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USGS2011

A first look at the petroleum geology of the Lomonosov Ridge microcontinent, Arctic Ocean

The Lomonosov microcontinent is an elongated continental fragment that transects the Arctic Ocean between North America and Siberia via the North Pole. Although it lies beneath polar pack ice, the geological framework of the microcontinent is inferred from sparse seismic reflection data, a few cores, potential field data and the geology of its conjugate margin in the Barents–Kara Shelf. Petroleum systems inferred to be potentially active are comparable to those sourced by condensed Triassic and Jurassic marine shale of the Barents Platform and by condensed Jurassic and (or) Cretaceous shale probably present in the adjacent Amerasia Basin. Cenozoic deposits are known to contain rich petroleum source rocks but are too thermally immature to have generated petroleum. For the 2008 USGS Circum Arctic Resource Appraisal (CARA), the microcontinent was divided into shelf and slope assessment units (AUs) at the tectonic hinge line along the Amerasia Basin margin. A low to moderate probability of accumulation in the slope AU yielded fully risked mean estimates of 123 MMBO oil and 740 BCF gas. For the shelf AU, no quantitative assessment was made because the probability of petroleum accumulations of the 50 MMBOE minimum size was estimated to be less than 10% owing to rift-related uplift, erosion and faulting.

Geological Society Memoir↗

USGS1979

Maps showing late Pleistocene and Holocene evolution of the South Texas continental shelf

Interpretation of acoustical profiles has provided insight into the late Quaternary geologic history of the Continental Shelf off South Texas. (See the geographic index map on sheet 1 for location of the area studied.) The profiles reveal the interplay of tectonism, sedimentation, and cyclic fluctuations of sea level in the building and geologic evolution of the continental terrace. The sequence of sediments studied extends to about 200 meters (m) beneath the sea-floor surface. Four seismic-stratigraphic units underlain by four prominent sound reflectors were identified and mapped. This geologic synthesis, for which the research was funded by the U.S. Bureau of Land Management (BLM), is but one aspect of a coordinated, multidisciplinary environmental study of the South Texas Outer Continental Shelf sponsored by BLM (Berryhill, 1976, 1977). The environmental studies are keyed to the leasing of Federal Outer Continental Shelf (OCS) lands for petroleum exploration and production. Their purpose is to provide the data development of petroleum resources on the OCS, as well as to provide the basis for predicting the impact of oil and gas exploration and production on the marine environment. Of primary concern is the recognition of geologic conditions that might be hazardous to structures placed on the sea floor. Geologic hazards relate directly to the potential for significant movement of the sea floor in the future. Judging sea-floor stability and recognizing geologic features that are potentially hazardous require an understanding of the recent geologic history of the area, which, in turn, entails determining the relative rates and interactions of sedimentation and tectonism through time. In addition to the primary objective, the synthesis provides knowledge about the magnitude and extent of sea-level fluctuations in the western Gulf of Mexico, and it provides a depositional facies model of possible use in appraising the resource potential of the more deeply buried sediments.

Texas↗

USGS2021

Geologic assessment of undiscovered oil and gas resources in the Cherokee Platform area of Kansas, Oklahoma, and Missouri

