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At least 145 records · Page 8Linked to original sources
USGS1998

Genetic features of petroleum systems in rift basins of eastern China

Most oil-bearing basins in eastern China are Mesozoic-Cenozoic continental rifts which have played a habitat for oil and gas in China. Investigation of the petroleum systems may give a better understanding of the oil and gas habitats in these basins. Of the essential elements of the petroleum system, the source rock is the most important in rift basins. However, rift tectonic evolution controls all the essential elements and processes nevessary for a petroleum system. A four stage evolution model is suggested for the controls in the rift basin. A rift basin may consist of sub-basins, depressions, sub-depressions, and major, moderate, and minor uplifts. A depression or sub-depression has its own depocentre (mainly occupied by source rock) and all kinds of lacustrine sediments, and thus has all the essential elements of a petroleum system. However, only those depressions or sub-depressions which are rich in organic matter and deeply buried to generate oil and gas form petroleum systems. Immature oil, another characteristic, complicates the petroleum system in the rift basins. Three types of oil and gas habitats are described as a result of this analysis of the petroleum systems of the 26 largest oil and gas fields discovered in eastern China rift basins: uplifts between oil source centres are the most prospective areas for oil and gas accumulations, slopes connecting oil source centres and uplifts are the second, and the third type is subtle traps in the soil source centre.Most oil-bearing basins in eastern China are Mesozoic-Cenozoic continental rifts which have played a habitat for oil and gas in China. Investigation of the petroleum systems may give a better understanding of the oil and gas habitats in these basins. Of the essential elements of the petroleum system, the source rock is the most important in rift basins. However, rift tectonic evolution controls all the essential elements and processes necessary for a petroleum system. A four stage evolution model is suggested for the controls in the rift basin. A rift basin may consist of sub-basins, depressions, sub-depressions, and major, moderate, and minor uplifts. A depression or sub-depression has its own depocentre (mainly occupied by source rock) and all kinds of lacustrine sediments, and thus has all the essential elements of a petroleum system. However, only those depressions or sub-depressions which are rich in organic matter and deeply buried to generate oil and gas form petroleum systems. Immature oil, another characteristic, complicates the petroleum system in the rift basins. Three types of oil and gas habitats are described as a result of this analysis of the petroleum systems of the 26 largest oil and gas fields discovered in eastern China rift basins: uplifts between oil source centres are the most prospective areas for oil and gas accumulations, slopes connecting oil source centres and uplifts are the second, and the third type is subtle traps in the oil source centre.

Marine and Petroleum Geology↗
USGS1999

Development of San Leandro synform and neotectonics of the San Francisco Bay block, California

High-resolution, 24-channel seismic-reflection data show a stratified synform beneath south San Francisco Bay. These seismic-reflection data reveal an eastward-dipping bedrock surface that is about 40 m deep (subbottom) beneath the western south bay, and that reaches a maximum observed depth of 500-800 m (subbottom) below the eastern half of the south bay. An angular unconformity cuts both the synform and underlying bedrock. The age of the unconformity is unknown but may be Pleistocene, when these strata forming the synform were presumably exposed subaerially during lowered sea levels. The synformal strata, the unconformity, and some generally flat-lying and overlying strata are folded near the eastern shore of the bay. This folding may result from movement on the Hayward fault (fault interactions and localized strain partitioning) or from compressional deformation in the East Bay Hills related to NE-SW ('fault-normal') convergence between the Pacific and North American plates. In general, reflections from sediment overlying the unconformity are flat lying (except near the eastern shore of the bay), whereas reflections beneath the unconformity dip eastward. The overlying, flat sediment section fills a shallow basin that is coincident with an elliptical residual gravity low. This low appears to be related to the deeper sedimentary, synformal section based on the spatial correlation between the east-dipping reflections and the gravity anomaly. Projecting the east-dipping reflections to the center of the gravity low suggests that the total section of flat-lying and dipping reflections in the synform may exceed 1000 m. Modeling of the gravity low suggests a total low-density section, about 1.5 km thick, at the center of the synform relative to the surrounding bedrock of presumed Franciscan Complex.High-resolution, 24-channel seismic-reflection data show a stratified synform beneath south San Francisco Bay. These seismic-reflection data reveal an eastward-dipping bedrock surface that is about 40 m deep (subbottom) beneath the western south bay, and that reaches a maximum observed depth of 500-800 m (subbottom) below the eastern half of the south bay. An angular unconformity cuts both the synform and underlying bedrock. The age of the unconformity is unknown but may be Pleistocene, when these strata forming the synform were presumably exposed subaerially during lowered sea levels. The synformal strata, the unconformity, and some generally flat-lying and overlying strata are folded near the eastern shore of the bay. This folding may result from movement on the Hayward fault (fault interactions and localized strain partitioning) or from compressional deformation in the East Bay Hills related to NE-SW (`fault-normal') convergence between the Pacific and North American plates. In general, reflections from sediment overlying the unconformity are flat lying (except near the eastern shore of the bay), whereas reflections beneath the unconformity dip eastward. The overlying, flat sediment section fills a shallow basin that is coincident with an elliptical residual gravity low. This low appears to be related to the deeper sedimentary, synformal section based on the spatial correlation between the east-dipping reflections and the gravity anomaly. Projecting the east-dipping reflections to the center of the gravity low suggests that the total section of flat-lying and dipping reflections in the synform may exceed 1000 m. Modeling of the gravity low suggests a total low-density section, about 1.5 km thick, at the center of the synform relative to the surrounding bedrock of presumed Franciscan Complex.

