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24 records · Page 2Linked to original sources
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↗
USGS2000

Mapping the petroleum system - An investigative technique to explore the hydrocarbon fluid system

Creating a petroleum system map includes a series of logical steps that require specific information to explain the origin in time and space of discovered hydrocarbon occurrences. If used creatively, this map provides a basis on which to develop complementary plays and prospects. The logical steps include the characterization of a petroleum system (that is, to identify, map, and name the hydrocarbon fluid system) and the summary of these results on a folio sheet. A petroleum system map is based on the understanding that there are several levels of certainty from "guessing" to "knowing" that specific oil and gas accumulations emanated from a particular pod of active source rock. Levels of certainty start with the close geographic proximity of two or more accumulations, continues with the close stratigraphic proximity, followed by the similarities in bulk properties, and then detailed geochemical properties. The highest level of certainty includes the positive geochemical correlation of the hydrocarbon fluid in the accumulations to the extract of the active source rock. A petroleum system map is created when the following logic is implemented. Implementation starts when the oil and gas accumulations of a petroleum province are grouped stratigraphically and geographically. Bulk and geochemical properties are used to further refine the groups through the determination of genetically related oil and gas types. To this basic map, surface seeps and well shows are added. Similarly, the active source rock responsible for these hydrocarbon occurrences are mapped to further define the extent of the system. A folio sheet constructed for a hypothetical case study of the Deer-Boar(.) petroleum system illustrates this methodology.

AAPG Memoir↗
USGS2012

Determining the source and genetic fingerprint of natural gases using noble gas geochemistry: a northern Appalachian Basin case study

Silurian and Devonian natural gas reservoirs present within New York state represent an example of unconventional gas accumulations within the northern Appalachian Basin. These unconventional energy resources, previously thought to be noneconomically viable, have come into play following advances in drilling (i.e., horizontal drilling) and extraction (i.e., hydraulic fracturing) capabilities. Therefore, efforts to understand these and other domestic and global natural gas reserves have recently increased. The suspicion of fugitive mass migration issues within current Appalachian production fields has catalyzed the need to develop a greater understanding of the genetic grouping (source) and migrational history of natural gases in this area. We introduce new noble gas data in the context of published hydrocarbon carbon (C 1 ,C 2+ ) ( 13 C) data to explore the genesis of thermogenic gases in the Appalachian Basin. This study includes natural gases from two distinct genetic groups: group 1, Upper Devonian (Marcellus shale and Canadaway Group) gases generated in situ, characterized by early mature ( 13 C[ C1 C2 ][ 13 C 1 13 C 2 ]: –9 ), isotopically light methane, with low ( 4 He) (average, 1 10 3 cc/cc) elevated 4 He/ 40 Ar and 21 Ne / 40 Ar (where the asterisk denotes excess radiogenic or nucleogenic production beyond the atmospheric ratio), and a variable, atmospherically (air-saturated–water) derived noble gas component; and group 2, a migratory natural gas that emanated from Lower Ordovician source rocks (i.e., most likely, Middle Ordovician Trenton or Black River group) that is currently hosted primarily in Lower Silurian sands (i.e., Medina or Clinton group) characterized by isotopically heavy, mature methane ( 13 C [C1 – C2] [ 13 C 1 13 C 2 ]: 3 ), with high ( 4 He) (average, 1.85 10 3 cc/cc) 4 He/ 40 Ar and 21 Ne / 40 Ar near crustal production levels and elevated crustal noble gas content (enriched 4 He, 21 Ne , 40 Ar ). Because the release of each crustal noble gas (i.e., He, Ne, Ar) from mineral grains in the shale matrix is regulated by temperature, natural gases obtain and retain a record of the thermal conditions of the source rock. Therefore, noble gases constitute a valuable technique for distinguishing the genetic source and post-genetic processes of natural gases.

New York↗
USGS2022

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↗
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↗
USGS1977

Lisburne Group (Mississippian and Pennsylvanian), potential major hydrocarbon objective of Arctic Slope, Alaska

The Lisburne Group, a thick carbonate-rock unit of Mississippian and Pennsylvanian age, is one of the most widespread potential reservoir-rock units in northern Alaska. A comprehensive review of the Lisburne in the subsurface of the eastern Arctic Slope indicates attractive reservoir characteristics in a favorable source and migration setting where numerous trapping mechanisms appear to be available. Evaluation of this group as a potential exploration objective is particularly timely because of impending offshore sales in the Beaufort Sea and current exploration programs under way in the Prudhoe Bay area and the Naval Petroleum Reserve. Dolomite and sandstone have been identified as reservoir rocks. Oolitic grainstone is a common rock type, but observations indicate little reservoir potential owing to complete void filling by calcite cement. The most important reservoir rock as judged by thickness, areal extent, and predictability is microsucrosic (10 to 30μ) dolomite of intertidal to supratidal origin. It is present throughout the Lisburne and is most abundant near the middle of the sequence. Northward it decreases in thickness from 1,000 ft (300 m) to less than 100 ft (30 m). Porosity of the dolomite as determined in selected wells averages between 10 and 15% and attains a maximum of slightly more than 25%. Net thickness of reservoir rocks (i.e., rocks with greater than 5% porosity) ranges in these wells from 140 to 390 ft (40 to 120 m). Oil shows are common, and drill-stem tests have yielded as much as 1,600 bbl/day of oil and 22 MMcf/day of gas in the Lisburne pool of the Prudhoe Bay field and as much as 2,057 bbl/day of salt water outside the field area. The occurrence of dolomite over such a large area makes its presence in the offshore Beaufort Sea and adjacent Naval Petroleum Reserve 4 fairly certain. The presence of sandstone as thick as 140 ft (40 m) in the middle and upper part of the Lisburne in two coastal wells suggests that larger areas of sandstone may be found on the north in offshore areas. Shows of oil and gas and a saltwater flow of 1,470 bbl/day have been recorded from this sandstone facies. Shales of Permian and Cretaceous ages unconformably overlie the Lisburne, providing adequate sealing beds above potential reservoirs. Impermeable limestone (completely cemented grainstone) and thin beds of shale may serve as seals within the Lisburne, but the possibility of fractures in these units may negate their sealing capability. The most favorable source rock for Lisburne hydrocarbons appears to be Cretaceous shale that unconformably overlies the Lisburne east of Prudhoe Bay. This shale is reported to be a rich source rock and is the most likely source for the entire Prudhoe Bay field. A source within the Lisburne or within the underlying Kayak Shale is postulated for oil shows in the southernmost Lisburne wells. This postulated source may be in a more basinal facies of the Lisburne and may be similar to dark shale in the upper Lisburne in thrust slices to dark shale in the upper Lisburne in thrust slices in the Brooks Range. Coal in the underlying Endicott Group is a possible source for dry gas. At present, much of this coal probably is in a gas-generating regime downdip from the Prudhoe Bay field. Stratigraphic traps involving the Lisburne Group may have resulted from widespread Permian and Cretaceous unconformities. Structural traps related to normal faulting may be present along the trend of the Barrow arch, and faulted anticlines are numerous in the foothills of the Brooks Range. Combination traps are possible along the trend of the Barrow arch.

Alaska↗