In 2015, the U.S. Geological Survey completed a geology-based assessment to estimate the volumes of undiscovered, technically recoverable petroleum resources in the Cherokee Platform Province area of southeastern Kansas, northeastern Oklahoma, and southwestern Missouri. The U.S. Geological Survey identified four stratigraphic intervals that contain petroleum source rocks: (1) thin shales in the Middle to Upper Ordovician Simpson Group, (2) shales within the Upper Devonian to Lower Mississippian Woodford Shale and stratigraphically equivalent Chattanooga Shale, (3) coals and coal-associated shales and mudstones in the Middle Pennsylvanian (Desmoinesian) Cherokee and Marmaton Groups, and (4) thin marine shales within the Marmaton Group and the Upper Pennsylvanian (Missourian) Kansas City and Lansing Groups. Based on the nature of the petroleum accumulations, the characterization of the compositions and thermal maturity of the organic matter in the rocks, and the compositions of the produced petroleum, the U.S. Geological Survey identified three total petroleum systems (TPS) containing four assessment units (AU): the Paleozoic Composite TPS with the Paleozoic Conventional Assessment Unit (AU), the Woodford/Chattanooga TPS with the Woodford Shale Oil AU and the Woodford Biogenic Gas AU, and the Desmoinesian Coal TPS with the Desmoinesian Coalbed Gas AU. Assessment unit summaries follow 1. Three source rock intervals have contributed geochemically distinct oils to reservoirs within the Paleozoic Conventional AU. These intervals are the Simpson Group; the Woodford and Chattanooga Shales; and the Marmaton, Kansas City, and Lansing Groups. The major petroleum source rocks are the Woodford and Chattanooga Shales. The Paleozoic Conventional AU includes reservoirs that range in age from the Upper Cambrian Arbuckle Group to the lower Permian Chase Group. Most oil production in the province has been from Pennsylvanian sandstone reservoirs. Estimated undiscovered petroleum resources for this AU are a mean of 3 million barrels of oil (MMBO), 140 billion cubic feet of gas (BCFG), and 4 million barrels of natural gas liquids (MMBNGL). 2. The Woodford Shale Oil AU contains undiscovered continuous petroleum resources within the Woodford Shale and Chattanooga Shale. The geologic model for the AU assumes that petroleum resources remain trapped within the shale following petroleum migration. For most of the AU, organic matter within the Woodford Shale and Chattanooga Shale is thermally mature with respect to petroleum generation as shown by vitrinite reflectance values between 0.6 and 1 percent. Petroleum has been produced from the Woodford Shale and Chattanooga Shale. Estimated undiscovered petroleum resources for this AU are means of 460 MMBO, 640 BCFG, and 7 MMBNGL. 3. The Woodford Shale Biogenic Gas AU contains undiscovered continuous petroleum resources in the east-central portion of the Cherokee Platform Province near the Ozark uplift where the Woodford Shale and Chattanooga Shale are at depths of 1,250 ft or shallower. At those depths, methanogenesis and(or) biodegradation of thermogenic natural gases can be found where the shale may be more fractured and more susceptible to groundwater penetrations. The mean assessed volume of undiscovered gas for this assessment unit is 416 BCFG and 1 MMBNGL. 4. The Desmoinesian Coalbed Gas AU contains undiscovered continuous petroleum resources within the Middle Pennsylvanian coals and coal-associated shales and mudstones. The boundaries for the Desmoinesian Coalbed Gas AU are, in part, defined by the extent, depth, and thickness of the coals. Within the Desmoinesian Coalbed Gas AU, a sweet spot area was delineated based on a 10 foot or greater net coal thickness. Gas analytical data show that natural gas produced from the coals has a mixed biogenic and thermogenic origin and that there is significant migration of natural gas into the coals from adjacent conventional sandstone reservoirs. The estimated mean volume of undiscovered gas is 10.0 trillion cubic ft of gas (TCFG), and 23 MMBNGL. For the three continuous (unconventional) assessment units and one conventional assessment unit in the Cherokee Platform Province, total mean volumes of undiscovered petroleum resources are estimated to be 463 MMBO, 11.2 TCFG and 35 MMBNGL.