Marine and Petroleum Geology↗
USGS2020

Oil-source rock correlation studies in the unconventional Upper Cretaceous Tuscaloosa marine shale (TMS) petroleum system, Mississippi and Louisiana, USA

The U.S. Geological Survey assessed undiscovered unconventional hydrocarbon resources reservoired in the Upper Cretaceous Tuscaloosa marine shale (TMS) of southern Mississippi and adjacent Louisiana in 2018. As part of the assessment, oil-source rock correlations were examined in the TMS play area where operators produce light (38–45° API), sweet oil from horizontal, hydraulically-fractured wells in an overpressured ‘high-resistivity’ (>5 Ω-m) zone at the base of the TMS. Geochemical data from 39 oil samples and 17 source rock solvent extracts collected from the TMS play area indicate close correspondence for Tuscaloosa Group oils [from lower Tuscaloosa, middle Tuscaloosa (the TMS) and upper Tuscaloosa reservoirs] in thermal maturity (computed from MPI), SARA proportions, n- alkane distributions, isoprenoid and DBT/P ratios, monoaromatic steroids, and δ 13 C isotopic compositions (from whole oils, saturate and aromatic fractions). Other parameters (normal steranes, extended homohopanes, C 31 R/C 30 hopane, norhopane/hopane and tricyclic terpane ratios, gammacerane/hopane) show most oil samples have similar values, suggesting all Tuscaloosa Group oils are from a common mixed marine-terrigenous source rock. Tighter distributions for triaromatic steroid (TAS) and δ 13 C isotopic composition for conventional oils in lower and upper Tuscaloosa reservoirs may indicate charge occurred in a single or shorter pulse relative to TMS oils which show broader TAS and δ 13 C properties, possibly from their generation over an extended period of burial maturation. Dissimilarity in geochemical properties between lower Tuscaloosa source rock solvent extracts and Tuscaloosa Group oils indicates lower Tuscaloosa source rocks did not contribute significantly to conventional and unconventional Tuscaloosa Group hydrocarbon accumulations. Whereas, TMS solvent extracts are similar to Tuscaloosa Group oils, suggesting an oil-source rock correlation. Excluding the possibility for long-distance lateral migration from a similar source downdip (which is unnecessary given thermal maturity considerations), the observations indicate 1. the TMS is a self-sourced reservoir, 2. the TMS is the source of oils accumulated in nearby conventional Tuscaloosa Group reservoirs, and 3. thin organic-rich shales in the lower Tuscaloosa did not contribute substantially to any oil accumulations in the Tuscaloosa Group.

Louisiana, Mississippi↗
USGS2018

Correlation of the Tuscaloosa marine shale in Mississippi, Louisiana, and east Texas, U.S.A.

