Search USGSSearch

USGS · 70200841

A revised Triassic stratigraphic framework for the Arctic Alaska Basin

Abstract

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.

Explore related subjects

90° N90° S · 180° W ← longitude → 180° E
Source-reported bounding extent: 65.58572002329473° to 71.49703690095419° latitude; -168.48632812499997° to -135.615234375° longitude. This indicates report coverage, not an exact sampling location. View area on OpenStreetMap.

Keep this discovery

Explore connections, maps & timelines

BibTeXRIS

Katherine J. Whidden, Julie A. Dumoulin, William A. Rouse. 2018. A revised Triassic stratigraphic framework for the Arctic Alaska Basin. https://doi.org/10.1306/0726171616517250

Cite the original work for its findings. Save a collection to share your selection of sources.

KEEP EXPLORING

Related USGS reports

Compression behavior of hydrate-bearing sediments

This work experimentally explores porosity, compressibility, and the ratio of horizontal to vertical effective stress ( K 0 ) in hydrate-bearing sandy silts from Green Canyon Block 955 in the deep-water Gulf of Mexico. The samples have an in situ porosity of 0.38 to 0.40 and a hydrate saturation of more than 80%. The hydrate-bearing sediments are stiffer than the equivalent hydrate-free sediments; the K 0 stress ratio is greater for hydrate-bearing sediments relative to the equivalent hydrate-free sediments. The porosity decreases by 0.01 to 0.02 when the hydrate is dissociated at the in situ effective stress. We interpret that the hydrate in the sediment pores is a viscoelastic material that behaves like a fluid over experimental time scales, yet it cannot escape the sediment skeleton. During compression, the hydrate bears a significant fraction of the applied vertical load and transfers this load laterally, resulting in the apparent increased stiffness and a larger apparent K 0 stress ratio. When dissociation occurs, the load carried by the hydrate is transferred to the sediment skeleton, resulting in further compaction and a decrease in the lateral stress. The viewpoint that the hydrate is a trapped viscous phase provides a mechanism for how stiffness and stress ratio ( K 0 ) are greater when hydrate is present in the porous media. This study provides insight into the initial stress state of hydrate-bearing reservoirs and the geomechanical evolution of these reservoirs during production.

Louisiana

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

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