Kansas, Missouri, Oklahoma↗

USGS1989

Regional Jurassic geologic framework of Alabama coastal waters area and adjacent Federal waters area

To date, numerous Jurassic hydrocarbon fields and pools have been discovered in the Cotton Valley Group, Haynesville Formation, Smackover Formation and Norphlet Formation in the tri-state area of Mississippi, Alabama and Florida, and in Alabama State coastal waters and adjacent Federal waters area. Petroleum traps are basement highs, salt anticlines, faulted salt anticlines and extensional faults associated with salt movement. Reservoirs include continental and marine sandstones, limestones and dolostones. Hydrocarbon types are oil, condensate and natural gas. The onshore stratigraphic and structural information can be used to establish a regional geologic framework for the Jurassic for the State coastal waters and adjacent Federal waters areas. Evaluation of the geologic information along with the hydrocarbon data from the tri-state area indicates that at least three Jurassic hydrocarbon trends (oil, oil and gas condensate, and deep natural gas) can be identified onshore. These onshore hydrocarbon trends can be projected into the Mobile area in the Central Gulf of Mexico and into the Pensacola, Destin Dome and Apalachicola areas in the Eastern Gulf of Mexico. Substantial reserves of natural gas are expected to be present in Alabama State waters and the northern portion of the Mobile area. Significant accumulations of oil and gas condensate may be encountered in the Pensacola, Destin Dome, and Apalachicola areas.

Marine Geology↗

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

An overview of the petroleum geology of the Arctic

Nine main petroleum provinces containing recoverable resources totalling 61 Bbbl liquids+269 Bbbloe of gas are known in the Arctic. The three best known major provinces are: West Siberia–South Kara, Arctic Alaska and Timan–Pechora. They have been sourced principally from, respectively, Upper Jurassic, Triassic and Devonian marine source rocks and their hydrocarbons are reservoired principally in Cretaceous sandstones, Triassic sandstones and Palaeozoic carbonates. The remaining six provinces except for the Upper Cretaceous–Palaeogene petroleum system in the Mackenzie Delta have predominantly Mesozoic sources and Jurassic reservoirs. There are discoveries in 15% of the total area of sedimentary basins ( c. 8×10 6 km 2 ), dry wells in 10% of the area, seismic but no wells in 50% and no seismic in 25%. The United States Geological Survey estimate yet-to-find resources to total 90 Bbbl liquids+279 Bbbloe gas, with four regions – South Kara Sea, Alaska, East Barents Sea, East Greenland – dominating. Russian estimates of South Kara Sea and East Barents Sea are equally positive. The large potential reflects primarily the large undrilled areas, thick basins and widespread source rocks.

Geological Society Memoir↗

USGS2013

Geology, sequence stratigraphy, and oil and gas assessment of the Lewis Shale Total Petroleum System, San Juan Basin, New Mexico and Colorado: Chapter 5 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

The Lewis Shale Total Petroleum System (TPS) in the San Juan Basin Province contains a continuous gas accumulation in three distinct stratigraphic units deposited in genetically related depositional environments: offshore-marine shales, mudstones, siltstones, and sandstones of the Lewis Shale, and marginal-marine shoreface sandstones and siltstones of both the La Ventana Tongue and the Chacra Tongue of the Cliff House Sandstone. The Lewis Shale was not a completion target in the San Juan Basin (SJB) in early drilling from about the 1950s through 1990. During that time, only 16 wells were completed in the Lewis from natural fracture systems encountered while drilling for deeper reservoir objectives. In 1991, existing wells that penetrated the Lewis Shale were re-entered by petroleum industry operators in order to fracture-stimulate the Lewis and to add Lewis gas production onto preexisting, and presumably often declining, Mesaverde Group production stratigraphically lower in the section. By 1997, approximately 101 Lewis completions had been made, both as re-entries into existing wells and as add-ons to Mesaverde production in new wells. Based on recent industry drilling and completion practices leading to successful gas production from the Lewis and because new geologic models indicate that the Lewis Shale contains both source rocks and reservoir rocks, the Lewis Shale TPS was defined and evaluated as part of this U.S. Geological Survey oil and gas assessment of the San Juan Basin. Gas in the Lewis Shale Total Petroleum System is produced from shoreface sandstones and siltstones in the La Ventana and Chacra Tongues and from distal facies of these prograding clastic units that extend into marine rocks of the Lewis Shale in the central part of the San Juan Basin. Reservoirs are in shoreface sandstone parasequences of the La Ventana and Chacra and their correlative distal parasequences in the Lewis Shale where both natural and artificially enhanced fractures produce gas. The Lewis Continuous Gas Assessment Unit (AU 50220261) is thought to be self-sourced from and self-sealed by marine shales and mudstones deposited within the Lewis Shale that enclose clastic parasequences in the La Ventana and Chacra Tongues. The gas resource is thought to be a continuous accumulation sourced from the Lewis Shale throughout the depositional basin. In the Lewis Continuous Gas Assessment Unit (AU 50220261), for continuous gas resources, there is an F95 of 8,315.22 billion cubic feet of gas (BCFG) and an F5 of 12,282.31 BCFG, with a mean value of 10,177.24 BCFG. There is an F95 of 18.08 million barrels of natural gas liquids (MMBNGL) and an F5 of 47.32 MMBNGL, with a mean of 30.53 MMBNGL.

