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At least 217 records · Page 12Linked to original sources

USGS1985

Reconnaissance geologic map of part of the San Isidro Quadrangle, Baja California Sur, Mexico

The reconnaissance geology of part of the San Isidro 1:250,000-scale quadrangle of Baja California Sur, Mexico, was mapped in 1982, 1983, and 1984 to determine the age and stratigraphic relations of Tertiary sedimentary and volcanic rocks that comprise the bulk of the Sierra de la Giganta (southern Peninsular Ranges) and Pacific coastal plain. Focus was placed on determining the distribution and age of plateau-capping basalts, and on mapping the eastern limits of Paleogene marine strata and the western limits of the nonmarine Comondu Formation. The area was also examined for outcrops of pre-Tertiary crystalline rocks, however, none were found. Mapping was done on aerial photographs and transferred, where possible, to 1:50,000-scale topographic base maps. Areas with roads were field checked; however, in the northeast part of the map area, lack of roads prevented field checks. Previous geologic surveys of parts of the map area were made by horseback in the early 1920's; reports were published by Darton (1921), Heim (1922), and Beal (1948). Subsurface data from petroleum exploration and a geologic map were incorporated in a regional study by Mina (1957). The first radiometric ages of rocks from the map area were published by Gastil and others (1979). Recently determined radiometric ages and chemical analysis of volcanic rocks were reported by Hausback (1984) and by Sawlan and Smith (1984). Our study incorporates geologic mapping with age control based on new radiometric ages as well as paleontology, Flows and tuffs were dated by the K-Ar method. Fossil ages are based on diatom and mollusk assemblages.

Baja California Sur↗

USGS1980

Preliminary report on the geology of the continental slope adjacent to OCS Lease Sale 55, eastern Gulf of Alaska: Petroleum resource implications

Forty samples of Tertiary and Cretaceous outcrop or suspected outcrop were dredged along the 250-km-long northwest-trending continental slope between long 138°00' W. and 142°30' W. These samples, from water depths of 3,150 m to 200 m, combined with seismic reflection data, identify seven rock units in apparently normal stratigraphic position. From oldest to youngest they are: Unit A: Hard graywacke, argillite, and possible intrusive rocks of inferred Late Cretaceous age that crop out in the eastern part of the slope and probably underlie much of the Fairweather Ground. Unit B: At least 900 m of sandstone, conglomerate, shale, and subordinate basaltic volcanic rocks west of Yakutat Seavalley between 142° W. and 143° W. that is not dated but is probably of late Paleocene to early Eocene age. Unit C: 1,300 m of basaltic flow and pyroclastic rocks with associated clastic marine sedimentary rocks that makes up much of the rugged lower slope throughout the area. This sequence is largely, or entirely, of early Eocene age. Unit D: Up to 2,100 m of early and middle Eocene sandstone, conglomerate, siltstone, and tuffaceous organic-rich shale that partly overlies, and partly intertongues with, the volcanic unit. Unit E: 800 m of early to late Eocene and early Oligocene(?) organic-rich shale, tuffaceous shale, siltstone, and sandstone that partly intertongues with, and partly overlies units C and D. Unit F: 300+ m of siltstone, at least in part of late Oligocene age, that crops out locally along the upper slope where it unconformably overlies Unit E. Unit G: Up to 2,000 m of late Cenozoic (middle Miocene? and younger) clastic sedimentary rocks including abundant glaciomarine deposits that unconformably overlie all the older units. The early Tertiary sequence sampled on the continental slope differs strikingly in lithology and structure from coeval rocks exposed onshore or penetrated in unsuccessful exploratory wells on the adjacent mainland. Units B, D, and E include abundant source rocks that have undergone a thermal history resulting in local generation of hydrocarbons. Sandstones from Units D and E locally have secondary porosities up to 31 percent and permeabilities to 36 md. Seismic reflection data indicate that the sequence with the most favorable source and reservoir potential (Units B, D, E) dips northeastward beneath OCS Lease Sale 55 where it could be a favorable exploratory target if involved in suitable traps. Young anticlinal folds are not present, but other important traps are likely to include drape structures, horsts, and faults within the early Tertiary sequence and pinchouts, fault traps, or combination structural/stratigraphic traps along the northeastern margin of the early Tertiary basin.

Alaska↗

USGS2013

Geologic assessment of undiscovered oil and gas resources: Oligocene Frio and Anahuac Formations, United States Gulf of Mexico coastal plain and State waters

