Geology topics
Publications and source records attributed to Katherine J. Whidden.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean conventional resources of 96 trillion cubic feet of gas in the Northern Alaska Province.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 3 million barrels of oil and 343.5 trillion cubic feet of gas in reservoirs of the Bossier Formation within the onshore United States and State waters of the Gulf Coast region.
We document chemostratigraphy in an outcrop of late Albian to early Campanian (∼103–82 Ma) marine source rocks to better understand paleoenvironmental controls on trace element (TE) enrichment and organic matter accumulation in the distal Colville foreland basin of Arctic Alaska and how those drivers are linked to arc volcanism and successions of Cretaceous oceanographic and climatic biogeochemical events. This unique, 113-m-thick section of Cretaceous Hue Shale deposited during a series of previously undocumented Arctic Cretaceous oceanic anoxic events (Lease et al., 2024) is the only known exposure of thermally immature (0.48–0.52% R o , random vitrinite reflectance) Hue Shale in Arctic Alaska. Strata comprise mainly clay-rich mudstone with elevated total organic carbon (TOC) and hydrogen index values reaching 26.3 wt% (mean = 7.5 wt%) and 689 mg hydrocarbon (HC)/g TOC (mean = 385 mg HC/g TOC), respectively. Maceral composition consists predominantly of fluorescent amorphous organic matter, with abundant brightly fluorescent alginite, including Tasmanites , acritarchs, and Leiosphaeridia . Discrete layers of volcanic ash (preserved as bentonite) are present throughout the section and provide quantitative age control based on U–Pb dates. Chemostratigraphic trends are investigated to advance our understanding of local oceanographic conditions and controls on stratigraphic and temporal heterogeneity of Brookian source rocks. Concurrent sedimentary enrichment in Mo, U, V, Pb, and Cu across the Albian–Cenomanian boundary of the exposed basal gamma-ray zone, may reflect anoxic to euxinic benthic redox conditions favoring organic matter accumulation and preservation. Fluctuating degrees of anoxia-euxinia are inferred throughout the overlying Hue Shale succession, reflected by varying patterns of TE enrichment and TE–TOC covariation. Elevated C org /P molar ratios (>250) across most of the section, with several values exceeding 690, signify that enhanced biological productivity is sustained throughout deposition. Enhanced productivity, recorded by both C org /P and excess Ba, also parallels increases in source rock richness (elevated TOC and S 2 values) during the late Albian–early Cenomanian and late Cenomanian – Turonian. Enhanced productivity and variations in oceanic circulation/stratification likely both drove changes in benthic redox conditions that favored organic carbon accumulation and preservation. Increased continental arc volcanism (e.g., Okhotsk–Chukotka volcanic belt) and High Arctic Large Igneous Province magmatic eruptions throughout the Cretaceous, inferred to have influenced nutrient cycling and local aqueous nutrient availability, also have been invoked as potential drivers of organic carbon burial and source-rock development across the sedimentary sequence. Results presented here document the organic-rich and oil-prone source-rock quality of the Hue Shale in the distal part of the Colville foreland basin and bolster the potential for a Cretaceous petroleum system beneath the eastern North Slope.
The Shublik Formation (Middle to Upper Triassic) is a heterogeneous unit that is a major hydrocarbon source rock in northern Alaska and the largest known Triassic phosphate accumulation in the world. This formation, which occurs in the subsurface and crops out within the Arctic Alaska basin, was deposited on a gently sloping ramp along the northwestern Laurentian margin. In this study, we document spatial and temporal facies variations within the Shublik and the overlying Karen Creek Sandstone (Upper Triassic) through 19 outcrop localities in the northeastern Brooks Range. New organic and inorganic geochemical data from these localities support and extend our sedimentologic and petrographic findings. The petrographic data come from an analysis of more than 900 thin sections, whereas age constraints come mainly from species of the pelecypod genera Daonella , Halobia , Eomonotis , and Monotis . Thirteen sites make up a main outcrop belt within which facies of the Shublik are spatially consistent but show marked vertical changes. Six additional outcrops located south of the main belt contain more distal facies of the Shublik that accumulated farther from land. Exposures of the Shublik Formation in its main outcrop belt are divisible into five informal lithologic units, each of which formed during a distinct transgressive to regressive sequence. The basal unit of the Shublik (Anisian? to Ladinian; Middle Triassic) is quartz siltstone to very fine grained sandstone that is locally phosphatic. The three middle units (Ladinian to middle Norian; Middle to Upper Triassic) contain various proportions of siliciclastic, carbonate, phosphatic, and organic material. The uppermost unit (middle to upper Norian; Upper Triassic) is mainly shale and mudstone. Highly phosphatic strata (10–34 percent phosphorus pentoxide) are chiefly Ladinian and lower to middle Norian. Highly phosphatic Ladinian strata have been transported, are granular, and formed during transgression and early regression. In contrast, highly phosphatic Norian strata include event beds and hardgrounds, contain displaced and in situ phosphate peloids and nodules, and cap regressive parasequences. The total organic content reaches 4.97 weight percent in the main belt and is highest in muddy beds, which are found mainly in the lower parts of the three middle units. Distal sections of the Shublik are typically finer grained, more organic-rich (total organic content as high as 6.33 weight percent), and less fossiliferous than those in the main belt. Both temporal and spatial factors shaped facies in the Shublik Formation. Shublik strata accumulated at a time of reduced tectonic activity in Arctic Alaska, resulting in diminished siliciclastic input. Marine upwelling along the northwestern Laurentian margin facilitated the development of heterozoan carbonates, as well as local concentrations of phosphatic and organic matter. Large- and small-scale eustatic cycles also affected this margin and provided further controls on Shublik facies distribution.