Colorado;New Mexico↗

USGS1999

Interaction of tectonic and depositional processes that control the evolution of the Iberian Gulf of Cadiz margin

This study provides an integrated view of the growth patterns and factors that controlled the evolution of the Gulf of Cadiz continental margin based on studies of the tectonic, sedimentologic and oceanographic history of the area. Seven sedimentary regimes are identified, but there are more extensive descriptions of the late Cenozoic regimes because of the larger data base. The regimes of the Mesozoic passive margin include carbonate platforms, which become mixed calcareous-terrigenous deposits during the Late Cretaceous-early Tertiary. The Oligocene and Early Miocene terrigenous regimes developed, in contrast, over the active and transcurrent margins near the African-Iberian plate boundary. The top of the Gulf of Cadiz olistostrome, emplaced in the Late Miocene, is used as a key horizon to define the 'post-orogenic' depositional regimes. The Late Miocene progradational margin regime is characterized by a large terrigenous sediment supply to the margin and coincides with the closing of the Miocene Atlantic-Mediterranean gateways. The terrigenous drift depositional regime of the Early Pliocene resulted from the occurrence of high eustatic sea level and the characteristics of the Mediterranean outflow currents that developed after the opening of the Strait of Gibraltar. The Late Pliocene and Quaternary regimes are dominated by sequences of deposits related to cycles of high and low sea levels. Deposition of shelf-margin deltas and slope wedges correlate with regressive and low sea level regimes caused by eustasy and subsidence. During the highstand regimes of the Holocene, inner shelf prograding deltas and deep-water sediment drifts were developed under the influence of the Atlantic inflow and Mediterranean outflow currents, respectively. A modern human cultural regime began 2000 years ago with the Roman occupation of Iberia; human cultural effects on sedimentary regimes may have equalled natural factors such as climate change. Interplay of tectonic and oceanographic controls dominated the evolution of the Cadiz margin during the Cenozoic. Depositional sequences formed where the tectonic setting provided the accommodation space and the shape of the deposits has been greatly influenced by the strong unidirectional Atlantic inflow currents on the shelf and Mediterranean outflow currents on the slope. The entire cycle of the inflow and outflow deposition along the margin has been controlled first by the tectonic evolution of the Betic and Rif gateways, which become closed during the Late Miocene, and after the Messinian by the opening of the Strait of Gibraltar. Strong current development during eustatic sea level highstands of the Pliocene and Quaternary has controlled deposition because of maximum sill depths at Gibraltar for water circulation. Lowstand sea levels slowed circulation and resulted in mud drapes over the slope and regressive stratigraphic sequences over the shelf. More recently, the human industrial revolution has caused heavy metal contamination of sediment and water over the Cadiz margin. Human activity also has affected sedimentation rates because of deforestation that caused increased depositional rates near undammed rivers and decreased rates where rivers have been dammed. Future research efforts will need to focus on: (1) the effect of increased Mediterranean outflow caused by river damming plus global warming and the increased outflow as a potential trigger for new ice ages; (2) assessments of geologic hazards for planning man-made shoreline structures, developing offshore petroleum resources and maintaining undersea communications cables; and (3) confirmation of the general geologic history of the Cadiz margin.