The Oligocene Frio and Anahuac Formations were assessed as part of the 2007 U.S. Geological Survey (USGS) assessment of Tertiary strata of the U.S. Gulf of Mexico Basin onshore and State waters. The Frio Formation, which consists of sand-rich fluvio-deltaic systems, has been one of the largest hydrocarbon producers from the Paleogene in the Gulf of Mexico. The Anahuac Formation, an extensive transgressive marine shale overlying the Frio Formation, contains deltaic and slope sandstones in Louisiana and Texas and carbonate rocks in the eastern Gulf of Mexico. In downdip areas of the Frio and Anahuac Formations, traps associated with faulted, rollover anticlines are common. Structural traps commonly occur in combination with stratigraphic traps. Faulted salt domes in the Frio and Anahuac Formations are present in the Houston embayment of Texas and in south Louisiana. In the Frio Formation, stratigraphic traps are found in fluvial, deltaic, barrier-bar, shelf, and strandplain systems. The USGS Tertiary Assessment Team defined a single, Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System (TPS) for the Gulf Coast basin, based on previous studies and geochemical analysis of oils in the Gulf Coast basin. The primary source rocks for oil and gas within Cenozoic petroleum systems, including Frio Formation reservoirs, in the northern, onshore Gulf Coastal region consist of coal and shale rich in organic matter within the Wilcox Group (Paleocene–Eocene), with some contributions from the Sparta Sand of the Claiborne Group (Eocene). The Jurassic Smackover Formation and Cretaceous Eagle Ford Formation also may have contributed substantial petroleum to Cenozoic reservoirs. Modeling studies of thermal maturity by the USGS Tertiary Assessment Team indicate that downdip portions of the basal Wilcox Group reached sufficient thermal maturity to generate hydrocarbons by early Eocene; this early maturation is the result of rapid sediment accumulation in the early Tertiary, combined with the reaction kinetic parameters used in the models. A number of studies indicate that the migration of oil and gas in the Cenozoic Gulf of Mexico basin is primarily vertical, occurring along abundant growth faults associated with sediment deposition or along faults associated with salt domes. The USGS Tertiary assessment team developed a geologic model based on recurring regional-scale structural and depositional features in Paleogene strata to define assessment units (AUs). Three general areas, as described in the model, are found in each of the Paleogene stratigraphic intervals assessed: “Stable Shelf,” “Expanded Fault,” and “Slope and Basin Floor” zones. On the basis of this model, three AUs for the Frio Formation were defined: (1) the Frio Stable Shelf Oil and Gas AU, containing reservoirs with a mean depth of about 4,800 feet in normally pressured intervals; (2) the Frio Expanded Fault Zone Oil and Gas AU, containing reservoirs with a mean depth of about 9,000 feet in primarily overpressured intervals; and (3) the Frio Slope and Basin Floor Gas AU, which currently has no production but has potential for deep gas resources (>15,000 feet). AUs also were defined for the Hackberry trend, which consists of a slope facies stratigraphically in the middle part of the Frio Formation, and the Anahuac Formation. The Frio Basin Margin AU, an assessment unit extending to the outcrop of the Frio (or basal Miocene), was not quantitatively assessed because of its low potential for production. Two proprietary, commercially available databases containing field and well production information were used in the assessment. Estimates of undiscovered resources for the five AUs were based on a total of 1,734 reservoirs and 586,500 wells producing from the Frio and Anahuac Formations. Estimated total mean values of technically recoverable, undiscovered resources are 172 million barrels of oil (MMBO), 9.4 trillion cubic feet of natural gas (TCFG), and 542 million barrels of natural gas liquids for all of the Frio and Anahuac AUs. Of the five units assessed, the Frio Slope and Basin Floor Gas AU has the greatest potential for undiscovered gas resources, having an estimated mean of 5.6 TCFG. The Hackberry Oil and Gas AU shows the second highest potential for gas of the five units assessed, having an estimated mean of 1.8 TCFG. The largest undiscovered, conventional crude oil resource was estimated for the Frio Slope and Basin Floor Gas AU; the estimated mean for oil in this AU is 110 MMBO.

Louisiana;Texas↗

USGS2009

Neogene gas total petroleum system – Neogene Nonassociated Gas Assessment Unit of the San Joaquin Basin Province

The Neogene Nonassociated Gas Assessment Unit (AU) of the Neogene Total Petroleum System consists of nonassociated gas accumulations in Pliocene marine and brackish-water sandstone located in the south and central San Joaquin Basin Province (Rudkin, 1968). Traps consist mainly of stratigraphic lenses in low-relief, elongate domes that trend northwest-southeast. Reservoir rocks typically occur as sands that pinch out at shallow depths (1,000 to 7,500 feet) within the Etchegoin and San Joaquin Formations. Map boundaries of the assessment unit are shown in figures 22.1 and 22.2; this assessment unit replaces the Pliocene Nonassociated Gas play 1001 (shown by purple line in fig. 22.1) considered by the U.S. Geological Survey (USGS) in its 1995 National Assessment (Beyer, 1996). The AU is drawn to include all existing fields containing nonassociated gas accumulations in the Pliocene to Pleistocene section, as was done in the 1995 assessment, but it was greatly expanded to include adjacent areas believed to contain similar source and reservoir rock relationships. Stratigraphically, the AU extends from the topographic surface to the base of the Etchegoin Formation (figs. 22.3 and 22.4). The boundaries of the AU explicitly exclude gas accumulations in Neogene rocks on the severely deformed west side of the basin and gas accumulations in underlying Miocene rocks; these resources, which primarily consist of a mixture of mostly thermogenic and some biogenic gas, are included in two other assessment units. Lillis and others (this volume, chapter 10) discuss the geochemical characteristics of biogenic gas in the San Joaquin Basin Province. Primary fields in the assessment unit are defined as those containing hydrocarbon resources greater than the USGS minimum threshold for assessment—3 billion cubic feet (BCF) of gas; secondary fields contain smaller volumes of gas but constitute a significant show of hydrocarbons. Although 12 fields meet the 3 BCF criterion for inclusion in the AU, only 5 fields were considered at the time of assessment.

