventional oil and gas are currently being developed. We find excellent agreement between maximum horizontal principal stress (S Hmax ) orientations over a wide range of depths, using multiple methods. In all basins studied, we observed coherent stress fields that in some cases vary systematically from one part of a basin to another. In the Appalachian Basin in the eastern United States, S Hmax is oriented northeast–southwest to east-northeast–west-southwest and the style of faulting is compressive, transitioning from reverse faulting in eastern Pennsylvania and New York to principally strike-slip faulting in western Pennsylvania, Ohio, and West Virginia. In the midcontinent, central Oklahoma is characterized by an approximately east–west S Hmax direction and strike-slip faulting. The Fort Worth Basin in northeastern Texas is characterized by normal–strike-slip faulting and a north-northeast–south-southwest S Hmax direction. In the Midland subbasin of western Texas, S Hmax is consistently approximately east–west and normal–strike-slip faulting is observed. Farther west, the Delaware subbasin of western Texas and southeastern New Mexico is characterized by normal faulting and S Hmax rotates ∼150° clockwise from north to south. Marked changes in S Hmax direction also occur across the Raton Basin of southern Colorado and northern New Mexico, the Denver-Julesburg Basin in northern Colorado, and the Uinta Basin in northeastern Utah, likely associated with their location near the margins of extensional provinces. The new data sets we present help improve operational efficiency by constraining absolute stress magnitudes and the ideal azimuth to drill horizontal wells (i.e., perpendicular to the local S Hmax orientation) and make it possible to predict which fractures and faults are likely to be activated during hydraulic stimulation.

AAPG Bulletin↗
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↗
USGS2014

U.S. Geological Survey 2013 assessment of undiscovered resources in the Bakken and Three Forks Formations of the U.S. Williston Basin Province

The Upper Devonian Three Forks and Upper Devonian to Lower Mississippian Bakken Formations comprise a major United States continuous oil resource. Current exploitation of oil is from horizontal drilling and hydraulic fracturing of the Middle Member of the Bakken and upper Three Forks, with ongoing exploration of the lower Three Forks, and the Upper, Lower, and Pronghorn Members of the Bakken Formation. In 2008, the U.S. Geological Survey (USGS) estimated a mean of 3.65 billion bbl of undiscovered, technically recoverable oil resource within the Bakken Formation. The USGS recently reassessed the Bakken Formation, which included an assessment of the underlying Three Forks Formation. The Pronghorn Member of the Bakken Formation, where present, was included as part of the Three Forks assessment due to probable fluid communication between reservoirs. For the Bakken Formation, five continuous and one conventional assessment units (AUs) were defined. These AUs are modified from the 2008 AU boundaries to incorporate expanded geologic and production information. The Three Forks Formation was defined with one continuous and one conventional AU. Within the continuous AUs, optimal regions of hydrocarbon recovery, or “sweet spots,” were delineated and estimated ultimate recoveries were calculated for each continuous AU. Resulting undiscovered, technically recoverable resource estimates were 3.65 billion bbl for the five Bakken continuous oil AUs and 3.73 billion bbl for the Three Forks Continuous Oil AU, generating a total mean resource estimate of 7.38 billion bbl. The two conventional AUs are hypothetical and represent a negligible component of the total estimated resource (8 million barrels of oil).

AAPG Bulletin↗
USGS2022

Thermodynamic insights into the production of methane hydrate reservoirs from depressurization of pressure cores

We present results of slow (multiple day) depressurization experiments of pressure cores recovered from Green Canyon Block 955 in the northern Gulf of Mexico during The University of Texas at Austin Hydrate Pressure Coring Expedition (UT-GOM2-1). These stepwise depressurization experiments monitored the pressure and temperature within the core storage chamber during each pressure step, or “shut-in” period to better understand dissociation behavior and to provide insight on the thermodynamic state of gas hydrate reservoirs during production. The pressure rebound that occurs in response to a depressurization step occurs more slowly during later dissociation steps, likely reflecting a slower heat transfer rate, decreasing salinity gradient, and increased compressibility of the pore and surrounding fluids with progressive dissociation. We demonstrate that displacement of water by gas within the core storage chamber during successive dissociations both insulates the core and increases the compressibility of the pore and chamber fluid. The increased compressibility requires that a larger hydrate volume dissociates per unit of pressure recovery. Pressures observed during progressive dissociation steps are lower than predicted by the sample’s average salinity, with pressures approaching the freshwater phase boundary during frequent dissociation steps, suggesting that local pore-water freshening strongly influences dissociation behavior. To avoid underestimating the magnitude of pressure drawdown required to sustain dissociation in the reservoir, we suggest that hydrate production models use the freshwater phase boundary rather than a phase boundary determined from bulk salinity.