Marine Geology↗

USGS2008

Geologic controls on the growth of petroleum reserves

The geologic characteristics of selected siliciclastic (largely sandstone) and carbonate (limestone and dolomite) reservoirs in North America (largely the continental United States) were investigated to improve our understanding of the role of geology in the growth of petroleum reserves. Reservoirs studied were deposited in (1) eolian environments (Jurassic Norphlet Formation of the Gulf Coast and Pennsylvanian-Permian Minnelusa Formation of the Powder River Basin), (2) interconnected fluvial, deltaic, and shallow marine environments (Oligocene Frio Formation of the Gulf Coast and the Pennsylvanian Morrow Formation of the Anadarko and Denver Basins), (3) deeper marine environments (Mississippian Barnett Shale of the Fort Worth Basin and Devonian-Mississippian Bakken Formation of the Williston Basin), (4) marine carbonate environments (Ordovician Ellenburger Group of the Permian Basin and Jurassic Smackover Formation of the Gulf of Mexico Basin), (5) a submarine fan environment (Permian Spraberry Formation of the Midland Basin), and (6) a fluvial environment (Paleocene-Eocene Wasatch Formation of the Uinta-Piceance Basin). The connection between an oil reservoir's production history and geology was also evaluated by studying production histories of wells in disparate reservoir categories and wells in a single formation containing two reservoir categories. This effort was undertaken to determine, in general, if different reservoir production heterogeneities could be quantified on the basis of gross geologic differences. It appears that reserve growth in existing fields is most predictable for those in which reservoir heterogeneity is low and thus production differs little between wells, probably owing to relatively homogeneous fluid flow. In fields in which reservoirs are highly heterogeneous, prediction of future growth from infill drilling is notably more difficult. In any case, success at linking heterogeneity to reserve growth depends on factors in addition to geology, such as engineering and technological advances and political or cultural or economic influences.

Bulletin↗

USGS2004

Sembar Goru/Ghazij Composite Total Petroleum System, Indus and Sulaiman-Kirthar Geologic Provinces, Pakistan and India

Geochemical analyses of rock samples and produced oil and gas in the Indus Basin have shown that the bulk of the hydrocarbons produced in the Indus Basin are derived from the Lower Cretaceous Sembar Formation and equivalent rocks. The source rocks of the Sembar are composed of shales that were deposited in shallow marine environments, are of mixed type-II and type-III kerogen, with total organic carbon (TOC) content ranging from less than 0.5 percent to more than 3.5 percent; the average TOC of the Sembar is about 1.4 percent. Vitrinite reflectance (Ro) values range from immature (< 0.6 percent Ro) to over mature (>1.35 percent Ro). Thermal generation of hydrocarbons in the Sembar Formation began 65 to 40 million years ago, (Mya) during Paleocene to Oligocene time. Hydrocarbon expulsion, migration, and entrapment are interpreted to have occurred mainly 50 to 15 Mya, during Eocene to Miocene time, prior to and contemporaneously with the development of structural traps in Upper Cretaceous and Tertiary reservoirs. The principal reservoirs in the Sembar-Goru/Ghazij Composite Total Petroleum System are Upper Cretaceous through Eocene sandstones and limestones.

Bulletin↗

USGS2015

Assessment of unconventional oil and gas resources in the Jurassic Sargelu Formation of Iraq, 2014