California↗

USGS2018

California State Waters Map Series — Offshore of Gaviota, California

Introduction In 2007, the California Ocean Protection Council initiated the California Seafloor Mapping Program (CSMP), designed to create a comprehensive seafloor map of high-resolution bathymetry, marine benthic habitats, and geology within the 3-nautical-mile limit of California’s State Waters. The CSMP approach is to create highly detailed seafloor maps through collection, integration, interpretation, and visualization of swath sonar data, acoustic backscatter, seafloor video, seafloor photography, high-resolution seismic-reflection profiles, and bottom-sediment sampling data. The map products display seafloor morphology and character, identify potential marine benthic habitats, and illustrate both the surficial seafloor geology and shallow subsurface geology. The map area is in the southern part of the Western Transverse Ranges geologic province, which is north of the California Continental Borderland. Significant clockwise rotation—at least 90°—since the early Miocene has been proposed for the Western Transverse Ranges province, and the region is presently undergoing north-south shortening. The offshore part of the map area lies south of the steep south flank of the Santa Ynez M ountains . The crest of the range , which has a maximum elevation of about 760 m in the map area , lies about 4 km north of the shoreline. Gaviota is an unincorporated community that has a sparse population (less than 100), and the coastal zone is largely open space that is locally used for cattle grazing. The Union Pacific railroad tracks extend westward along the coast through the entire map area, within a few hundred meters of the shoreline. Highway 101 crosses the eastern part of the map area, also along the coast, then turns north (inland) and travels through Cañada de la Gaviota and Gaviota Pass en route to Buellton. Gaviota State Park lies at the mouth of Cañada de la Gaviota. West of Gaviota, the onland coastal zone is occupied by the Hollister Ranch, a privately owned, gated community that has no public access. The map area has a long history of petroleum exploration and development. Several offshore gas fields were discovered and were developed by onshore directional drilling in the 1950s and 1960s. Three offshore petroleum platforms were installed in adjacent federal waters in 1976 (platform “Honda”) and 1989 (platforms “Heritage” and “Harmony”). Local offshore and onshore operations were serviced for more than a century by the Gaviota marine terminal, which is currently being decommissioned and will be abandoned in an intended transition to public open space. The Offshore of Gaviota map area lies within the western Santa Barbara Channel region of the Southern California Bight, and it is somewhat protected from large Pacific swells from the north and northwest by Point Conception and from south and southwest swells by offshore islands and banks. Much of the shoreline in the map area is characterized by narrow beaches that have thin sediment cover, backed by low (10- to 20-m-high) cliffs that are capped by a narrow coastal terrace. Beaches are subject to wave erosion during winter storms, followed by gradual sediment recovery or accretion in the late spring, summer, and fall months during the gentler wave climate. The map area lies in the western-central part of the Santa Barbara littoral cell, which is characterized by west-to-east transport of sediment from Point Arguello on the northwest to Hueneme and Mugu Canyons on the southeast. Sediment supply to the western and central part of the littoral cell is mainly from relatively small coastal watersheds. In the map area, sediment sources include Cañada de la Gaviota (52 km 2 ), as well as Cañada de la Llegua, Arroyo el Bulito, Cañada de Santa Anita, Cañada de Alegria, Cañada del Agua Caliente, Cañada del Barro, Cañada del Leon, Cañada San Onofre, and many others. Coastal-watershed discharge and sediment load are highly variable, characterized by brief large events during major winter storms and long periods of low (or no) flow and minimal sediment load between storms. In recent (recorded) history, the majority of high-discharge, high-sediment-flux events have been associated with El Niño phases of the El Niño–Southern Oscillation climatic pattern. Shelf width in the Offshore of Gaviota map area ranges from about 4.3 to 4.7 km, and shelf slopes average about 1.0° to 1.2° but are highly variable because of the presence of the large Gaviota sediment bar. This bar extends southwestward for about 9 km from the mouth of Cañada de la Gaviota to the shelf break, is as wide as 2 km, and is by far the largest shore-attached sediment bar in the Santa Barbara Channel. The shelf is underlain by bedrock and variable amounts (0 to as much as 36 m in the Gaviota bar) of upper Quaternary sediments deposited as sea level fluctuated in the late Pleistocene. The trend of the shelf break changes from about 276° to 236° azimuth over a distance of about 12 km, and it ranges in depth from about 91 m to as shallow as 62 to 73 m where significant shelf-break and upper-slope failure and landsliding has apparently occurred. The shelf break in the western part of the map area is notably embayed by the heads of three large (150- to 300-m-wide) channels that have been referred to as “the Gaviota Canyons” or as “Drake Canyon,” “Sacate Canyon,” and “Alegria Canyon.” Seafloor habitats in the broad Santa Barbara Channel region consist of significant amounts of soft, unconsolidated sediment interspersed with isolated areas of rocky habitat that support kelp-forest communities in the nearshore and rocky-reef communities in deeper water. The potential marine benthic habitat types mapped in the Offshore of Gaviota map area are directly related to its Quaternary geologic history, geomorphology, and active sedimentary processes. These potential habitats lie primarily within the Shelf (continental shelf) but also partly within the Flank (basin flank or continental slope) megahabitats. The fairly homogeneous seafloor of sediment and low-relief bedrock provides characteristic habitat for rockfish, groundfish, crabs, shrimp, and other marine benthic organisms. Several areas of smooth sediment form nearshore terraces that have relatively steep, smooth fronts, which may be attractive to groundfish. Below the steep shelf break, soft, unconsolidated sediment is interrupted by the heads of several submarine canyons and rills, some bedrock exposures, and small carbonate mounds associated with asphalt mounds and pockmarks, also good potential habitat for rockfish. The map area includes the relatively small (5.2 km 2 ) Kashtayit State Marine Conservation Area, which largely occupies the inner part of the Gaviota sediment bar.