More than 20,000 horizontal wells have been drilled and hydraulically fractured in the Eagle Ford Group since the discovery well in 2008, but a considerable amount of undiscovered petroleum remains. Recently, drilled wells have been hydraulically fractured with an average of nearly 13 million gallons of water and 16 million lb of sand, yielding a million or more gallons of produced water. To inform future petroleum development in the Eagle Ford, the U.S. Geological Survey (USGS) conducted a water and proppant assessment using a geology-based approach that builds on the 2018 USGS assessment of undiscovered technically recoverable petroleum. Using probabilistic input values and a Monte Carlo simulation, we determined that production of the remaining undiscovered technically recoverable oil and gas in the Eagle Ford Group would require approximately 687,565 Mgal (millions of gallons) of water and 839,702,000,000 lb of proppant (both are mean values of output distributions). This possible future petroleum production would also include 176,817 Mgal (mean value) of produced formation water. On average, oil wells require water volumes that are approximately twice the volume of oil that will be produced, and Eagle Ford gas wells require approximately 5.21 Mgal of water per billion cubic feet of gas (bcfg). Produced formation water volumes are approximately 60% of the produced oil volume and, for gas wells, will yield approximately 1 Mgal formation water per bcfg. Understanding the water and proppant requirements associated with petroleum exploration and the resulting volume of produced water can inform decisions regarding the future of Eagle Ford development.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 143 million barrels of oil and 1,084 billion cubic feet of natural gas in conventional accumulations for the Upper Jurassic Smackover Formation in the onshore U.S. Gulf Coast region.
The middle Cretaceous greenhouse period experienced profound environmental change including episodes of enhanced global burial of organic carbon marked by carbon isotopic excursions (CIEs). However, the role and response of polar regions like the newly formed, partially enclosed Arctic Ocean Basin during middle Cretaceous carbon burial remains enigmatic. We present the first Arctic deepwater CIE record that characterizes conditions offshore of the Alaska margin north of 75°N paleolatitude. Organic carbon isotopes (δ 13 C org ) and 103–82 Ma ash zircon U-Pb dates from the distal Hue Shale record multiple Albian–Campanian CIEs during slow ∼3–15 m/Myr sediment accumulation rates. Average total organic carbon (TOC) increased substantially during large 2–3 ‰ CIEs of the ∼101 Ma Albian-Cenomanian boundary event (from 7 to 18 % TOC) and ∼94 Ma Cenomanian-Turonian boundary event (5 to 10 % TOC). Turonian TOC remained elevated (8–13 %) during high global sea levels and temperatures of the Cretaceous Thermal Maximum, followed by an increase from 7 to 11 % TOC during the ∼90 Ma late Turonian event 1.5 ‰ CIE. Average TOC subsequently decreased in the Coniacian–Campanian, but relative maxima occurred during subtle 0.5–1 ‰ CIEs interpreted as the ∼87 Ma late Coniacian event (increase from 4 to 7 % TOC), ∼85 Ma Horseshoe Bay event (3.5 to 4.5 % TOC), and ∼84 Ma Santonian-Campanian boundary event (3.5 to 5 % TOC). Increases in hydrogen index and productivity proxies (P, Ba, Nd) that accompanied each CIE episode with enhanced TOC suggest a strong link between marine productivity and organic carbon burial at short-term CIE timescales. However, long-term (>5–8 Myr) changes in trace metal redox (Mo, Fe, V) and salinity (B/Ga) proxies suggest shifts in prevailing environmental conditions at timescales longer than the CIEs. Late Albian–middle Turonian marine salinity occurred during euxinic (103–98 Ma) and suboxic (98–90 Ma) conditions with deposition interpreted to have occurred within and beneath an oxygen minimum zone, respectively. In contrast, late Turonian–early Campanian (90–82 Ma) freshening and restricted euxinic basin conditions may signal the start of widespread restriction known to characterize the Paleogene Arctic. Overall, these results highlight that middle Cretaceous Arctic deepwater remained a productive marine carbon sink coupled to the global carbon cycle despite evolving Arctic greenhouse conditions.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean continuous resources of 0.8 billion barrels of oil and 16 trillion cubic feet of gas in the Upper Jurassic Smackover Formation of the onshore U.S. Gulf Coast region.