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable unconventional petroleum resources in the Upper Cretaceous marine shale of the Tuscaloosa Group (Tuscaloosa marine shale; TMS) in 2018. As part of the geologic characterization in preparation for the assessment, a series of wireline log cross sections were constructed to illustrate TMS thickness trends and aid in the delineation of the assessment unit (AU). Lithostratigraphic units were correlated based on gamma ray, spontaneous potential, and resistivity log responses and generally follow the classic stratigraphic nomenclature first proposed in the 1960s. Correlated stratigraphic units include (from youngest to oldest) the Austin Group, Eagle Ford Shale, upper Tuscaloosa, Tuscaloosa marine shale, lower Tuscaloosa, and Lower Cretaceous. A high resistivity zone (HRZ) in the basal Tuscaloosa marine shale was delineated where resistivity was greater than 5 ohm-meters and high resistivity sections were separated by less than 20 feet of low resistivity shale. The HRZ was identified regionally and might indicate petroleum accumulations in the TMS. Third-party biostratigraphic data from wells in Mississippi and Louisiana were integrated into the well control, which aided wireline log correlation. Cross sections depict east-west thinning of the TMS onto the Sabine uplift and north-south thickening of the TMS off of the Lower Cretaceous shelf margin. The western boundary of the USGS-defined Tuscaloosa Marine Shale Continuous Oil AU was drawn in western Louisiana near the Texas-Louisiana state border based on stratigraphic thinning of the Upper Cretaceous section onto the structural high of the Sabine uplift as projected downdip.

Louisiana, Mississippi, Texas↗
USGS2006

delta 15N and non-carbonate delta 13C values for two petroleum source rock reference materials and a marine sediment reference material

Samples of United States Geological Survey (USGS) Certified Reference Materials USGS Devonian Ohio Shale (SDO-1), and USGS Eocene Green River Shale (SGR-1), and National Research Council Canada (NRCC) Certified Marine Sediment Reference Material (PACS-2), were sent for analysis to four separate analytical laboratories as blind controls for organic rich sedimentary rock samples being analyzed from the Red Dog mine area in Alaska. The samples were analyzed for stable isotopes of carbon (delta13Cncc) and nitrogen (delta15N), percent non-carbonate carbon (Wt % Cncc) and percent nitrogen (Wt % N). SDO-1, collected from the Huron Member of the Ohio Shale, near Morehead, Kentucky, and SGR-1, collected from the Mahogany zone of the Green River Formation are petroleum source rocks used as reference materials for chemical analyses of sedimentary rocks. PACS-2 is modern marine sediment collected from the Esquimalt, British Columbia harbor. The results presented in this study are, with the exceptions noted below, the first published for these reference materials. There are published information values for the elemental concentrations of 'organic' carbon (Wt % Corg measured range is 8.98 - 10.4) and nitrogen (Wt % Ntot 0.347 with SD 0.043) only for SDO-1. The suggested values presented here should be considered 'information values' as defined by the NRCC Institute for National Measurement Reference Materials and should be useful for the analysis of 13C, 15N, C and N in organic material in sedimentary rocks.

Open-File Report↗
USGS1983

Trends in Engineering Geologic and Related Mapping 1972–1983

Progress is reviewed that has been made during the period 1972-1982 in producing medium- and small-scale engineering geologic maps with a variety of content. Improved methods to obtain and present information are evolving. Standards concerning text and map content, soil and rock classification, and map symbols have been proposed. Application of geomorphological techniques in terrain evaluation has increased, as has the use of aerial photography and other remote sensing. Computers are being used to store, analyze, retrieve, and print both text and map information. Development of offshore resources, especially petroleum, has led to marked improvement and growth in marine engineering geology and geotechnology. Coordinated planning for societal needs has required broader scope and increased complexity of both engineering geologic and environmental geologic studies. Refs.

Bulletin of the Association of Engineering Geologi↗
USGS1974

Structural framework of United States Atlantic outer continental shelf north of Cape Hatteras