The U.S. Geological Survey (USGS) quantitatively assessed the potential for unconventional (continuous) oil and gas resources within the Jurassic Sargelu Formation of Iraq. Organic-rich shales of the Jurassic Sargelu Formation are one of the main petroleum source rocks for conventional fields in the Arabian Peninsula. The Sargelu Formation consists of marine shales, with as much as 10 weight percent sulfur-rich Type IIS organic matter, deposited in a relatively deep, anoxic Jurassic depocenter. The potential for volumes of oil retained in the Sargelu Formation source-reservoir rock system following oil migration, cracking, or degradation is the focus of this assessment. Conventional oil and gas resources of Iraq were assessed by the USGS in 2012. The USGS assessment methodology consists of a well-performance approach that recognizes the geologic variability within assessed reservoirs. For non-U.S. assessments, the USGS assesses shale-gas or shale-oil reservoirs that (1) contain greater than 2 weight percent total organic carbon (TOC), (2) are within the proper thermal maturity window for oil or gas generation, (3) have greater than 15-m thickness of organic-rich shale, and (4) contain Type I or II organic matter. These specific USGS criteria when applied to any given shale-oil or shale-gas reservoir might significantly reduce the potential resource assessment area compared to maps made with greater than 1 weight percent TOC.

Jurassic Sargelu Formation↗

USGS2016

Assessment of undiscovered hydrocarbon resources of sub-Saharan Africa

Introduction The main objective of the U.S. Geological Survey’s (USGS) National and Global Petroleum Assessment Project is to assess the potential for undiscovered, technically recoverable oil and natural gas resources of the United States and the world (U.S. Geological Survey World Conventional Resources Assessment Team, 2012). The USGS updated assessments that were completed during the USGS World Petroleum Assessment 2000 (U.S. Geological Survey World Energy Assessment Team, 2000) and conducted new assessments in areas around the world that were not previously examined (U.S. Geological Survey World Conventional Resources Assessment Team, 2012). These assessments used the latest geology-based assessment methodology for conventional oil and gas resources. The new assessments are available at the USGS website, ( http://energy.usgs.gov/OilGas/AssessmentsData/WorldPetroleumAssessment.aspx ) . As part of this project, the USGS assessed 13 geologic provinces located in sub-Saharan Africa (U.S. Geological Survey World Conventional Resources Assessment Team, 2012). Coastal provinces were extended offshore to water depths ranging from 2,000 to 4,000 meters (m). Within these 13 geologic provinces 18 assessment units (figs. 1, 2) were identified. The west Africa provinces are (1) the Senegal, containing the passive-margin Senegal Basin of Middle Jurassic to Holocene age; (2) the West African Coastal, characterized by rift, passive-margin, and transform tectonics; (3) the Gulf of Guinea, characterized by transform tectonics; (4) the Niger Delta, containing more than 9,100 m of sedimentary rock and recent sediments; (5) the West-Central Coastal, which contains the Aptian salt basin, is dominated by both rift and sag tectonics, and includes the Congo Basin; and (6) the Orange River Coastal, containing more than 7,000 m of syn-rift and post-rift sedimentary rock. The West African Coastal Province was assessed for the first time, whereas the other five west Africa provinces were reassessed for the 2012 World Oil and Wandrey Gas Resource Assessment (fig. 1 of U.S. Geological Survey World Conventional Resources Assessment Team, 2012). More than 275 new oil and gas fields have been discovered in the six west Africa provinces (IHS Energy, 2008, 2009) since the USGS World Petroleum Assessment in 2000 (U.S. Geological Survey World Energy Assessment Team, 2000). These provinces were assessed because of increased energy exploration activity and new oil and gas discoveries within the provinces. Seven provinces not assessed as part of the World Petroleum Assessment 2000 (U.S. Geological Survey World Energy Assessment Team, 2000) were assessed by the USGS as part of the World Assessment 2012 (U.S. Geological Survey World Conventional Resources Assessment Team, 2012). These provinces are (1) the Chad Province, containing Cretaceous and Cenozoic-age lacustrine, continental, and minor marine rocks; (2) the Sud Province, containing Cretaceous and Paleogene age lacustrine, continental, and minor marine rocks; (3) the South Africa Coastal Province, which contains rift, transform, and passive-margin rocks; (4) the Mozambique Coastal Province, containing rift, drift, and passive-margin rocks; (5) the Morondava Province, which contains failed rift, drift, and passive-margin rocks; (6) the Tanzania Coastal Province, containing rift, drift, and passive-margin rocks; and (7) the Seychelles Province, which contains rift and drift rocks. At the time of this assessment 157 oil and gas fields had been discovered in the seven provinces (IHS Energy, 2009). These provinces were assessed because of increased interest and new oil and gas discoveries within the provinces. The assessment was geology-based and used the total petroleum system (TPS) concept. The geologic elements of a TPS are hydrocarbon source rocks (source rock maturation and hydrocarbon generation and migration), reservoir rocks (quality and distribution), and traps where hydrocarbon accumulates. Using these geologic criteria, 16 conventional total petroleum systems and 18 assessment units in the 13 provinces were defined. The undiscovered, technically recoverable oil and gas resources were assessed for all assessment units.

