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D.K. Higley

Publications and source records attributed to D.K. Higley.

At least 19 recordsLinked to original sources
USGS2019

Controls on petroleum resources for the Devonian Marcellus Shale in the Appalachian Basin Province, Kentucky, West Virginia, Ohio, Pennsylvania, and New York

Greater than 33 trillion cubic feet of gas, 68 million barrels of natural gas liquids (NGL), and 192 million barrels of water have been produced from the Middle Devonian Marcellus Shale of the Hamilton Group in the Appalachian Basin. These volumes are from more than 11,700 non-commingled wells. Areas of greatest production and future potential for gas and NGL from the Marcellus Shale are within and near the northeast-trending Rome trough in northern West Virginia and Pennsylvania. Southernmost New York, eastern Ohio, western Virginia, and Maryland also contain petroleum potential and (or) reserves. A confluence of factors enhances gas and NGL reserves and resources in the Marcellus Shale. These include (1) brittleness based on lithofacies composition; (2) thickness and distribution of brittle and organic-rich shale; (3) measured thermal maturity of 1% vitrinite reflectance and greater; (4) at least 2 weight percent total organic carbon; (5) dense and complex fracturing and faulting; (6) presence of evaporite beds in the underlying Silurian Salina Group; (7) potential overpressure; (8) current depths of 1,370 m (4,500 ft) and greater; and (9) predominately horizontal wells with laterals that are oriented to the northwest or southeast, or roughly perpendicular to the direction of maximum horizontal stress, and that cross major fault and fracture sets.

Kentucky, West Virginia, Ohio, Pennsylvania, New Y↗
USGS2019

Status of three-dimensional geological mapping and modeling activities in the U.S. Geological Survey

The U.S. Geological Survey (USGS), created in 1879, is the national geological survey for the United States and the sole science agency within its cabinet-level bureau, the Department of the Interior. The USGS has a broad mission, including: serving the Nation by providing reliable scientific information to describe and understand the Earth; minimize loss of life and property from natural disasters; manage water, biological, energy, and mineral resources; and enhance and protect quality of life. USGS scientific activities are organized around major topics, or Mission Areas, aligned with distinct science themes; three-dimensional (3-D) modelling typically supports research and project work within a specific Mission Area. The vastness, diversity, and complexity of the geological landscape of the United States has resulted in the creation of 3-D geological framework models that are local or regional in scale; a National-scale 3-D model is only beginning to evolve. This paper summarizes 3-D geological modeling at the USGS and does not discuss 3-D modeling that is conducted by other Federal agencies, state geological surveys, academia, or industry within the U.S. This paper updates and expands upon a similar status report of USGS 3-D modeling activities of Jacobsen et al. (2011).

Report↗
USGS2011

Assessment of undiscovered oil and gas resources of the Anadarko Basin Province of Oklahoma, Kansas, Texas, and Colorado, 2010

The U.S. Geological Survey, using a geoscience-based assessment methodology, estimated mean technically-recoverable undiscovered continuous and conventional resources that total 495 million barrels of oil, 27.5 trillion cubic feet of natural gas, and 410 million barrels of natural gas liquids in the Anadarko Basin Province; this assessment includes the Las Animas arch area of southeastern Colorado. The province is at a mature stage of exploration and development for conventional resources. Mean undiscovered continuous resources are estimated at 79 percent of oil, 90 percent of natural gas, and 81 percent of natural gas liquids in the province.

Fact Sheet↗
USGS2009

Timing and petroleum sources for the Lower Cretaceous Mannville Group oil sands of northern Alberta based on 4-D modeling