Green Canyon Block 955 (GC 955) study area, northe↗
USGS2014

Compositional controls on early diagenetic pathways in fine-grained sedimentary rocks: Implications for predicting unconventional reservoir attributes of mudstones

Diagenesis significantly impacts mudstone lithofacies. Processes operating to control diagenetic pathways in mudstones are poorly known compared to analogous processes occurring in other sedimentary rocks. Selected organic-carbon-rich mudstones, from the Kimmeridge Clay and Monterey Formations, have been investigated to determine how varying starting compositions influence diagenesis. The sampled Kimmeridge Clay Formation mudstones are organized into thin homogenous beds, composed mainly of siliciclastic detritus, with some constituents derived from water-column production (e.g., coccoliths, S-depleted type-II kerogen, as much as 52.6% total organic carbon [TOC]) and others from diagenesis (e.g., pyrite, carbonate, and kaolinite). The sampled Monterey Formation mudstones are organized into thin beds that exhibit pelleted wavy lamination, and are predominantly composed of production-derived components including diatoms, coccoliths, and foraminifera, in addition to type-IIS kerogen (as much as 16.5% TOC), and apatite and silica cements. During early burial of the studied Kimmeridge Clay Formation mudstones, the availability of detrital Fe(III) and reactive clay minerals caused carbonate- and silicate-buffering reactions to operate effectively and the pore waters to be Fe(II) rich. These conditions led to pyrite, iron-poor carbonates, and kaolinite cements precipitating, preserved organic carbon being S-depleted, and sweet hydrocarbons being generated. In contrast, during the diagenesis of the sampled Monterey Formation mudstones, sulfide oxidation, coupled with opal dissolution and the reduced availability of both Fe(III) and reactive siliciclastic detritus, meant that the pore waters were poorly buffered and locally acidic. These conditions resulted in local carbonate dissolution, apatite and silica cements precipitation, natural kerogen sulfurization, and sour hydrocarbons generation. Differences in mud composition at deposition significantly influence subsequent diagenesis. These differences impact their source rock attributes and mechanical properties.

AAPG Bulletin↗
USGS2018

Paleozoic shale gas resources in the Sichuan Basin, China

The Sichuan Basin, China, is commonly considered to contain the world’s most abundant shale gas resources. Although its Paleozoic marine shales share many basic characteristics with successful United States gas shales, numerous geologic uncertainties exist, and Sichuan Basin shale gas production is nascent. Gas retention was likely compromised by the age of the shale reservoirs, multiple uplifts and orogenies, and migration pathways along unconformities. High thermal maturities raise questions about gas storage potential in lower Paleozoic shales. Given these uncertainties, a new look at Sichuan Basin shale gas resources is advantageous. As part of a systematic effort to quantitatively assess continuous oil and gas resources in priority basins worldwide, the US Geological Survey (USGS) completed an assessment of Paleozoic shale gas in the Sichuan Basin in 2015. Three organic-rich marine Paleozoic shale intervals meet the USGS geologic criteria for quantitative assessment of shale gas resources: the lower Cambrian Qiongzhusi Formation, the uppermost Ordovician Wufeng through lowermost Silurian Longmaxi Formations (currently producing shale gas), and the upper Permian Longtan and Dalong Formations. This study defined geologically based assessment units and calculated probabilistic distributions of technically recoverable shale gas resources using the USGS well productivity–based method. For six assessment units evaluated in 2015, the USGS estimated a mean value of 23.9 tcf (677 billion cubic meters) of undiscovered, technically recoverable shale gas. This result is considerably lower than volumes calculated in previous shale gas assessments of the Sichuan Basin, highlighting a need for caution in this geologically challenging setting.