To assess the area’s hydrocarbon potential, regional geologic and geophysical studies are being conducted by the U.S. Geological Survey to determine the structural framework of the United States Atlantic outer continental shelf (AOCS) north of Cape Hatteras. Preliminary interpretations of geophysical data suggest that the buried ridge under the eastern edge of the AOCS in the Baltimore Canyon trough area is deeper and farther west than previously suspected. Although it is not observed under the seaward extension of the Cape Fear arch, this ridge can be traced from the south side of the Baltimore Canyon trough northeastward toward the eastern edge of the Georges Bank trough. In the Baltimore Canyon trough area, the ridge seems to be fault controlled and to form the eastern edge of a Mesozoic depocenter in which approximately 12 km of relatively undisturbed post-Paleozoic sediments accumulated. Below a depth of 6 km, rocks previously considered to be crystalline basement instead may be carbonate and/or evaporite sequences of Jurassic age or older which overlie an even deeper crystalline basement. More than 8 km of sediments are present beneath the continental shelf on Georges Bank. The preliminary regional geophysical studies indicate that thick marine sedimentary sections and geologic structures favorable for the accumulation of petroleum apparently exist under the AOCS off the northeastern part of the United States.

Atlantic outer continental shelf↗
USGS1974

Atlantic OCS resource and leasing potential

Thick marine sedimentary sections and geologic structures favorable for the accumulation of petroleum are indicated in Georges Bank basin, the Baltimore Canyon trough, and the Southeast Georgia embayment. Undiscovered recoverable resources of petroleum on the Atlantic OCS are estimated to be 10 billion to 20 billion barrels of oil and 55 trillion to 110 trillion cubic feet of gas. Such estimates carry a high degree of uncertainty. Preliminary results suggest that the most favorable areas for leasing are under the deeper waters of the shelf.

Atlantic OCS, Baltimore Canyon trough, Georges Ban↗
USGS1997

3-D reservoir characterization of the House Creek oil field, Powder River Basin, Wyoming

This CD-ROM is intended to serve a broad audience. An important purpose is to explain geologic and geochemical factors that control petroleum production from the House Creek Field. This information may serve as an analog for other marine-ridge sandstone reservoirs. The 3-D slide and movie images are tied to explanations and 2-D geologic and geochemical images to visualize geologic structures in three dimensions, explain the geologic significance of porosity/permeability distribution across the sandstone bodies, and tie this to petroleum production characteristics in the oil field. Movies, text, images including scanning electron photomicrographs (SEM), thin-section photomicrographs, and data files can be copied from the CD-ROM for use in external mapping, statistical, and other applications.

Data Series↗
USGS1975

Interim report on petroleum resource potential and geologic hazards in the outer continental shelf of the Gulf of Alaska Tertiary province

The potential for discovering large accumulations of petroleum on the Outer Continental Shelf of the Gulf of Alaska Tertiary Province cannot be evaluated with much confidence at present because of the inadequacies of the available offshore geological and geophysical data. The 22 deep test wells that have been drilled since 1954 have been unsuccessful because structure is complex and because suitable reservoir rocks have not been found in favorable structural positions. Although it is possible that the factors controlling accumulation of petroleum may improve offshore, regional stratigraphic and structural considerations together with the limited geophysical data suggest that this is not necessarily the case. Extrapolation of onshore geology together with the limited amount of marine geophysical data, indicate that the eastern Gulf of Alaska Outer Continental Shelf is geologically complex and consists of several areas with markedly differing structural styles and petroleum potential.

Alaska↗
USGS2016

The Chuar Petroleum System, Arizona and Utah

The Neoproterozoic Chuar Group consists of marine mudstone, sandstone and dolomitic strata divided into the Galeros and Kwagunt Formations, and is exposed only in the eastern Grand Canyon, Arizona. Research by the U.S. Geological Survey (USGS) in the late 1980s identified strata within the group to be possible petroleum source rocks, and in particular the Walcott Member of the Kwagunt Formation. Industry interest in a Chuar oil play led to several exploratory wells drilled in the 1990s in southern Utah and northern Arizona to test the overlying Cambrian Tapeats Sandstone reservoir, and confirm the existence of the Chuar in subcrop. USGS geochemical analyses of Tapeats oil shows in two wells have been tentatively correlated to Chuar bitumen extracts. Distribution of the Chuar in the subsurface is poorly constrained with only five well penetrations, but recently published gravity/aeromagnetic interpretations provide further insight into the Chuar subcrop distribution. The Chuar petroleum system was reexamined as part of the USGS Paradox Basin resource assessment in 2011. A map was constructed to delineate the Chuar petroleum system that encompasses the projected Chuar source rock distribution and all oil shows in the Tapeats Sandstone, assuming that the Chuar is the most likely source for such oil shows. Two hypothetical plays were recognized but not assessed: (1) a conventional play with a Chuar source and Tapeats reservoir, and (2) an unconventional play with a Chuar source and reservoir. The conventional play has been discouraging because most surface structures have been tested by drilling with minimal petroleum shows, and there is some evidence that petroleum may have been flushed by CO2 from Tertiary volcanism. The unconventional play is untested and remains promising even though the subcrop distribution of source facies within the Chuar Group is largely unknown.