The Lower Cretaceous Mannville Group oil sands of northern Alberta have an estimated 270.3 billion m3 (BCM) (1700 billion bbl) of in-place heavy oil and tar. Our study area includes oil sand accumulations and downdip areas that partially extend into the deformation zone in western Alberta. The oil sands are composed of highly biodegraded oil and tar, collectively referred to as bitumen, whose source remains controversial. This is addressed in our study with a four-dimensional (4-D) petroleum system model. The modeled primary trap for generated and migrated oil is subtle structures. A probable seal for the oil sands was a gradual updip removal of the lighter hydrocarbon fractions as migrated oil was progressively biodegraded. This is hypothetical because the modeling software did not include seals resulting from the biodegradation of oil. Although the 4-D model shows that source rocks ranging from the Devonian-Mississippian Exshaw Formation to the Lower Cretaceous Mannville Group coals and Ostracode-zone-contributed oil to Mannville Group reservoirs, source rocks in the Jurassic Fernie Group (Gordondale Member and Poker Chip A shale) were the initial and major contributors. Kinetics associated with the type IIS kerogen in Fernie Group source rocks resulted in the early generation and expulsion of oil, as early as 85 Ma and prior to the generation from the type II kerogen of deeper and older source rocks. The modeled 50% peak transformation to oil was reached about 75 Ma for the Gordondale Member and Poker Chip A shale near the west margin of the study area, and prior to onset about 65 Ma from other source rocks. This early petroleum generation from the Fernie Group source rocks resulted in large volumes of generated oil, and prior to the Laramide uplift and onset of erosion (???58 Ma), which curtailed oil generation from all source rocks. Oil generation from all source rocks ended by 40 Ma. Although the modeled study area did not include possible western contributions of generated oil to the oil sands, the amount generated by the Jurassic source rocks within the study area was 475 BCM (2990 billion bbl). Copyright ?? 2009. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2005

1-D/3-D geologic model of the Western Canada Sedimentary Basin

The 3-D geologic model of the Western Canada Sedimentary Basin comprises 18 stacked intervals from the base of the Devonian Woodbend Group and age equivalent formations to ground surface; it includes an estimated thickness of eroded sediments based on 1-D burial history reconstructions for 33 wells across the study area. Each interval for the construction of the 3-D model was chosen on the basis of whether it is primarily composed of petroleum system elements of reservoir, hydrocarbon source, seal, overburden, or underburden strata, as well as the quality and areal distribution of well and other data. Preliminary results of the modeling support the following interpretations. Long-distance migration of hydrocarbons east of the Rocky Mountains is indicated by oil and gas accumulations in areas within which source rocks are thermally immature for oil and (or) gas. Petroleum systems in the basin are segmented by the northeast-trending Sweetgrass Arch; hydrocarbons west of the arch were from source rocks lying near or beneath the Rocky Mountains, whereas oil and gas east of the arch were sourced from the Williston Basin. Hydrocarbon generation and migration are primarily due to increased burial associated with the Laramide Orogeny. Hydrocarbon sources and migration were also influenced by the Lower Cretaceous sub-Mannville unconformity. In the Peace River Arch area of northern Alberta, Jurassic and older formations exhibit high-angle truncations against the unconformity. Potential Paleozoic though Mesozoic hydrocarbon source rocks are in contact with overlying Mannville Group reservoir facies. In contrast, in Saskatchewan and southern Alberta the contacts are parallel to sub-parallel, with the result that hydrocarbon source rocks are separated from the Mannville Group by seal-forming strata within the Jurassic. Vertical and lateral movement of hydrocarbons along the faults in the Rocky Mountains deformed belt probably also resulted in mixing of oil and gas from numerous source rocks in Alberta.

Mountain Geologist↗
USGS2002

Material-balance assessment of the New Albany-Chesterian petroleum system of the Illinois basin

The New Albany-Chesterian petroleum system of the Illinois basin is a well-constrained system from which petroleum charges and losses were quantified through a material-balance assessment. This petroleum system has nearly 90,000 wells penetrating the Chesterian section, a single New Albany Shale source rock accounting for more than 99% of the produced oil, well-established stratigraphic and structural frameworks, and accessible source rock samples at various maturity levels. A hydrogen index (HI) map based on Rock-Eval analyses of source rock samples of New Albany Shale defines the pod of active source rock and extent of oil generation. Based on a buoyancy-drive model, the system was divided into seven secondary-migration catchments. Each catchment contains a part of the active pod of source rock from which it derives a petroleum charge, and this charge is confined to carrier beds and reservoirs within these catchments as accountable petroleum, petroleum losses, or undiscovered petroleum. A well-constrained catchment with no apparent erosional or leakage losses is used to determine an actual petroleum charge from accountable petroleum and residual migration losses. This actual petroleum charge is used to calibrate the other catchments in which erosional petroleum losses have occurred. Petroleum charges determined by laboratory pyrolysis are exaggerated relative to the actual petroleum charge. Rock-Eval charges are exaggerated by a factor of 4-14, and hydrouspyrolysis charges are exaggerated by a factor of 1.7. The actual petroleum charge provides a more meaningful material balance and more realistic estimates of petroleum losses and remaining undiscovered petroleum. The total petroleum charge determined for the New Albany-Chesterian system is 78 billion bbl, of which 11.4 billion bbl occur as a accountable in place petroleum, 9 billion bbl occur as residual migration losses, and 57.6 billion bbl occur as erosional losses. Of the erosional losses, 40 billion bbl were lost from two catchments that have highly faulted and extensively eroded sections. Anomalies in the relationship between erosional losses and degree of erosion suggest there is potential for undiscovered petroleum in one of the catchments. These results demonstrate that a material-balance assessment of migration catchments provides a useful means to evaluate and rank areas within a petroleum system. The article provides methodologies for obtaining more realistic petroleum charges and losses that can be applied to less data-rich petroleum systems.

