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Christopher J. Schenk

Publications and source records attributed to Christopher J. Schenk.

At least 235 records · Page 13Linked to original sources
USGS2012

Assessment of undiscovered oil and gas resources of the Ordovician Utica Shale of the Appalachian Basin Province, 2012

The U.S. Geological Survey assessed unconventional oil and gas resources of the Upper Ordovician Utica Shale and adjacent units in the Appalachian Basin Province. The assessment covers parts of Maryland, New York, Ohio, Pennsylvania, Virginia, and West Virginia. The geologic concept is that black shale of the Utica Shale and adjacent units generated hydrocarbons from Type II organic material in areas that are thermally mature for oil and gas. The source rocks generated petroleum that migrated into adjacent units, but also retained significant hydrocarbons within the matrix and adsorbed to organic matter of the shale. These are potentially technically recoverable resources that can be exploited by using horizontal drilling combined with hydraulic fracturing techniques.

Maryl;New York;Ohio;Pennsylvania;Virginia;West Vir↗
USGS2011

Geology and petroleum potential of the Timan-Pechora Basin Province, Russia

The Timan–Pechora Basin Province represents the northeastern-most cratonic block of Eastern European Russia. More than 16 billion barrels of oil (BBO) and 40 trillion cubic feet of gas (TCFG) have been discovered in this basin. Three geological assessment units (AU) were defined for assessing the potential for undiscovered oil and gas resources. The NW Izhma Depression AU encompasses all potential structures and reservoirs in the northwestern part of the Izhma–Pechora Depression, but this part of the basin contains little source and reservoir rocks and so was not assessed quantitatively. The Main Basin Platform AU includes all structures and reservoirs that developed in the central part of the basin where the tectonic evolution and development of petroleum systems were complex. The Foredeep Basins AU includes all potential reservoirs within the thick sedimentary section of the foredeep basins developed during the Permo-Triassic Uralian Orogeny. For the Timan–Pechora Basin Province, the estimated means of undiscovered resources are 3.3 BBO, 17 TCFG and 0.3 billion barrels of natural gas liquids (BBNGL). For the areas of the AUs north of the Arctic Circle in the Timan–Pechora Basin Province, the estimated means of undiscovered resources are 1.7 BBO, 9.0 TCFG and 0.2 BBNGL. The Pechora Sea was assessed with the South Barents Sea Province and is not included in this assessment.

Pechora Basin Province↗
USGS2011

Geology and petroleum potential of the West Greenland-East Canada Province

The US Geological Survey (USGS) assessed the potential for undiscovered oil and gas resources of the West Greenland–East Canada Province as part of the USGS Circum-Arctic Resource Appraisal programme. The province lies in the offshore area between western Greenland and eastern Canada and includes Baffin Bay, Davis Strait, Lancaster Sound and Nares Strait west of and including part of Kane Basin. A series of major tectonic events led to the formation of several distinct structural domains that are the geological basis for defining five assessment units (AU) in the province, all of which are within the Mesozoic–Cenozoic Composite Petroleum System. Potential petroleum source rocks include strata of Ordovician, Lower and Upper Cretaceous, and Palaeogene ages. The five AUs defined for this study – the Eurekan Structures AU, NW Greenland Rifted Margin AU, NE Canada Rifted Margin AU, Baffin Bay Basin AU and the Greater Ungava Fault Zone AU – encompass the entire province and were assessed for undiscovered technically recoverable resources. The mean volumes of undiscovered resources for the West Greenland–East Canada Province are 10.7×10 9 barrels of oil, 75×10 12 cubic feet of gas, and 1.7×10 9 barrels of natural gas liquids. For the part of the province that is north of the Arctic Circle, the estimated mean volumes of these undiscovered resources are 7.3×10 9 barrels of oil, 52×10 12 cubic feet of natural gas, and 1.1×10 9 barrels of natural gas liquids.