Book chapter↗
USGS2022

Characterization of the partial oxidation products of crude oil contaminating groundwater at the U.S. Geological Survey Bemidji research site in Minnesota by elemental analysis, radiocarbon dating, nuclear magnetic resonance spectroscopy, and Fourier transform ion cyclotron resonance mass spectrometry

In oil spill research, a topic of increasing attention during the last decade has been the environmental impact of the partial oxidation products that result from transformation of the petroleum in freshwater, marine, and terrestrial ecosystems. This report describes the isolation and characterization of the partial oxidation products from crude oil contaminating groundwater at the long-term U.S. Geological Survey Bemidji research site in Minnesota. As the result of a pipeline burst in August 1979, a body of light aliphatic crude oil is present from the land surface to 2 meters below the water table in a shallow sand and gravel aquifer in a remote area outside Bemidji, Minnesota, United States. Biodegradation has resulted in the formation of a plume of dissolved organic carbon (DOC) downgradient from the oil body. Groundwater has also been contaminated in an area known as the spray zone, from vertical infiltration of DOC resulting from biodegradation of oil in the soil column, and possibly from photooxidation of oil at the soil surface. The majority of DOC in the contaminated groundwater is in the form of nonvolatile organic acids (NVOAs) which represent the partial oxidation products of the crude oil constituents. The NVOAs have been classified into three fractions according to their isolation on XAD resins: hydrophobic neutrals (HPON), hydrophobic acids (HPOA), and hydrophilic acids (HPIA). These fractions of NVOAs were isolated from wells downgradient from the oil body (sampling well numbers 533, 532, 530, 515), in the spray zone (603), and from an uncontaminated well upgradient of the oil body (310) between the years 1986 and 1989, and again from wells 530 and 603 in 1998. The samples have been characterized by elemental analysis, radiocarbon dating, carbon-13 nuclear magnetic resonance spectroscopy ( 13 C NMR), and negative-mode (-) electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (ESI FTICR-MS), with a particular focus on fractions from wells 310, 530, and 603. All the characterization data indicate that the NVOAs from contaminated wells are distinguishable from the background DOC. Carbon-14 ( 14 C) ages of NVOAs from contaminated wells ranged from 3,615 to 18,985 years before the present, whereas the background DOC from the aquifer was post-bomb (post 1950). By elemental analysis, NVOAs from contaminated wells had higher sulfur but lower nitrogen contents than the background. By electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry, number average molecular weights determined from assigned molecular formulas ranged from 416 to 486 daltons for the HPOA and HPIA fractions from both background and contaminant wells. NVOAs from contaminated wells had significantly greater numbers of assigned molecular formulas containing sulfur, with elevated concentrations of the S 1 O 4-10 species in particular. Compared to the background, HPOA and HPIA fractions from contaminant wells had a broader range of double bond equivalents (DBEs) within O n compound classes (n is number of atoms). Additionally, within O n compound classes, contaminant well HPOA fractions had a greater abundance of lower n (less than eight) than the background. Contaminant well double bond equivalents versus carbon number (C # ) plots of oxygen compound classes suggest oil-derived aliphatic compounds in the range from C 12 to C 22 in HPOA and HPIA fractions and oil-derived compounds containing aromatic or saturated rings in the approximate range from C 20 to C 30 are present in HPOA fractions. The data suggest the NVOAs originate from biodegradation of several classes of C 12 and greater crude oil constituents: sulfur-containing constituents, including possibly the resins and asphaltenes; constituents containing aromatic rings substituted with methyl groups, including alkylaromatic and naph- thenoaromatic compounds, and C 12 to C 22 alkyl constituents. The overall similarities of the carbon-13 nuclear magnetic resonance spectra for the well 603 and 530 samples from the two sampling dates suggest that a steady state in the composition of the partial oxidation products in each of the two wells had been reached between 1986–1989 and 1998.