Sichuan Basin↗
USGS2018

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Solid bitumen is a common organic component of thermally mature shales and typically is identified by embayment against euhedral mineral terminations and by groundmass textures. However, because these textures are not always present, solid bitumen can be easily misidentified as vitrinite. Hydrous-pyrolysis experiments (72 hr, 300°C–360°C) on shale and coal samples show that solid-bitumen reflectance ( BR o ) in shales is less responsive to thermal stress than vitrinite reflectance ( R o ) in coal. This effect is most pronounced at lower experimental temperatures (300°C–320°C), whereas reflectance changes are more similar at higher temperatures (340°C–360°C). Neither a “vitrinite-like” maceral nor “suppressed vitrinite” was identified or measured in our sample set; instead, the experiments show that solid bitumen matures slower than vitrinite. The data may explain some reports of “ R o suppression,” particularly at lower thermal maturity ( R o ≤ 1.0%), as a simple case of solid bitumen being mistaken for vitrinite. Further, the experimental results confirm previous empirical observations that R o and BR o are more similar at higher maturities ( R o > 1.0%). It is suggested that R o suppression, commonly reported from upper Paleozoic marine shales of early to midoil window maturity, is a misnomer. This observation has important implications to petroleum exploration models and resource assessment, because it may change interpretations for the timing and spatial locations of kerogen maturation and petroleum generation.

AAPG Bulletin↗
USGS2021

Organic petrology and geochemistry of the Sunbury and Ohio Shales in eastern Kentucky and southeastern Ohio

As part of a study to determine the origin of oil and gas in the Berea Sandstone in northeastern Kentucky and southeastern Ohio, 158 samples of organic-rich shale from the Upper Devonian Olentangy and Ohio Shales and the Lower Mississippian Sunbury Shale, collectively referred to as the “black shale,” were collected and analyzed from 12 cores. The samples were analyzed for total organic carbon ( TOC ) content, organic petrography, and programmed pyrolysis. Previously acquired analytical data for 11 samples from 2 additional wells in eastern Kentucky were also used. Most of the samples were organic rich (>5 wt. % TOC ), high in sulfur (>2.0 wt. %), and dominated by liptinite macerals. The vitrinite reflectance ( VR o ) and equivalent vitrinite reflectance ( VR eq ) values, calculated from bitumen reflectance ( BR o ) measurements, were found to be in close agreement. The calculated reflectance values from programmed pyrolysis temperature at which the maximum release of hydrocarbons occurs ( T max ) showed better agreement with measured VR o after T max was corrected for excessive hydrogen index values for several samples. Thermal maturation parameters were found to increase in a northwest–southeast direction, paralleling an increase in black shale thickness and depth of burial. The thermal maturity proxies indicate the northwestern part of the study area to be more thermally mature than previously indicated. Geochemical and biomarker data from Berea oils indicate migration of oil from more thermally mature to less thermally mature areas. As such, the occurrence of petroleum liquids in the Berea Sandstone cannot be predicted directly from conventional thermal maturity proxies ( T max , VR o , and BR o ) because these methods do not account for migrated petroleum.

Ohio, Kentucky↗
USGS2016

Cretaceous–Cenozoic burial and exhumation history of the Chukchi shelf, offshore Arctic Alaska

Apatite fission track (AFT) and vitrinite reflectance data from five exploration wells and three seafloor cores illuminate the thermal history of the underexplored United States Chukchi shelf. On the northeastern shelf, Triassic strata in the Chevron 1 Diamond well record apatite annealing followed by cooling, possibly during the Triassic to Middle Jurassic, which is a thermal history likely related to Canada Basin rifting. Jurassic strata exhumed in the hanging wall of the frontal Herald Arch thrust fault record a history of probable Late Jurassic to Early Cretaceous structural burial in the Chukotka fold and thrust belt, followed by rapid exhumation to near-surface temperatures at 104 ± 30 Ma. This history of contractional tectonism is in good agreement with inherited fission track ages in low-thermal-maturity, Cretaceous–Cenozoic strata in the Chukchi foreland, providing complementary evidence for the timing of exhumation and suggesting a source-to-sink relationship. In the central Chukchi foreland, inverse modeling of reset AFT samples from the Shell 1 Klondike and Shell 1 Crackerjack wells reveals several tens of degrees of cooling from maximum paleo-temperatures, with maximum heating permissible at any time from about 100 to 50 Ma, and cooling persisting to as recent as 30 Ma. Similar histories are compatible with partially reset AFT samples from other Chukchi wells (Shell 1 Popcorn, Shell 1 Burger, and Chevron 1 Diamond) and are probable in light of regional geologic evidence. Given geologic context provided by regional seismic reflection data, we interpret these inverse models to reveal a Late Cretaceous episode of cyclical burial and erosion across the central Chukchi shelf, possibly partially overprinted by Cenozoic cooling related to decreasing surface temperatures. Regionally, we interpret this kinematic history to be reflective of moderate, transpressional deformation of the Chukchi shelf during the final phases of contractional tectonism in the Chukotkan orogen (lasting until ∼70 Ma), followed by renewed subsidence of the Chukchi shelf in the latest Cretaceous and Cenozoic. This history maintained modest thermal maturities at the base of the Brookian sequence across the Chukchi shelf, because large sediment volumes bypassed to adjacent depocenters. Therefore, the Chukchi shelf appears to be an area with the potential for widespread preservation of petroleum systems in the oil window.