The Shublik Formation (Middle and Upper Triassic) is a mixed siliciclastic-carbonate-phosphatic unit in northern Alaska. It generated oil found in Prudhoe Bay and other accumulations and is a prospective self-sourced resource play on Alaska’s North Slope. Its distal, deeper-water equivalent—the Otuk Formation—consists largely of radiolarian chert, mudstone, and limestone and contains potential gas accumulations in the Brooks Range foothills to the south. New petrographic, fossil, geochemical, spectral gamma-ray, and zircon U-Pb data yield insights into facies changes in these units, which were deposited across a shallowly dipping shelf margin in a high-latitude setting. Samples come from four localities along a transect that extends ~410 km from present-day northeast (proximal) to southwest (distal) in northwest Alaska. Proximal Shublik facies (Brontosaurus 1 well) contain abundant siliciclastic detritus and local phosphate. Shublik-Otuk transitional facies occur in the probable onshore extension of the Hanna Trough (Surprise Creek); new zircon U-Pb data indicate an early Norian age for a bentonite bed in this section. Distal Otuk facies (Red Dog district, Cape Lisburne) are fine grained, biosiliceous, and organic rich. New detrital zircon U-Pb data from a distinctive sandstone member in the Otuk Formation at Cape Lisburne reinforce previous interpretations of a provenance to the present-day northwest and indicate a protracted history of Triassic magmatism for this source area. Triassic facies patterns in northwestern Alaska were shaped by sea-level change, climate, and regional tectonism. Organic-rich facies developed best at times (Ladinian–middle Norian) and/or in settings (distal shelf, Hanna Trough) with minimal dilution of organic matter by other detritus.
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.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated a mean of 1,407 billion (1.4 trillion) cubic feet of gas in conventional accumulations in Upper Devonian to Lower Cretaceous strata of the western North Slope, Alaska.
The U.S. Geological Survey (USGS) assesses potential for undiscovered, technically recoverable oil and gas resources in priority geologic provinces and quantifies resource volume estimates within subdivisions called assessment units (AUs). AU boundaries are defined by USGS geologists using quantitative and qualitative geologic information. Variables contained in IHS Markit’s well and production databases can quantify and/or function as proxies for many of the qualitative, boundary-defining variables. This research explores a new approach to determine AU boundaries and the potential to automate their definition, using data analytics and machine learning algorithms on key, qualitative variables within the IHS Markit databases. Well and production data from the U.S. onshore Gulf Coast region for the Upper Cretaceous Eagle Ford Group and Austin Chalk are used in this analysis because each is relatively geologically uniform in Texas and both have recently been assessed by the USGS. The Eagle Ford is an example of an in situ continuous oil and gas accumulation, and the overlying Austin Chalk is an example of a combined conventional and continuous resource, sourced from the underlying Eagle Ford. Wellspecific values were extracted or calculated from data in IHS Markit’s well and production databases for depth to top and base of the formations, formation thickness, bottom-hole temperature, temperature gradient, temperature at base of formation, cumulative oil and gas production values, barrels of oil equivalent, oil and gas gravities, mud weights from initial well test, depth pressure ratio, and excess pressure. A raster for each variable was interpolated using the natural neighbor technique from the spatial analyst toolbox in ArcGIS. Rasters were then transformed using minimum-maximum scaling, which rescales the distribution to the range of 0–1. Clustering was completed using the iso cluster unsupervised classification tool on the normalized rasters. Raster cell groupings from two to ten were explored, with initial results demonstrating that four to six classes return the most differentiable groups, with depth to formation, oil gravity, pressure, and temperature variables containing the greatest between-group differences. Modeled clusters have spatial similarities to the geologically defined AUs, with indication that temperature and pressure are the most fundamental to AU definition. Input from geologists will remain crucial for further dividing clusters and defining final AUs, since AUs are defined by both qualitative and quantitative information; however, this research documents promising cluster modeling results for the automation of initial AU definitions.
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.
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.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 3.6 billion barrels of oil and 8.9 trillion cubic feet of natural gas (associated and nonassociated) in conventional accumulations in Mississippian through Paleogene strata in the central North Slope of Alaska.