Data Series↗

USGS2011

Geology and petroleum potential of the Eurasia Basin

The Eurasia Basin petroleum province comprises the younger, eastern half of the Arctic Ocean, including the Cenozoic Eurasia Basin and the outboard part of the continental margin of northern Europe. For the USGS petroleum assessment (CARA), it was divided into four assessment units (AUs): the Lena Prodelta AU, consisting of the deep-marine part of the Lena Delta; the Nansen Basin Margin AU, comprising the passive margin sequence of the Eurasian plate; and the Amundsen Basin and Nansen Basin AUs which encompass the abyssal plains north and south of the Gakkel Ridge spreading centre, respectively. The primary petroleum system thought to be present is sourced in c . 50–44 Ma (Early to Middle Eocene) condensed pelagic deposits that could be widespread in the province. Mean estimates of undiscovered, technically recoverable petroleum resources include <1 billion barrels of oil (BBO) and about 1.4 trillion cubic feet (TCF) of nonassociated gas in Lena Prodelta AU, and <0.4 BBO and 3.4 TCF nonassociated gas in the Nansen Basin Margin AU. The Nansen Basin and Amundsen Basin AUs were not quantitatively assessed because they have less than 10% probability of containing at least one accumulation of 50 MMBOE (million barrels of oil equivalent).

Book chapter↗

USGS1985

EARTHQUAKE HAZARDS IN THE OFFSHORE ENVIRONMENT.

This report discusses earthquake effects and potential hazards in the marine environment, describes and illustrates methods for the evaluation of earthquake hazards, and briefly reviews strategies for mitigating hazards. The report is broadly directed toward engineers, scientists, and others engaged in developing offshore resources. The continental shelves have become a major frontier in the search for new petroleum resources. Much of the current exploration is in areas of moderate to high earthquake activity. If the resources in these areas are to be developed economically and safely, potential earthquake hazards must be identified and mitigated both in planning and regulating activities and in designing, constructing, and operating facilities. Geologic earthquake effects that can be hazardous to marine facilities and operations include surface faulting, tectonic uplift and subsidence, seismic shaking, sea-floor failures, turbidity currents, and tsunamis.

Ocean science and engineering↗

USGS2014

Geological controls on the occurrence of gas hydrate from core, downhole log, and seismic data in the Shenhu area, South China Sea

Multi-channel seismic reflection data, well logs, and recovered sediment cores have been used in this study to characterize the geologic controls on the occurrence of gas hydrate in the Shenhu area of the South China Sea. The concept of the "gas hydrate petroleum system" has allowed for the systematic analysis of the impact of gas source, geologic controls on gas migration, and the role of the host sediment in the formation and stability of gas hydrates as encountered during the 2007 Guangzhou Marine Geological Survey Gas Hydrate Expedition (GMGS-1) in the Shenhu area. Analysis of seismic and bathymetric data identified seventeen sub-linear, near-parallel submarine canyons in this area. These canyons, formed in the Miocene, migrated in a northeasterly direction, and resulted in the burial and abandonment of canyons partially filled by coarse-grained sediments. Downhole wireline log (DWL) data were acquired from eight drill sites and sediment coring was conducted at five of these sites, which revealed the presence of suitable reservoirs for the occurrence of concentrated gas hydrate accumulations. Gas hydrate-bearing sediment layers were identified from well log and core data at three sites mainly within silt and silt clay sediments. Gas hydrate was also discovered in a sand reservoir at one site as inferred from the analysis of the DWL data. Seismic anomalies attributed to the presence of gas below the base of gas hydrate stability zone, provided direct evidence for the migration of gas into the overlying gas hydrate-bearing sedimentary sections. Geochemical analyses of gas samples collected from cores confirmed that the occurrence of gas hydrate in the Shenhu area is controlled by the presence thermogenic methane gas that has migrated into the gas hydrate stability zone from a more deeply buried source.