Minnesota↗
USGS2015

Assessment of unconvential (tight) gas resources in Upper Cook Inlet Basin, South-central Alaska

A geologic model was developed for the assessment of potential Mesozoic tight-gas resources in the deep, central part of upper Cook Inlet Basin, south-central Alaska. The basic premise of the geologic model is that organic-bearing marine shales of the Middle Jurassic Tuxedni Group achieved adequate thermal maturity for oil and gas generation in the central part of the basin largely due to several kilometers of Paleogene and Neogene burial. In this model, hydrocarbons generated in Tuxedni source rocks resulted in overpressure, causing fracturing and local migration of oil and possibly gas into low-permeability sandstone and siltstone reservoirs in the Jurassic Tuxedni Group and Chinitna and Naknek Formations. Oil that was generated either remained in the source rock and subsequently was cracked to gas which then migrated into low-permeability reservoirs, or oil initially migrated into adjacent low-permeability reservoirs, where it subsequently cracked to gas as adequate thermal maturation was reached in the central part of the basin. Geologic uncertainty exists on the (1) presence of adequate marine source rocks, (2) degree and timing of thermal maturation, generation, and expulsion, (3) migration of hydrocarbons into low-permeability reservoirs, and (4) preservation of this petroleum system. Given these uncertainties and using known U.S. tight gas reservoirs as geologic and production analogs, a mean volume of 0.64 trillion cubic feet of gas was assessed in the basin-center tight-gas system that is postulated to exist in Mesozoic rocks of the upper Cook Inlet Basin. This assessment of Mesozoic basin-center tight gas does not include potential gas accumulations in Cenozoic low-permeability reservoirs.

Alaska↗
USGS1983

U.S. Geological Survey program of offshore resource and geoenvironmental studies, Atlantic-Gulf of Mexico region, from September 1, 1976, to December 31, 1978

Mineral and energy resources of the continental margins of the United States arc important to the Nation's commodity independence and to its balance of payments. These resources are being studied along the continental margins of the Atlantic Ocean and the Gulf of Mexico in keeping with the mission of the U.S. Geological Survey to survey the geologic structures, mineral resources, and products of the national domain.'(Organic Act of 1879). An essential corollary to these resource studies is the study of potential geologic hazards that may be associated with offshore resource exploration and exploitation. In cooperation with the U.S. Bureau of Land Management, the Geological Survey, through its Atlantic-Gulf of Mexico Marine Geology Program, carries out extensive research to evaluate hazards from sediment mobility, shallow gas, and slumping and to acquire information on the distribution and concentration of trace metals and biogenic and petroleum-derived hydrocarbons in sea-floor sediments. All these studies arc providing needed background information, including information on pollutant dispersal, on the nearshore, estuarine, and lacustrine areas that may be near pipeline and nuclear powerplant sites. Users of these data include the Congress, many Federal agencies, the coastal States, private industry, academia, and the concerned public. The results of the regional structural, stratigraphic, and resource studies carried out under the Atlantic-Gulf of Mexico Marine Geology Program have been used by the Geological Survey and the Bureau of Land Management to select areas for future leasing and to aid in the evaluation of tracts nominated for leasing. Resource studies have concentrated mostly on the Atlantic Outer Continental Shelf frontier areas. Geologic detailing of five major basins along the U.S. Atlantic margin, where sediments are as much as 14 km thick, have been revealed by 25,000 km of 24-and 48-channel common-depth-point seismic data, 187,000 km of acromagnetic data, and 39,000 km of gravity data, plus 10,000 samples and logs obtained from U.S. Geological Survey and industry drilling (for example, coreholes of the Atlantic Slope Program, Joint Oceanographic Institutions Deep Earth Sampling, Continental Offshore Stratigraphic Tests, and the Atlantic Margin Coring Program). A sedimentary section of Jurassic and Cretaceous age grades from terrigenous clastic rocks nearshore to carbonate rocks offshore; this section is part of an extensive buried bank-platform complex that could contain large reserves of natural gas and oil. The volume of sediment deposited offshore far exceeds the volume deposited onshore where extensive accumulations of oil, gas, and minerals have been found. Commercial exploratory drilling offshore thus far has been limited to the Baltimore Canyon Trough area off New Jersey, where at least two holes have found gas; leasing has taken place in the Southeast Georgia Embayment, where drilling was scheduled to begin in 1979, and is imminent in the Georges Bank area off New England. In addition, hydrogeologic and hydrochemical data obtained from the drilling studies have delineated freshwater-bearing submarine extensions of land aquifers that are important coastal ground-water resources. Hazards in the Georges Bank area include sand mobility associated with strong currents and storm-driven waves; high concentrations of suspended sediment in the water column that, when mixed with spilled oil, may sink to the bottom; and slumping along the upper slope. In the Baltimore Canyon, high sediment mobility accompanies major winter storms, and slumped material may cover as much as 20 percent of the upper slope. Potentially unstable slope areas are being studied in great detail to provide data on timing, triggering mechanisms, and rates of sediment movement. In the Southeast Georgia Embayment and Blake Plateau Basin, strong Gulf Stream flow poses a major problem to all offshore operations. In the Gulf o