AAPG Bulletin↗
USGS1990

Hydrothermally derived petroleum: examples from Guaymas Basin, Gulf of California, and Escanaba Trough, northeast Pacific Ocean

In the Guaymas Basin, a spreading axis in the Gulf of California, petroleum having a wide range of compositions forms by hydrothermal alteration of organic matter in Quaternary sediment composed mainly of marine diatomaceous ooze and muddy turbidites. In Escanaba Trough, at the southern end of the Gorda Ridge spreading axis offshore northern California, petroleum is formed by hydrothermal processes acting on mainly terrigenous organic material in Quaternary turbiditic river-derived sediment. Comparisons of the distributions of hydrocarbons - n-alkanes, isoprenoids, terpanes, steranes, and aromatics - show that chemical differences among four petroleum samples are such that two samples from Guaymas Basin can be distinguished from two samples from Escanaba Trough. Distinguishing characteristics resulting from differences in sources include n-alkane distributions and certain sterane ratios; distinguishing characteristics resulting from differences in thermal histories of the organic matter include hopane and sterane epimer ratios and various distributions of polycyclic aromatic hydrocarbons. These oils differ from conventionally derived petroleum in that they are admixtures of products generated over a wide range of thermal regimes, and their generation, expulsion, and migration occurred simultaneously over an instantaneous geological time period. The potential economic significance of hydrothermal derived petroleum is uncertain, but the fact that petroleum can form at active oceanic spreading axes adds a new facet to understanding the processes of petroleum generation, expulsion, and migration.

Escanaba Trough and Guaymas Basin in the system of↗
USGS2013

Controls on the deposition and preservation of the Cretaceous Mowry Shale and Frontier Formation and equivalents, Rocky Mountain region, Colorado, Utah, and Wyoming

Regional variations in thickness and facies of clastic sediments are controlled by geographic location within a foreland basin. Preservation of facies is dependent on the original accommodation space available during deposition and ultimately by tectonic modification of the foreland in its postthrusting stages. The preservation of facies within the foreland basin and during the modification stage affects the kinds of hydrocarbon reservoirs that are present. This is the case for the Cretaceous Mowry Shale and Frontier Formation and equivalent strata in the Rocky Mountain region of Colorado, Utah, and Wyoming. Biostratigraphically constrained isopach maps of three intervals within these formations provide a control on eustatic variations in sea level, which allow depositional patterns across dip and along strike to be interpreted in terms of relationship to thrust progression and depositional topography. The most highly subsiding parts of the Rocky Mountain foreland basin, near the fold and thrust belt to the west, typically contain a low number of coarse-grained sandstone channels but limited sandstone reservoirs. However, where subsidence is greater than sediment supply, the foredeep contains stacked deltaic sandstones, coal, and preserved transgressive marine shales in mainly conformable successions. The main exploration play in this area is currently coalbed gas, but the enhanced coal thickness combined with a Mowry marine shale source rock indicates that a low-permeability, basin-centered play may exist somewhere along strike in a deep part of the basin. In the slower subsiding parts of the foreland basin, marginal marine and fluvial sandstones are amalgamated and compartmentalized by unconformities, providing conditions for the development of stratigraphic and combination traps, especially in areas of repeated reactivation. Areas of medium accommodation in the most distal parts of the foreland contain isolated marginal marine shoreface and deltaic sandstones that were deposited at or near sea level lowstand and were reworked landward by ravinement and longshore currents by storms creating stratigraphic or combination traps enclosed with marine shale seals. Paleogeographic reconstructions are used to show exploration fairways of the different play types present in the Laramide-modified, Cretaceous foreland basin. Existing oil and gas fields from these plays show a relatively consistent volume of hydrocarbons, which results from the partitioning of facies within the different parts of the foreland basin.