Illinois, Indiana, Kentucky↗
USGS2001

The Putumayo-Oriente-Maranon Province of Colombia, Ecuador, and Peru; Mesozoic-Cenozoic and Paleozoic petroleum systems

This report is an evaluation of oil and gas resources for petroleum systems of the Putumayo-Oriente-Maranon province of Columbia, Ecuador, and Peru. This assessment is a product of the World Energy Project of the U.S. Geological Survey, under the direction of Thomas Ahlbrandt. Described in this explanation of the petroleum geology of the Putumayo-Oriente-Maranon province are thermal maturation of hydrocarbon source rocks, primary reservoir formations, areas and volumes of oil and (or) gas production, and the history of exploration. Complete oil and gas resource assessment results are planned for a later publication, although some data and results are contained in this report.

Data Series↗
USGS1993

Coalbed methane potential of the Upper Cretaceous Mesaverde and Meeteetse formations, Wind River Reservation, Wyoming

The environments of deposition of the uppermost part of the Cody Shale and the Mesaverde and Meeteetse Formations of Late Cretaceous age were studied on outcrop in the Shotgun Butte area in the north-central part of the Wind River Reservation. A shoreface sandstone occurs in the lower part of the Mesaverde Formation at all localities studied, and is directly overlain by a coaly interval. Repetitive coarsening-upward cycles of mudstone, siltstone, and sandstone occur in the 200 ft interval of the upper part of the Cody Shale below the shoreface sandstone. These Cody sandstones are typically hummocky cross stratified with symmetrical ripples near the top, indicating that they are largely storm surge deposits that were later reworked. Channel-form sandstones from 10 to 20 ft thick, with abundant locally derived clayey clasts, occur in a 75 ft thick interval below the shoreface at one locality. These unusual sandstones are largely confined to a narrow area of the outcrop and grade laterally into more typical storm surge deposits. They may be unusually large storm surge channels created when high-energy flow conditions were localized to a limited area of the shelf. The Mesaverde Formation above the shoreface sandstone is divided into a middle member and the Teapot Sandstone Member. The lower part of the middle member is everywhere coaly. Erosional-based sandstones in this coaly interval are highly variable in thickness and architecture. Thin, single channel sandstone bodies were deposited by moderate to high sinuosity streams, and thick, multistory channel sandstone bodies were deposited by rapidly switching fluvial channel systems that remained relatively stationary for extended periods of time. The architecture of the fluvial channel sandstones in the overlying noncoaly interval appears to be highly variable as well, with complex multistory sandstones occurring at different stratigraphic levels at different localities. This distribution may be explained by long term stability of fluvial channel systems followed by major avulsion events. The Teapot Sandstone Member consists of fairly persistent to lenticular white multistory sandstone units that are as much as 85 ft thick and contain trough cross beds as much as 5 ft high. These sandstone units are interbedded with gray mudstones and carbonaceous shales. Paleosols are preserved at the tops of individual sandstones in the multistory units in some places. It is suggested that these sandstones were deposited largely by low-sinuosity to braided streams. The Meeteetse Formation consists of alternating coal and sandstone-rich intervals. The coal-rich intervals have relatively thin fluvial channel sandstones probably deposited by medium to high sinuosity streams whereas the sand-rich intervals have thick (to 105 ft) multistory fluvial channel sandstones possibly deposited by low-sinousity to braided streams.