Geological Society Memoir↗
USGS2011

Assessment of NE Greenland: Prototype for development of Circum-ArcticResource Appraisal methodology

Geological features of NE Greenland suggest large petroleum potential, as well as high uncertainty and risk. The area was the prototype for development of methodology used in the US Geological Survey (USGS) Circum-Arctic Resource Appraisal (CARA), and was the first area evaluated. In collaboration with the Geological Survey of Denmark and Greenland (GEUS), eight ‘assessment units’ (AU) were defined, six of which were probabilistically assessed. The most prospective areas are offshore in the Danmarkshavn Basin. This study supersedes a previous USGS assessment, from which it differs in several important respects: oil estimates are reduced and natural gas estimates are increased to reflect revised understanding of offshore geology. Despite the reduced estimates, the CARA indicates that NE Greenland may be an important future petroleum province.

Geological Society Memoir↗
USGS2011

Oil and gas resource potential north of the Arctic Circle

The US Geological Survey recently assessed the potential for undiscovered conventional petroleum in the Arctic. Using a new map compilation of sedimentary elements, the area north of the Arctic Circle was subdivided into 70 assessment units, 48 of which were quantitatively assessed. The Circum-Arctic Resource Appraisal (CARA) was a geologically based, probabilistic study that relied mainly on burial history analysis and analogue modelling to estimate sizes and numbers of undiscovered oil and gas accumulations. The results of the CARA suggest the Arctic is gas-prone with an estimated 770–2990 trillion cubic feet of undiscovered conventional natural gas, most of which is in Russian territory. On an energy-equivalent basis, the quantity of natural gas is more than three times the quantity of oil and the largest undiscovered gas field is expected to be about 10 times the size of the largest undiscovered oil field. In addition to gas, the gas accumulations may contain an estimated 39 billion barrels of liquids. The South Kara Sea is the most prospective gas assessment unit, but giant gas fields containing more than 6 trillion cubic feet of recoverable gas are possible at a 50% chance in 10 assessment units. Sixty per cent of the estimated undiscovered oil resource is in just six assessment units, of which the Alaska Platform, with 31% of the resource, is the most prospective. Overall, the Arctic is estimated to contain between 44 and 157 billion barrels of recoverable oil. Billion barrel oil fields are possible at a 50% chance in seven assessment units. Undiscovered oil resources could be significant to the Arctic nations, but are probably not sufficient to shift the world oil balance away from the Middle East.

Geological Society Memoir↗
USGS2011

Geologic assessment of undiscovered hydrocarbon resources of the Western Oregon and Washington Province

The purpose of the U.S. Geological Survey (USGS) National Oil and Gas Assessment is to develop geology-based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States, focusing on the distribution, quantity, and availability of oil and natural gas resources. The USGS has completed an assessment of the undiscovered, technically recoverable oil and gas resources in western Oregon and Washington (USGS Western Oregon and Washington Province 5004). The province includes all of Oregon and Washington north of the Klamath Mountains and west of the crest of the Cascade Range, and extends offshore to the 3-mi limit of State waters on the west and to the International Boundary in the Straits of Juan de Fuca and Canada on the north. It measures about 450 mi north-south and 50 to 160 mi east-west, encompassing more than 51,000 mi2. The assessment of the Western Oregon and Washington Province is geology based and used the total petroleum system (TPS) concept. The geologic elements of a TPS include hydrocarbon source rocks (source rock maturation and hydrocarbon generation and migration), reservoir rocks (quality and distribution), and traps for hydrocarbon accumulation. Using these geologic criteria, two conventional and one unconventional (continuous) total petroleum systems were defined, with one assessment unit (AU) in each TPS: (1) the Cretaceous-Tertiary Composite TPS and the Western Oregon and Washington Conventional Gas AU, (2) the Tertiary Marine TPS and the Tertiary-Marine Gas AU, and (3) the Tertiary Coalbed Gas TPS and the Eocene Coalbed Gas AU, in which a cell-based methodology was used to estimate coalbed-gas resources.