Circular↗
USGS1979

Observations on the geology and petroleum potential of the Cold Bay-False Pass area, Alaska Peninsula

Upper Jurassic strata in the Black Hills area consist mainly of fossiliferous, tightly cemented, gently folded sandstone deposited in a shallow marine environment. Upper Cretaceous strata on Sanak Island are strongly deformed and show structural features of broken formations similar to those observed in the Franciscan assemblage of California. Rocks exposed on Sanak Island do not crop out on the peninsular mainland or on Unimak Island, and probably make up the acoustic and economic basement of nearby Sanak basin. Tertiary sedimentary rocks on the outermost part of the Alaska Peninsula consist of Oligocene, Miocene, and lower Pliocene volcaniclastic sandstone, siltstone, and conglomerate deposited in nonmarine and very shallow marine environments. Interbedded airfall and ash-flow tuff deposits indicate active volcanism during Oligocene time. Locally, Oligocene strata are intruded by quartz diorite plutons of probable Miocene age. Reservoir properties of Mesozoic and Tertiary rocks are generally poor due to alteration of chemically unstable volcanic rock fragments. Igneous intrusions have further reduced porosity and permeability by silicification of sandstone. Organic-rich source rocks for petroleum generation are not abundant in Neogene strata. Upper Jurassic rocks in the Black Hills area have total organic carbon contents of less than 0.5 percent. Deep sediment-filled basins on the Shumagin Shelf probably contain more source rocks than onshore correlatives, but reservoir quality is not likely to be better than in onshore outcrops. The absence of well-developed folds in most Tertiary rocks, both onshore and in nearby offshore basins, reduces the possibility of hydrocarbon entrapment in anticlines.

Open-File Report↗
USGS2013

Reconnaissance studies of potential petroleum source rocks in the Middle Jurassic Tuxedni Group near Red Glacier, eastern slope of Iliamna Volcano

Previous geological and organic geochemical studies have concluded that organic-rich marine shale in the Middle Jurassic Tuxedni Group is the principal source rock of oil and associated gas in Cook Inlet (Magoon and Anders, 1992; Magoon, 1994; Lillis and Stanley, 2011; LePain and others, 2012; LePain and others, submitted). During May 2009 helicopter-assisted field studies, 19 samples of dark-colored, fine-grained rocks were collected from exposures of the Red Glacier Formation of the Tuxedni Group near Red Glacier, about 70 km west of Ninilchik on the eastern flank of Iliamna Volcano (figs. 1 and 3). The rock samples were submitted to a commercial laboratory for analysis by Rock-Eval pyrolysis and to the U.S. Geological Survey organic geochemical laboratory in Denver, Colorado, for analysis of vitrinite reflectance. The results show that values of vitrinite reflectance (percent R o ) in our samples average about 2 percent, much higher than the oil window range of 0.6–1.3 percent (Johnsson and others, 1993). The high vitrinite reflectance values indicate that the rock samples experienced significant heating and furthermore suggest that these rocks may have generated oil and gas in the past but no longer have any hydrocarbon source potential. The high thermal maturity of the rock samples may have resulted from (1) the thermaleffects of igneous activity (including intrusion by igneous rocks), (2) deep burial beneath Jurassic, Cretaceous, and Tertiary strata that were subsequently removed by uplift and erosion, or (3) the combined effects of igneous activity and burial.

Alaska↗
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↗