Conference Paper↗
USGS1991

Porosity trends of the Lower Cretaceous J Sandstone, Denver Basin, Colorado

This study examines relationships between porosity and time-temperature history, and the influence of rock properties upon porosity, for the Lower Cretaceous J Sandstone in the Colorado portion of the Denver basin. The J Sandstone is classified as a quartzarenite to litharenite and was deposited in nearshore-marine, deltaic, and fluvial-estuarine (valley-fill) settings. Principal elements of its paragenetic sequence include quartz cementation and pressure solution, carbonate cementation and dissolution, dissolution of feldspar and rock fragments, and formation of authigenic clays. Porosity versus vitrinite reflectance (R 0 ) regression lines of the form Phi = A(R 0 )Beta (where B is a negative number) depicting the 10th, 25th, 50th, 75th, and 90th porosity percentiles of the J Sandstone were derived from 963 core-plug measurements representing 31 wells. The data span a thermal maturity range of R 0 = 0.41%-1.14%. Porosity distributions at different locations within the basin can be estimated as a function of thermal maturity on the basis of these regression lines. Porosity trends of the J Sandstone, if considered as a function of R 0 , are similar to those of broad, composite data sets representing sandstones in general. The petrographic factors that most affect J Sandstone porosity variability at a given level of thermal maturity are carbonate cementation and clay content. Carbonate cement, where present, reduces porosity. If previously more widespread, carbonate cement could also introduce porosity heterogeneity by temporarily preserving the pore network relative to uncemented intervals. Abundant detrital and authigenic clay reduces porosity by occupying pores. Low clay content indirectly reduces porosity because the inhibiting effects of clay upon quartz cementation and pressure solution are largely absent.

Journal of Sedimentary Petrology↗
USGS1987

Median-porosity contour maps of the J Sandstone, Dakota Group, in the Denver Basin, Colorado, Nebraska, and Wyoming

The Lower Cretaceous J sandstone of the Dakota Group is present in the Denver basin in eastern Colorado, southeastern Wyoming, and southwestern Nebraska. Deposited during a regression of the Cretaceous epicontinental sea, this informally named unit is composed primarily of sandstone and shale of deltaic and near shore-marine origin. The J sandstone can be divided into an upper transgressive sand, a middle marginal-marine and deltaic facies, and a lower prodelta sequence (Clark, 1978). The depth from the surface to the top of the J sandstone increases from about 4,000 ft on the gently-dipping eastern flank of the basin to more than 8,000 ft at the basin ax is near the steeply-dipping western flank. Porosity data compiled in this study were determined from J sandstone cores from 134 widely spaced boreholes. Porosity in areas of poor core coverage was determined from neutron density logs from an additional 20 boreholes ( corrected to core average grain density). Median, rather than average, porosity was used in order to minimize the statistical effect of anomalously high and low porosity values. Thirty-five oil companies and independent operators supplied core porosity data. Core porosities were determined by means of helium porosimetry, primarily by Core Laboratories of Denver, Colo.

Colorado, Nebraska, Wyoming↗
USGS1986

Median-permeability contour maps of the J sandstone, Dakota Group, in the Denver Basin, Colorado, Nebraska, and Wyoming

The Lower Cretaceous J sandstone of the Dakota Group (MacKenzie, 1965) is present in the Denver basin in eastern Colorado, southeastern Wyoming, and southwestern Nebraska. This informally named unit deposited during a regression of the Cretaceous epi continental sea and is composed primarily of sandstone and shale of deItaic and near-shore marine origin. The J sandstone can be divided into an upper transgressive sand, a middle marginal-marine and deltaic facies, and a lower prodelta sequence (Clark, 1978). The depth from the surface to the top of the J sandstone increases from about 4,000 ft on the gently-dipping eastern flank of the bass n to more than 8,000 ft near the steeply-dipping flank at the western boundary. Permeability values compiled in this J sandstone study were determined from cores from 134 widely scattered boreholes. Median permeabilities, rather than average permeabilities, were used in order to minimize the effect of anomalous samples. Thirty-five oil companies and independent operators supplied core data. Core Laboratories of Denver, Colorado analyzed the core, which was submitted over a period of 25 years.

Colorado, Nebraska, Wyoming↗