California↗

USGS1983

Geology of the Volga-Ural petroleum province and detailed description of the Ramashkino and Arlan oil fields

The Volga-Ural petroleum province is in general coincident with the Volga-Ural regional high, a broad upwarp of the east-central part of the Russian (East European) platform. The central part of the province is occupied by the Tatar arch, which contains the major share of the oil fields of the province. The Perm-Bashkir arch forms the northeastern part of the regional high, and the Zhigulevsko-Orenburg arch makes up the southern part. These arches are separated from one another by elongate downwarps. The platform cover overlies an Archean crystalline basement and consists of seven main sedimentation cycles as follows: 1) Riphean (lower Bavly) continental sandstone, shale, and conglomerate beds from 500 to 5,000 m thick deposited in aulacogens. 2) Vendian (upper Bavly) continental and marine shale and sandstone up to 3,000 m thick. 3) Middle Devonian-Tournaisian transgressive deposits, which are sandstone, siltstone, and shale in the lower part and carbonates with abundant reefs in the upper; thickness is 300-1,000 m. In the upper carbonate part is the Kamsko-Kinel trough system, which consists of narrow interconnected deep-water troughs. 4) The Visean-Namurian-Bashkirian cycle, which began with deposition of Visean clastics that draped over reefs of the previous cycle and filled in an erosional relief that had formed in some places on the sediments of the previous cycle. The Visean clastics are overlain by marine carbonates. Thickness of the cycle is 50-800 m. 5) Early Moscovian-Early Permian terrigenous clastic deposits and marine carbonate beds 1,000-3,000 m thick. 6) The late Early Permian-Late Permian cycle, which reflects maximum growth of the Ural Mountains and associated Ural foredeep. Evaporites were first deposited, then marine limestones and dolomites, which intertongue eastward with clastic sediments from the Ural Mountains. 7) Continental redbeds of Triassic age and mixed continental and marine elastic beds of Jurassic and Cretaceous age, which were deposited on the southern, southwestern, and northern margins of the Russian platform; they are generally absent in the Volga-Ural province, however. The Volga-Ural oil and gas basin is a single artesian system that contains seven aquifers separated by seals. The areas of greatest hydraulic head are in the eastern parts of the basin near areas where the aquifers crop out on the western slopes of the Ural Mountains. The Peri-Caspian basin is the principal drainage area of the artesian system. Approximately 600 oil and gas fields and 2,000 pools have been found in the Volga-Ural province. Nine productive sequences are recognized as follows: 1) Upper Proterozoic (Bavly beds), which are promising but not yet commercial. 2) Clastic Devonian, which contains the major reserves and includes the main pays of the super-giant Romashkino field. 3) Carbonate Upper Devonian and lowermost Carboniferous, which is one of the main reef-bearing intervals. 4) Visean (Lower Carboniferous) elastics, which are the main pays in the super-giant Arian field. 5) Carbonate Lower and Middle Carboniferous. 6) Clastic Middle Carboniferous Moscovian. 7) Carbonate Middle and Upper Carboniferous. 8) Carbonate-evaporite Lower Permian, which contains the major gas reserves and the lower part of the Melekess tar deposits. 9) Clastic-carbonate Upper Permian, which contains the major part of the Melekess tar deposits. The Volga-Ural province is divided into several productive regions on a basis of differences in structure, distribution of reservoir and source-rock facies, and general composition of the petroleum accumulations. These regions are the Tatar arch, Birsk saddle, Upper Kama depression, Perm-Bashkir arch, Ufa-Orenburg monocline, Melekess-Sernovodsko-Abdulino basin, Zhligulevsko-Orenburg arch, Ural foredeep, and north borders of the Peri-Casplan depression. Exploration activity has declined in recent years; however, interest remains high in several parts of the province, particula

Open-File Report↗

USGS1952

Stratigraphy and paleontology of the Noatak and associated formations, Brooks Range, Alaska

A think complex sequence of olastic rocks, formerly named the Noatak formation, underlies the Lisburns formation (Mississippian) in the Brooks Range, northern Alaska. Five formations have been recognized as a result of of recent investigations by the author and other geologists of the Navy Oil Unit, U.S. Geological Survey. In the western Brooks Range, the three formations present below the Lisburns formation are: Utukok formation (Upper Touranisian to Lower Visean), Montak formation (restricted) (Upper Devonian to Lower Tournaisian (?)) and Hunt Fork (?) formation (Upper Devonian). In the central Brooks Range the Kayak formation (Lower to Upper Tournaisian), Kanayut formation (Upper Devonian to Lower Tournaisian (?)), and Hunt Fork formation (Upper Devonian) lie below the Lisburns formation. Lithologic and faunal characteristics of these sedimentary units reveal the regional pattern of sedimentation and suggest specific paleoecologic environments. The chart conglomerates in the Kanayut and Noatuk formations are thought to have formed in a belt characterized by fluctuating marine and nonmarine conditions, the chart source being a mid-Devonian ragolith. Analysis of formulas suggest certain correlations with the European, Siberian, and western Cordilleran sections. Described faunas of the Utukok and Kayak formations include 40 braciopod species and varieties, 9 echinodera species, 2 bryzoan species, 8 molluscan species, and 1 tribute species, of which 13 are new.

Alaska↗

USGS1983

Petroleum geology and resources of the Volga-Ural province, U.S.S.R.