Shenhu area, South China Sea↗

USGS2012

Vitrinite reflectance data for Cretaceous marine shales and coals in the Bighorn Basin, north-central Wyoming and south-central Montana

The Bighorn Basin is a large Laramide (Late Cretaceous through Eocene) structural and sedimentary basin that encompasses about 10,400 square miles in north-central Wyoming and south-central Montana. The purpose of this report is to present new vitrinite reflectance data collected from Cretaceous marine shales and coals in the Bighorn Basin to better characterize the thermal maturity and petroleum potential of these rocks. Ninety-eight samples from Lower Cretaceous and lowermost Upper Cretaceous strata were collected from well cuttings from wells stored at the U.S. Geological Survey (USGS) Core Research Center in Lakewood, Colorado.

Wyoming;Montana↗

USGS1997

Fluvial-deltaic sedimentation and stratigraphy of the ferron sandstone

East-central Utah has world-class outcrops of dominantly fluvial-deltaic Turonian to Coniacian aged strata deposited in the Cretaceous foreland basin. The Ferron Sandstone Member of the Mancos Shale records the influences of both tidal and wave energy on fluvial-dominated deltas on the western margin of the Cretaceous western interior seaway. Revisions of the stratigraphy are proposed for the Ferron Sandstone. Facies representing a variety of environments of deposition are well exposed, including delta-front, strandline, marginal marine, and coastal-plain. Some of these facies are described in detail for use in petroleum reservoir characterization and include permeability structure.

Brigham Young University Geology Studies↗

USGS2008

Citronelle Dome: A giant opportunity for multizone carbon storage and enhanced oil recovery in the Mississippi Interior Salt Basin of Alabama

The Citronelle Dome is a giant, salt-cored anticline in the eastern Mississippi Interior Salt Basin of southern Alabama that is located near several large-scale, stationary, carbon-emitting sources in the greater Mobile area. The dome forms an elliptical, four-way structural closure containing opportunities for CO2-enhanced oil recovery (CO2-EOR) and large-capacity saline reservoir CO2 sequestration. The Citronelle oil field, located on the crest of the dome, has produced more than 169 million bbl of 42-46?? API gravity oil from sandstone bodies in the Lower Cretaceous Rodessa Formation. The top seal for the oil accumulation is a thick succession of shale and anhydrite, and the reservoir is underfilled such that oil-water contacts are typically elevated 30-60 m (100-200 ft) above the structural spill point. Approximately 31-34% of the original oil in place has been recovered by primary and secondary methods, and CO2-EOR has the potential to increase reserves by up to 20%. Structural contour maps of the dome demonstrate that the area of structural closure increases upward in section. Sandstone units providing prospective carbon sinks include the Massive and Pilot sands of the lower Tuscaloosa Group, as well as several sandstone units in the upper Tuscaloosa Group and the Eutaw Formation. Many of these sandstone units are characterized by high porosity and permeability with low heterogeneity. The Tuscaloosa-Eutaw interval is capped by up to 610 m (2000 ft) of chalk and marine shale that are proven reservoir seals in nearby oil fields. Therefore, the Citronelle Dome can be considered a major geologic sink where CO2 can be safely stored while realizing the economic benefits associated with CO2-EOR. Copyright ?? 2008. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