Data Series↗
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↗
USGS2011

Assessment of undiscovered oil and gas resources of the Sud Province, north-central Africa

The Sud Province located in north-central Africa recently was assessed for undiscovered, technically recoverable oil, natural gas, and natural gas liquids resources as part of the U.S. Geological Survey's (USGS) World Oil and Gas Assessment. Using a geology-based assessment methodology, the USGS estimated mean volumes of 7.31 billion barrels of oil, 13.42 trillion cubic feet of natural gas, and 353 million barrels of natural gas liquids.

Fact Sheet↗
USGS2011

Assessment of undiscovered oil and gas resources of the West African Costal Province, West Africa

The West African Coastal Province along the west African coastline recently was assessed for undiscovered, technically recoverable oil, natural gas, and natural gas liquids resources as part of the U.S. Geological Survey's USGS World Oil and Gas Assessment. Using a geology-based assessment methodology, the USGS estimated mean volumes of 3.2 billion barrels of oil, 23.63 trillion cubic feet of natural gas, and 721 million barrels of natural gas liquids.

Fact Sheet↗
USGS2011

Assessment of undiscovered oil and gas resources of the Cook Inlet region, south-central Alaska, 2011

The U.S. Geological Survey (USGS) recently completed a new assessment of undiscovered, technically recoverable oil and gas resources in the Cook Inlet region of south-central Alaska. Using a geology-based assessment methodology, the USGS estimates that mean undiscovered volumes of nearly 600 million barrels of oil, about 19 trillion cubic feet of natural gas, and 46 million barrels of natural gas liquids remain to be found in this area.

Alaska↗
USGS2011

Assessment of undiscovered oil and gas resources of the Devonian Marcellus Shale of the Appalachian Basin Province

Using a geology-based assessment methodology, the U.S. Geological Survey (USGS) estimated a mean undiscovered natural gas resource of 84,198 billion cubic feet and a mean undiscovered natural gas liquids resource of 3,379 million barrels in the Devonian Marcellus Shale within the Appalachian Basin Province. All this resource occurs in continuous accumulations. In 2011, the USGS completed an assessment of the undiscovered oil and gas potential of the Devonian Marcellus Shale within the Appalachian Basin Province of the eastern United States. The Appalachian Basin Province includes parts of Alabama, Georgia, Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia. The assessment of the Marcellus Shale is based on the geologic elements of this formation's total petroleum system (TPS) as recognized in the characteristics of the TPS as a petroleum source rock (source rock richness, thermal maturation, petroleum generation, and migration) as well as a reservoir rock (stratigraphic position and content and petrophysical properties). Together, these components confirm the Marcellus Shale as a continuous petroleum accumulation. Using the geologic framework, the USGS defined one TPS and three assessment units (AUs) within this TPS and quantitatively estimated the undiscovered oil and gas resources within the three AUs. For the purposes of this assessment, the Marcellus Shale is considered to be that Middle Devonian interval that consists primarily of shale and lesser amounts of bentonite, limestone, and siltstone occurring between the underlying Middle Devonian Onondaga Limestone (or its stratigraphic equivalents, the Needmore Shale and Huntersville Chert) and the overlying Middle Devonian Mahantango Formation (or its stratigraphic equivalents, the upper Millboro Shale and middle Hamilton Group).

Alabama, Georgia, Kentucky, Maryland, New York, Oh↗
USGS2011

Assessment of undiscovered oil and gas resources of the North Sakhalin Basin Province, Russia, 2011

Using a geology-based assessment methodology, the U.S. Geological Survey estimated volumes of undiscovered, technically recoverable, conventional petroleum resources for the North Sakhalin Basin Province of Russia. The mean volumes were estimated at 5.3 billion barrels of crude oil, 43.8 trillion cubic feet of natural gas, and 0.8 billion barrels of natural gas liquids.