The Volga-Ural petroleum province is, in general, coincident with the Volga-Ural regional high, a broad upwarp of the east-central part of the Russian (East European) Platform. The central part of the province is occupied by the Tatar arch, which contains the major share of the oilfields of the province. The Komi-Perm arch forms the northeastern part of the regional high, and the Zhigulevsko-Pugachev and Orenburg arches make up the southern part. These arches are separated from one another by elongate downwarps. The platform cover overlies an Archean crystalline basement and consists of seven main sedimentation cycles. (1) Riphean (lower Bavly) continental sandstone, shale, and conglomerate beds, from 500 to 5,000 m thick, were deposited in aulacogens. (2) Vendian (upper Bavly) continental and marine shale and sandstone are up to 3,000 m thick. (3) Middle Devonian-Tournaisian transgressive deposits, which are sandstone, siltstone, and shale in the lower part and carbonates and abundant reefs in the upper part, range from 300 to 1,000 m in thickness. The upper carbonate part includes the Kamsko-Kinel trough system, which consists of narrow, interconnected, deepwater troughs. (4) The Visean-Namurian-Bashkirian cycle began with deposition of Visean clastic deposits, which draped over reefs of the previous cycle and filled in an erosional relief that had formed in some places on the sediments of the previous cycle. The Visean clastic deposits are overlain by marine carbonate beds. The cycle is from 50 to 800 m thick. (5) The lower Moscovian-Lower Permian cycle consists of 1,000 to 3,000 m of terrigenous clastic deposits and marine carbonate beds. (6) The upper Lower Permian-Upper Permian cycle reflects the maximum growth of the Ural Mountains and the associated Ural foredeep. Evaporite deposits were first laid down, followed by marine limestones and dolomites, which intertongue eastward with clastic sediments from the Ural Mountains. (7) Continental red beds of Triassic age and mixed continental and marine clastic beds of Jurassic and Cretaceous age were deposited on the western, southwestern, and northern margins of the Russian Platform; they are generally absent in the Volga-Ural province, however. Approximately 600 oilfields and gasfields and 2,000 pools have been found in the Volga-Ural province. Nine productive sequences are recognized; these are, in general, the same as the sedimentation cycles, although some subdivisions have been added. The clastic section of Middle and early Late Devonian age contains the major recoverable oil accumulations, including the supergiant Romashkino field. Cumulative production to 1980 is estimated at 30 to 35 billion barrels of oil equivalent, identified reserves at about 10 billion barrels of oil equivalent, and undiscovered resources at about 7 billion barrels of oil equivalent. Identified reserves of natural gas are estimated at 100 trillion cubic feet and undiscovered resources at 63 trillion cubic feet.

Circular↗

USGS1992

Geology of the Eel River basin and adjacent region: Implications for late Cenozoic tectonics of the southern Cascadia subduction zone and Mendocino triple junction

Two upper Cenozoic depositional sequences of principally marine strata about 4000m thick overlie accreted basement terranes of the Central and Coastal belts of the Franciscan Complex in the onshore-offshore Eel River basin of northwestern California. The older depositional sequence is early to middle Miocene in age and represents slope basin and slope-blanket deposition, whereas the younger sequence, late Miocene to middle Pleistocene in age, consists largely of forearc basin deposits. -from Author

California↗

USGS2002

Undiscovered oil and gas resources of Lower Silurian Qusaiba-Paleozoic total petroleum systems, Arabian Peninsula

The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered conventional oil and gas potential of 128 of the world’s petroleum provinces (U.S. Geological Survey World Energy Assessment Team, 2000). In each province, the USGS defined Total Petroleum Systems, and Assessment Units in each Total Petroleum System, and then quantitatively estimated the undiscovered conventional oil and gas resources. Of the eight global regions studied by the USGS, the Arabian Peninsula portion of the Middle East region was estimated to contain the greatest volumes of undiscovered oil and gas. The Lower Silurian Qusaiba Member of the Qalibah Formation is the source rock for some of the most important Total Petroleum Systems of the Middle East region. For example, the sources of the gas in the supergiant North field of Qatar and Iran and recent giant light oil discoveries in central Saudi Arabia were largely organic-rich, Qusaiba marine mudstones.

Fact Sheet↗

USGS2006

Chapter 2: 2003 Geologic Assessment of Undiscovered Conventional Oil and Gas Resources in the Upper Cretaceous Navarro and Taylor Groups, Western Gulf Province, Texas

The Upper Cretaceous Navarro and Taylor Groups in the western part of the Western Gulf Province were assessed for undiscovered oil and gas resources in 2003. The area is part of the Smackover-Austin-Eagle Ford Composite Total Petroleum System. The rocks consist of, from youngest to oldest, the Escondido and Olmos Formations of the Navarro Group and the San Miguel Formation and the Anacacho Limestone of the Taylor Group (as well as the undivided Navarro Group and Taylor Group). Some units of the underlying Austin Group, including the 'Dale Limestone' (a term of local usage that describes a subsurface unit), were also part of the assessment in some areas. Within the total petroleum system, the primary source rocks comprise laminated carbonate mudstones and marine shales of the Upper Jurassic Smackover Formation, mixed carbonate and bioclastic deposits of the Upper Cretaceous Eagle Ford Group, and shelf carbonates of the Upper Cretaceous Austin Group. Possible secondary source rocks comprise the Upper Jurassic Bossier Shale and overlying shales within the Upper Jurassic to Lower Cretaceous Cotton Valley Group, Lower Cretaceous marine rocks, and the Upper Cretaceous Taylor Group. Oil and gas were generated in the total petroleum system at different times because of variations in depth of burial, geothermal gradient, lithology, and organic-matter composition. A burial-history reconstruction, based on data from one well in the eastern part of the study area (Jasper County, Tex.), indicated that (1) the Smackover generated oil from about 117 to 103 million years ago (Ma) and generated gas from about 52 to 41 Ma and (2) the Austin and Eagle Ford Groups generated oil from about 42 to 28 Ma and generated gas from about 14 Ma to the present. From the source rocks, oil and gas migrated upsection and updip along a pervasive system of faults and fractures as well as along bedding planes and within sandstone units. Types of traps include stratigraphic pinchouts, folds, faulted folds, and combinations of these. Seals consist of interbedded shales and mudstones and diagenetic cementation. The area assessed is divided into five assessment units (AUs): (1) Travis Volcanic Mounds Oil (AU 50470201), (2) Uvalde Volcanic Mounds Gas and Oil (AU 50470202), (3) Navarro-Taylor Updip Oil and Gas (AU 50470203), (4) Navarro-Taylor Downdip Gas and Oil (AU 50470204), and (5) Navarro-Taylor Slope-Basin Gas (AU 50470205). Total estimated mean undiscovered conventional resources in the five assessment units combined are 33.22 million barrels of oil, 1,682.80 billion cubic feet of natural gas, and 34.26 million barrels of natural gas liquids.