Colorado;Utah;Wyoming↗
USGS2014

Effects of smectite on the oil-expulsion efficiency of the Kreyenhagen Shale, San Joaquin Basin, California, based on hydrous-pyrolysis experiments

The amount of oil that maturing source rocks expel is expressed as their expulsion efficiency, which is usually stated in milligrams of expelled oil per gram of original total organic carbon (TOC O ). Oil-expulsion efficiency can be determined by heating thermally immature source rocks in the presence of liquid water (i.e., hydrous pyrolysis) at temperatures between 350°C and 365°C for 72 hr. This pyrolysis method generates oil that is compositionally similar to natural crude oil and expels it by processes operative in the subsurface. Consequently, hydrous pyrolysis provides a means to determine oil-expulsion efficiencies and the rock properties that influence them. Smectite in source rocks has previously been considered to promote oil generation and expulsion and is the focus of this hydrous-pyrolysis study involving a representative sample of smectite-rich source rock from the Eocene Kreyenhagen Shale in the San Joaquin Basin of California. Smectite is the major clay mineral (31 wt. %) in this thermally immature sample, which contains 9.4 wt. % total organic carbon (TOC) comprised of type II kerogen. Compared to other immature source rocks that lack smectite as their major clay mineral, the expulsion efficiency of the Kreyenhagen Shale was significantly lower. The expulsion efficiency of the Kreyenhagen whole rock was reduced 88% compared to that of its isolated kerogen. This significant reduction is attributed to bitumen impregnating the smectite interlayers in addition to the rock matrix. Within the interlayers, much of the bitumen is converted to pyrobitumen through crosslinking instead of oil through thermal cracking. As a result, smectite does not promote oil generation but inhibits it. Bitumen impregnation of the rock matrix and smectite interlayers results in the rock pore system changing from water wet to bitumen wet. This change prevents potassium ion (K + ) transfer and dissolution and precipitation reactions needed for the conversion of smectite to illite. As a result, illitization only reaches 35% to 40% at 310°C for 72 hr and remains unchanged to 365°C for 72 hr. Bitumen generation before or during early illitization in these experiments emphasizes the importance of knowing when and to what degree illitization occurs in natural maturation of a smectite-rich source rock to determine its expulsion efficiency. Complete illitization prior to bitumen generation is common for Paleozoic source rocks (e.g., Woodford Shale and Retort Phosphatic Shale Member of the Phosphoria Formation), and expulsion efficiencies can be determined on immature samples by hydrous pyrolysis. Conversely, smectite is more common in Cenozoic source rocks like the Kreyenhagen Shale, and expulsion efficiencies determined by hydrous pyrolysis need to be made on samples that reflect the level of illitization at or near bitumen generation in the subsurface.

California↗
USGS2012

Geological and geochemical characterization of the Lower Cretaceous Pearsall Formation, Maverick Basin, south Texas: A future shale gas resource?

As part of an assessment of undiscovered hydrocarbon resources in the northern Gulf of Mexico onshore Mesozoic section, the U.S. Geological Survey (USGS) evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource. Wireline logs were used to determine the stratigraphic distribution of the Pearsall Formation and to select available core and cuttings samples for analytical investigation. Samples used for this study spanned updip to downdip environments in the Maverick Basin, including several from the current shale gas-producing area of the Pearsall Formation. The term shale does not adequately describe any of the Pearsall samples evaluated for this study, which included argillaceous lime wackestones from more proximal marine depositional environments in Maverick County and argillaceous lime mudstones from the distal Lower Cretaceous shelf edge in western Bee County. Most facies in the Pearsall Formation were deposited in oxygenated environments as evidenced by the presence of biota preserved as shell fragments and the near absence of sediment laminae, which is probably caused by bioturbation. Organic material is poorly preserved and primarily consists of type III kerogen (terrestrial) and type IV kerogen (inert solid bitumen), with a minor contribution from type II kerogen (marine) based on petrographic analysis and pyrolysis. Carbonate dominates the mineralogy followed by clays and quartz. The low abundance and broad size distribution of pyrite are consistent with the presence of oxic conditions during sediment deposition. The Pearsall Formation is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance values, R o = 1.2–2.2%) and contains moderate levels of total organic carbon (average 0.86 wt. %), which primarily resides in the inert solid bitumen. Solid bitumen is interpreted to result from in-situ thermal cracking of liquid hydrocarbon generated from original type II kerogen that was prevented from expulsion and migration by low permeability. The temperature of maximum pyrolysis output ( T max ) is a poor predictor of thermal maturity because the pyrolysis (S2) peaks from Rock-Eval analysis are ill defined. Vitrinite reflectance values are consistent with the dry gas window and are the preferred thermal maturity parameter. A Maverick Basin Pearsall shale gas assessment unit was defined using political and geologic boundaries to denote its spatial extent and was evaluated following established USGS hydrocarbon assessment methodology. The assessment estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 tcf of gas at the F95 and F5 fractile confidence levels, respectively. Significant engineering challenges will likely need to be met in determining the correct stimulation and completion combination for the successful future development of undiscovered natural gas resources in the Pearsall Formation.