Recent work on cores and outcrops of the Middle-Upper Triassic Shublik Formation has facilitated surface to subsurface correlation of depositional sequences across the Alaska North Slope. Five transgressive-regressive depositional sequences have been defined within three large-scale stratigraphic units. Outcrop spectral gamma-ray (GR) profiles were used to correlate observed stacking patterns with nearby exploration wells, and GR logs from 161 exploration wells were used to correlate the three large-scale stratigraphic units across the North Slope and nearby offshore. Interpretations of depositional facies and sequence stratigraphy in cores from 26 wells were used to corroborate regional correlations. Isochore maps constructed for each of the three stratigraphic units illustrate the influence of accommodation on depositional patterns and suggest reactivation of several older tectonic elements during Shublik deposition. An isochore map of the richest, oil-prone interval of the Shublik Formation reveals a thick pod south of Harrison Bay, the eastern part of which lies beneath a recent giant Shublik-sourced oil discovery in the Cretaceous Nanushuk Formation. In addition, when integrated with thermal maturity, this isochore map may provide leads for areas that are optimal for unconventional resource exploration.
In 2019, total daily tight oil and gas production increased in the United States month over month, with annualized growth of 14% for oil and 12% for gas. Those gains leveled off in the first quarter of 2020 due to aggressive price competition and increases in international production. Then came the pandemic with a substantially larger dose of economic turmoil, driving down demand due in part to shelter in place orders and safety concerns around travel. Between March and May, tight oil and gas production dropped by nearly 2 million bpd and almost 5 Bcf/day before beginning to recover. Production has continued to increase for the most part through the second half of 2020, but drilling remains subdued throughout most of the U.S. and uncertainty around long term demand along with the current price environment and general state of the economy has contributed to layoffs throughout the industry. Some shale-gas production has declined recently, but a few areas have seen expansion due to construction of LNG facilities along the East Coast of the U.S. (e.g., the Haynesville Formation). Current U.S. shale-gas production is still higher now than in 2019, with daily production of almost 71 Bcf as of October 2020 driven in large part by increased production from the Marcellus Shale in the Appalachian Basin and shales within the Permian Basin. Shale liquids production is down by around a million bpd to approximately 7.1 million (September 2020; U.S. EIA) from pre-pandemic production levels at the end of 2019 and beginning of 2020. Tight oil production remains dominated by plays in the Permian Basin as well as the Bakken and Eagle Ford Formations. On the development and production front, new enhanced oil recovery approaches for tight shale reservoirs are being more widely implemented. Natural gas or CO2 injection is currently being utilized in the Bakken Formation, Eagle Ford Formation, Anadarko Basin, and the Permian Basin to optimize injection sequences and boost recovery. Refracturing of existing wells to reduce drilling costs, improve production, and prolong well productive life has also begun to occur more widely in developed plays. International interest in exploiting hydrocarbons from unconventional reservoirs continues to develop, with active exploration projects on most continents. Europe remains relatively underexplored as compared to North America, although a total of 141 exploration and appraisal wells with a possible shale-gas exploration component have been spudded, including horizontal legs from vertical wells. Shale exploration has made a breakthrough in China with shale gas output in 2019 of 10 billion cubic meters (35.3 Bcf), 60% of which was produced from Sinopec’s Fuling Shale Gas field. Lacustrine shale oil exploration has also been successful in the Sichuan and Ordos Basins in central China, Junggar and Tarim Basins in northwest China, and Songliao Basin in north China, and Bohai Bay Basins in northeast China as of 2018. South America’s potential as an unconventional shale gas and oil province is mainly in Argentina and Brazil, where the production from Neuquen Basin’s tight shale of the Vaca Muerta Formation has been steadily increasing since 2016, but only 4% of the shale resource has been developed thus far. According to International Energy Agency’s report in 2013, Brazil holds the 9th largest unconventional gas reserves. Brazil has shale oil and gas potential in the Parana, Solimoes and Amazon Basins and is actively producing from the oil shale unit of the Irati Formation. In 2019, the Brazil energy ministry launched REATE 2020 to boost onshore investments that include the expectation of drilling an experimental unconventional well in the northeast region. For this inaugural report, the new AAPG EMD Tight Oil and Gas Committee (TO&G; formerly the Shale Gas & Liquids and Tight Gas Sands committees) has developed new commodity report requirements for contributors. This includes shorter annual reports focused on new developments, play concepts, along with the typical updates on production and new drilling in the play areas they cover. We are also asking contributors to collect background geologic and production related information into a document that summarizes important features of the plays they cover that will be stored on the TO&G webpage along with our commodity reports. TO&G is currently working to expand the number of contributors to cover more play areas and replace committee and advisory board members that have recently stepped down. Changes to committee leadership occurred in October as recent chairs transition to EMD elected positions.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered, technically recoverable resources of 49 million barrels of oil and 18 billion cubic feet of gas in the onshore and State waters part of the South Florida basin.