Data Series↗

USGS2013

Characterization of the Hosgri Fault Zone and adjacent structures in the offshore Santa Maria Basin, south-central California

The Hosgri Fault Zone trends subparallel to the south-central California coast for 110 km from north of Point Estero to south of Purisima Point and forms the eastern margin of the present offshore Santa Maria Basin. Knowledge of the attributes of the Hosgri Fault Zone is important for petroleum development, seismic engineering, and environmental planning in the region. Because it lies offshore along its entire reach, our characterizations of the Hosgri Fault Zone and adjacent structures are primarily based on the analysis of over 10,000 km of common-depth-point marine seismic reflection data collected from a 5,000-km2 area of the central and eastern parts of the offshore Santa Maria Basin. We describe and illustrate the along-strike and downdip geometry of the Hosgri Fault Zone over its entire length and provide examples of interpreted seismic reflection records and a map of the structural trends of the fault zone and adjacent structures in the eastern offshore Santa Maria Basin. The seismic data are integrated with offshore well and seafloor geologic data to describe the age and seismic appearance of offshore geologic units and marker horizons. We develop a basin-wide seismic velocity model for depth conversions and map three major unconformities along the eastern offshore Santa Maria Basin. Accompanying plates include maps that are also presented as figures in the report. Appendix A provides microfossil data from selected wells and appendix B includes uninterpreted copies of the annotated seismic record sections illustrated in the chapter. Features of the Hosgri Fault Zone documented in this investigation are suggestive of both lateral and reverse slip. Characteristics indicative of lateral slip include (1) the linear to curvilinear character of the mapped trace of the fault zone, (2) changes in structural trend along and across the fault zone that diminish in magnitude toward the ends of the fault zone, (3) localized compressional and extensional structures characteristic of constraining and releasing bends and stepovers, (4) changes in the sense and magnitude of vertical separation along strike within the fault zone, and (5) changes in downdip geometry between the major traces and segments of the fault zone. Characteristics indicative of reverse slip include (1) reverse fault geometries that occur across major strands of the fault zone and (2) fault-bend folds and localized thrust faults that occur along the northern and southern reaches of the fault. Analyses of high-resolution, subbottom profiler and side-scan sonar records indicate localized Holocene activity along most of the extent of the fault zone. Collectively, these features are the basis of our characterization of the Hosgri Fault Zone as an active, 110-km-long, convergent right-oblique slip (transpressional) fault with identified northern and southern terminations. This interpretation is consistent with recently published analyses of onshore geologic data, regional tectonic kinematic models, and instrumental seismicity.

California↗

USGS2019

Geology and assessment of undiscovered oil and gas resources of the East Greenland Rift Basins Province, 2008

In 2007 the U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable oil and gas resources in the East Greenland Rift Basins Province of Northeast Greenland. The province was selected as the prototype for the U.S. Geological Survey Circum-Arctic Resource Appraisal (CARA). In collaboration with the Geological Survey of Denmark and Greenland (GEUS), the province was subdivided into nine geologically distinctive areas. Seven of these were defined as Assessment Units (AUs), of which five were quantitatively assessed. These are: North Danmarkshavn Salt Basin, South Danmarkshavn Basin, Thetis Basin, Northeast Greenland Volcanic Province, and Liverpool Land Basin. Jameson Land Basin and the Jameson Land Basin Subvolcanic Extension were defined as AUs but were not quantitatively assessed. Onshore studies by GEUS and other organizations suggest that at least four stratigraphic intervals may contain potential source rocks for petroleum. The geological history of related areas in western Norway and burial history modeling suggest that Upper Jurassic strata are most likely to contain petroleum source rocks. A wide variety of possible trapping mechanisms are expected within the province. Potential traps in the North Danmarkshavn Salt Basin AU are dominated by structures formed through salt tectonics; those in the South Danmarkshavn Basin and the Northeast Greenland Volcanic Province are characterized by extensional structures and by stratigraphic traps in submarine fan complexes. Prospective inversion structures of Tertiary age are present along the western margin of South Danmarkshavn Basin AU, and the large horst block structures that separate the Danmarkshavn and Thetis Basins may provide numerous opportunities for traps in fault blocks and along various facies-related permeability barriers. Possible reservoirs include shallow marine to nonmarine sandstones of Middle Jurassic age, sandstones in Upper Jurassic synrift deposits, Cretaceous sandstones in submarine fan complexes, sandstones in Paleogene progradational sequences, and in Upper Carboniferous to Lower Permian warm-water carbonate sequences, especially in northern Danmarkshavn Basin. Marine shales are expected to provide the main sealing lithologies in most AUs. Most of the undiscovered oil, gas, and natural gas liquids are likely to be in the offshore areas of the province and are inferred to belong to an Upper Jurassic Composite Total Petroleum System. The USGS estimated that the East Greenland Rift Basins Province contains approximately (mean) 31,400 million barrels oil equivalent (MMBOE) of oil, natural gas, and natural gas liquids. Of the five assessed AUs, North Danmarkshavn Salt Basin and the South Danmarkshavn Basin are estimated to contain most of the undiscovered petroleum.