AAPG Bulletin↗
USGS1979

Stratigraphy and depositional environments of Baltimore Canyon Trough

The Baltimore Canyon Trough, lying offshore from the United States Middle Atlantic States, contains a thickness of at least 14 km of marine and nonmarine sedimentary rocks. One deep offshore stratigraphic test (COST B-2 well), several wells on the coastal plain, 18 shallow core holes (Deep Sea Drilling Project, Atlantic Slope Project, and Atlantic Margin Coring Project) on the continental shelf and slope, and scattered oceanographic cores and dredgings provide rich foraminiferal assemblages from which the geologic age and depositional environments have been determined. The oldest sedimentary rocks penetrated are Upper Jurassic terrigenous sandstone and shale, which are interspersed with shallow-marine limestone. Lower Cretaceous rocks, where penetrated, are also chiefly terrigenous sandstone and shale, but Upper Cretaceous rocks are progressively more marine. Paleogene strata reflect even deeper marine conditions (bathyal carbonate deposits in the B-2 well). In the Neogene, terrigenous clastic deposits replaced the Paieogene carbonate sequences throughout the trough. Deposition began with thick (>800 m) deltaic beds in the Miocene and Pliocene and culminated in sandy and, in many places, nonfofesiHferous strata of the Pleistocene shelf. Surprisingly thick (>300 m) silty and sandy clay composes the Pleistocene section on the continental slope. These stratigraphic and paleoecologic relations are graphically illustrated in eight geologic cross sections parallel with and perpendicular to the axis of the trough.

Mid-Atlantic United States↗
USGS1980

Mesozoic and Cenozoic structural trends under southern Bering Sea shelf

Mesozoic rocks exposed near the tip of the Alaska Peninsula form an antiformal structure that flanks the southern side of Bristol Bay basin and that can be traced with geophysical data about 700 km offshore to the vicinity of the Pribilof Islands. Upper Jurassic sandstone and Upper Cretaceous mudstone dredged from the top and flanks of this structure near the islands confirm that Mesozoic rocks extend from the Alaska Peninsula to the Bering sea margin. The southern part of the Bering Sea Shelf is underlain by several large structural basins: St. George, Amak, and Bristol Bay basins. These filled basins encompass an offshore area of about 31,000 sq km; St. George basin contains more than 10 km of strata. Reflection profiles show that the surface of the offshore antiformal structures is an angular unconformity overlain by Cenozoic beds. This unconformity can be traced toward the axes of the adjacent subshelf basins where, as a disconformity, it parallels underlying and overlying strata. Dredge data suggest that the unconformity and disconformity may be as old as middle to Late Cretaceous. The downdip trace of the unconformity in Bristol Bay basin is underlain by reflectors paralleling the contact, a relation suggesting that the basin and perhaps other shelf basins may be underlain by ancient Mesozoic depocenters. The bulk of the thick sections in these basins is, however, thought to be mainly Cenozoic in age. Strata in the basins are cut by high-angle growth faults. The faults commonly offset the seafloor, which implies that basin subsidence and filling continue to the present. Shallow-water diatomaceous mudstone of Eocene and Oligocene age dredged from the continental slope near the Pribilof Islands indicates that collapse of the margin and outer shelf basins began by at least early Tertiary time. In Mesozoic time, the Bering margin between Siberia and the Alaska Peninsula (Beringian margin) may have been a zone of either oblique underthrusting or transform motion between the North American and Pacific lithosphere (Kula plate?). This motion may have rifted the edge of the North American plate, resulting in the formation of a series of elongate basins and ridges paralleling the plate edge. These hypothetical basins may have controlled the location and initial subsidence of Bristol Bay, Amak, and St. George basins. Formation of the Aleutian Island arc in late Mesozoic or earliest Tertiary time presumably terminated plate interaction along the Beringian margin. Sediment loading and subsequent subsidence of the remnant plate within the abyssal Bering Sea may have caused continuing collapse of the Beringian margin in latest Cretaceous and earliest Tertiary time.

AAPG Bulletin↗