North Sakhalin Basin Province↗
USGS2011

Sedimentology and reservoir heterogeneity of a valley-fill deposit– A field guide to the Dakota Sandstone of the San Rafael Swell, Utah

Valley-fill deposits form a significant class of hydrocarbon reservoirs in many basins of the world. Maximizing recovery of fluids from these reservoirs requires an understanding of the scales of fluid-flow heterogeneity present within the valley-fill system. The Upper Cretaceous Dakota Sandstone in the San Rafael Swell, Utah contains well exposed, relatively accessible outcrops that allow a unique view of the external geometry and internal complexity of a set of rocks interpreted to be deposits of an incised valley fill. These units can be traced on outcrop for tens of miles, and individual sandstone bodies are exposed in three dimensions because of modern erosion in side canyons in a semiarid setting and by exhumation of the overlying, easily erodible Mancos Shale. The Dakota consists of two major units: (1) a lower amalgamated sandstone facies dominated by large-scale cross stratification with several individual sandstone bodies ranging in thickness from 8 to 28 feet, ranging in width from 115 to 150 feet, and having lengths as much as 5,000 feet, and (2) an upper facies composed of numerous mud-encased lenticular sandstones, dominated by ripple-scale lamination, in bedsets ranging in thickness from 5 to 12 feet. The lower facies is interpreted to be fluvial, probably of mainly braided stream origin that exhibits multiple incisions amalgamated into a complex sandstone body. The upper facies has lower energy, probably anastomosed channels encased within alluvial and coastal-plain floodplain sediments. The Dakota valley-fill complex has multiple scales of heterogeneity that could affect fluid flow in similar oil and gas subsurface reservoirs. The largest scale heterogeneity is at the formation level, where the valley-fill complex is sealed within overlying and underlying units. Within the valley-fill complex, there are heterogeneities between individual sandstone bodies, and at the smallest scale, internal heterogeneities within the bodies themselves. These different scales of fluid-flow compartmentalization present a challenge to hydrocarbon exploration targeting paleovalley deposits, and producing fields containing these types of reservoirs may have significant bypassed pay, especially where well spacing is large.

Utah↗
USGS2011

New U.S. Geological Survey method for the assessment of reserve growth

Reserve growth is defined as the estimated increases in quantities of crude oil, natural gas, and natural gas liquids that have the potential to be added to remaining reserves in discovered accumulations through extension, revision, improved recovery efficiency, and additions of new pools or reservoirs. A new U.S. Geological Survey method was developed to assess the reserve-growth potential of technically recoverable crude oil and natural gas to be added to reserves under proven technology currently in practice within the trend or play, or which reasonably can be extrapolated from geologically similar trends or plays. This method currently is in use to assess potential additions to reserves in discovered fields of the United States. The new approach involves (1) individual analysis of selected large accumulations that contribute most to reserve growth, and (2) conventional statistical modeling of reserve growth in remaining accumulations. This report will focus on the individual accumulation analysis. In the past, the U.S. Geological Survey estimated reserve growth by statistical methods using historical recoverable-quantity data. Those statistical methods were based on growth rates averaged by the number of years since accumulation discovery. Accumulations in mature petroleum provinces with volumetrically significant reserve growth, however, bias statistical models of the data; therefore, accumulations with significant reserve growth are best analyzed separately from those with less significant reserve growth. Large (greater than 500 million barrels) and older (with respect to year of discovery) oil accumulations increase in size at greater rates late in their development history in contrast to more recently discovered accumulations that achieve most growth early in their development history. Such differences greatly affect the statistical methods commonly used to forecast reserve growth. The individual accumulation-analysis method involves estimating the in-place petroleum quantity and its uncertainty, as well as the estimated (forecasted) recoverability and its respective uncertainty. These variables are assigned probabilistic distributions and are combined statistically to provide probabilistic estimates of ultimate recoverable quantities. Cumulative production and remaining reserves are then subtracted from the estimated ultimate recoverable quantities to provide potential reserve growth. In practice, results of the two methods are aggregated to various scales, the highest of which includes an entire country or the world total. The aggregated results are reported along with the statistically appropriate uncertainties.

Scientific Investigations Report↗