Professional Paper↗

USGS2011

An evaluation of the science needs to inform decisions on Outer Continental Shelf energy development in the Chukchi and Beaufort Seas, Alaska

The U. S. Geological Survey (USGS) was asked to conduct an initial, independent evaluation of the science needs that would inform the Administration's consideration of the right places and the right ways in which to develop oil and gas resources in the Arctic Outer Continental Shelf (OCS), particularly focused on the Beaufort and Chukchi Seas. Oil and gas potential is significant in Arctic Alaska. Beyond petroleum potential, this region supports unique fish and wildlife resources and ecosystems, and indigenous people who rely on these resources for subsistence. This report summarizes key existing scientific information and provides initial guidance of what new and (or) continued research could inform decision making. This report is presented in a series of topical chapters and various appendixes each written by a subset of the USGS OCS Team based on their areas of expertise. Three chapters (Chapters 2, 3, and 4) provide foundational information on geology; ecology and subsistence; and climate settings important to understanding the conditions pertinent to development in the Arctic OCS. These chapters are followed by three chapters that examine the scientific understanding, science gaps, and science sufficiency questions regarding oil-spill risk, response, and impact (Chapter 5), marine mammals and anthropogenic noise (Chapter 6), and cumulative impacts (Chapter 7). Lessons learned from the 1989 Exxon Valdez Oil Spill are included to identify valuable "pre-positioned" science and scientific approaches to improved response and reduced uncertainty in damage assessment and restoration efforts (appendix D). An appendix on Structured Decision Making (appendix C) is included to illustrate the value of such tools that go beyond, but incorporate, science in looking at what can/should be done about policy and implementation of Arctic development. The report provides a series of findings and recommendations for consideration developed during the independent examination of science gaps and sufficiency. These recommendations are important for understanding what the USGS discovered in the course of this study and to help inform and improve decision making.

Circular↗

USGS2003

Brookian structural plays in the National Petroleum Reserve, Alaska

As part of the U.S. Geological Survey assessment of undiscovered oil and gas resources in the National Petroleum Reserve-Alaska (NPRA), two structural plays were assessed in thrust-faulted and folded Upper Cretaceous rocks of the Brookian megasequence. These are the Brookian Topset Structural Play and the Torok Structural Play, located in the Brooks Range foothills and the southern part of the coastal plain, within the Tertiary-age frontal part of the Jurassic to Tertiary Brooks Range orogenic belt. A new regional structural interpretation, developed through regional seismic analyses, reconnaissance field investigations, and new thermal constraints, guided the geologic evaluation and risking of these plays. Volumetric parameters were derived from seismic reflection data, well data and oil and gas field analogs. The fundamental elements of the Brookian Topset Structural Play, exemplified by the undeveloped Umiat oil field, include: (1) reservoirs in Nanushuk Group and uppermost Torok Formation shallow-marine to nonmarine sandstones draped over anticlines caused by structural thickening in underlying Torok mudstones; (2) seals provided by overlying shale drapes in the Nanushuk, and locally by thrust faults; (3) Torok, gamma-ray-zone (GRZ) or pebble shale source rocks; (4) remigration of hydrocarbons from early formed (Late Cretaceous) stratigraphic traps disrupted by 60 Ma thrusting, into newly formed structural traps. The 60 Ma thrusting was probably accompanied by new generation and migration of natural gas resulting from late structural thickening and tectonic loading. Subsurface data from the Umiat field and other seismic reflection data within the play area indicate that the structural traps are commonly compartmentalized by thrust faults. The fundamental elements of the Torok Structural Play, exemplified by the undeveloped East Kurupa gas accumulation just south of NPRA, include: (1) reservoirs in lower Torok Formation basin-floor sandstones, and perhaps in small sandstone bodies intercalated with middle to upper Torok mudstones; (2) structural traps provided by folded sandstone bodies above thrust faults within a pervasively deformed passive-roof duplex beneath the foothills and a less-strongly deformed domain to the north; (3) seals provided by Torok mudstone, both stratigraphically above the sandstone bodies and smeared along bounding thrust faults; (4) Torok, GRZ, pebble shale, or Kingak Shale source rocks; (5) a migration and charging scenario similar to that of the Brookian Topset Structural Play. According to our estimates, the Brookian Topset Structural Play contains 137 million barrels of technically recoverable oil and 10.6 trillion cubic feet (TCF) of technically recoverable, non-associated natural gas, with both values representing the mean estimate (expected value). The Torok Structural Play contains about 35 million barrels of technically recoverable oil and 17.9 TCF of technically recoverable, nonassociated natural gas.

Open-File Report↗

USGS1980

Structural framework, stratigraphy, and petroleum geology of the area of oil and gas lease Sale No. 49 on the U.S. Atlantic continental shelf and slope

On September 23, 1977, the U.S. Department of the Interior announced the tentative selection of 136 tracts for Sale No. 49 of oil and gas leases in the Baltimore Canyon Trough on the U.S. Atlantic Continental Shelf and Slope. This report summarizes the geology and petroleum potential of the area. The Baltimore Canyon Trough is an elongate, seaward-opening sedimentary basin filled by as much as 14 km of Mesozoic and Cenozoic sedimentary rocks. The basin first formed under the New Jersey shelf and gradually spread west and south as the area subsided after the rifting that formed the Atlantic basin. Rocks of the Triassic and Jurassic Systems together are more than 8 km thick in a depocenter areally restricted to the northern part of the trough. Basal Jurassic rocks are apparently nonmarine sedimentary rocks bedded with evaporite deposits. Direct evidence that some salt is in the basal Jurassic section comes from the Houston Oil and Minerals 676-1 well, which penetrated salt at a depth of about 3.8 km. During the Middle and Late Jurassic, more open marine conditions prevailed than in the Early Jurassic, and carbonate banks and reefs formed discontinuously along the seaward side of the shelf. Sand flats likely occupied the central part of the shelf, and these probably graded shoreward into nonmarine red beds that accumulated in a bordering coastal plain. Thick nonmarine sands and silty shales of Late Jurassic age were deposited in what is now the nearshore and midshelf area. These sedimentary rocks probably grade into thick marine carbonate rocks near the present shelf edge. During the Cretaceous, less sediment accumulated (about 4 km) than during the Jurassic, and most was deposited during Early Cretaceous time. The Cretaceous units show two main trends through time-a diminishing rate of sediment accumulation and an increase in marine character of sediments. During the Middle and Late Cretaceous, calcareous sand and mud filled the basin, buried the shelf-edge reefs and later spilled across the reefs into the oceanic basin as worldwide sea level reached a maximum. Cenozoic deposits are spread over the present shelf and adjacent Coastal Plain in overlapping sheets of marine and nonmarine sediment. The maximum thickness (1.5 km) is along the outer part of the present shelf. Major tectonic deformation in the Baltimore Canyon Trough area appears to have terminated near the end of the Early Cretaceous, when at least one large mafic intrusion (Great Stone dome) was emplaced. Upper Cretaceous sedimentary rocks are arched above older uplifted fault blocks near the shelf edge; this arching may be the result of draping due to differential compaction or, perhaps, minor movement of the fault blocks during Late Cretaceous time. The dominance of terrestrial over marine-derived organic matter in sediment samples from the COST No. B-2 well indicates that economic amounts of liquid petroleum hydrocarbons were probably not generated in the area but suggests a high potential for generation of wet or dry gas. Supporting evidence for the presence of natural-gas deposits on the slope comes from AMCOR 6021, the upper 305 m of which penetrated sediments that contained methane, ethane, and propane. Texaco, Inc., has announced that its 598-1 well yielded nearly 479,000 m s of natural gas per day from two zones during early testing. Further indication of possible gas deposits comes from analyzing the amplitude (bright spots) of seismic data. Geochemical studies of the COST No. B-2 well have shown that the shelf area of the Baltimore Canyon Trough has a relatively low geothermal gradient today and that it apparently has had a gradient as low or even lower throughout the Cretaceous to Holocene. A controversy exists concerning the maturity of the basal sediments penetrated by the COST No. B-2 well. Although significant amounts of gaseous hydrocarbons may have been generated, large amounts of liquid petroleum hydrocarbons probably hav

Circular↗

USGS1972

Acoustic-reflection profiles, Bay of Campeche: International Decade of Ocean Exploration, U.S. Geological Survey, Leg 1, 1971 cruise, UNITEDGEO I

Introduction As part of a cooperative marine research program designated the International Decade of Ocean Exploration (IDOE), the United States Geological Survey is participating in an investigation of the geologic framework and resource potential of continental margins and small ocean basins in the Gulf of Mexico, Caribbean Sea, and west African continental shelf areas. These studies are funded through the National Science Foundation. Acoustic-reflection profiles of Leg 1, described in this report concern mainly a 200 X 250 kilometer project area in the Bay of Campeche in the southwestern part of the Gulf of Mexico. The cruise leg began at Corpus Christi, Texas, and ended at Veracruz, Mexico. Other geophysical records collected during the cruise include magnetometry, gravimetry, and bathymetry. Visiting scientists from the Institute of Geophysics of the National University of Mexico, the Oceanographic Commission of the Mexican Navy, and the Mexican Institute of Petroleum joined the research vessel UNITEDGEO I throughout the cruise in the Bay of Campeche. The cruise offered an excellent opportunity for scientific interchange between investigators from Mexico and the United States and permitted collaboration in the instrumentation, operational techniques, and interpretation of acoustic-reflection records aboard the research vessel.

Bay Of Campeche;Gulf Of Mexico↗

USGS2014

Geology and total petroleum systems of the Paradox Basin, Utah, Colorado, New Mexico, and Arizona

The geological model for the development of the Total Petroleum Systems (TPSs) within the Paradox Basin formed the foundation of the recent U.S. Geological Survey assessment of undiscovered, technically recoverable resources in the basin. Five TPSs were defined, of which three have known production and two are hypothetical. These TPSs are based on geologic elements of the basin and the potential development of Precambrian, Devonian, Pennsylvanian, Permian-Mississippian, and Cretaceous source rock intervals. The most studied source intervals are the Pennsylvanian black shales that were deposited during relative high stands in an otherwise evaporitic basin. These black shales are the source for most of the discovered hydrocarbons in the Paradox Basin. A second oil type can be traced to either a Mississippian or Permian source rock to the west, and therefore requires long-distance migration to explain its presence in the basin. Upper Cretaceous continental to nearshore-marine sandstones are interbedded with coal beds that have recognized coalbed methane potential. Precambrian and Devonian TPSs are considered hypothetical, as both are known to have organic-rich intervals, but no discovered hydrocarbons have been definitively typed back to either of these units.

Arizona, Colorado, New Mexico, Utah↗