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At least 937 records · Page 52Linked to original sources
USGS1996

Geology of the Harpers Ferry Quadrangle, Virginia, Maryland, and West Virginia

The Harpers Ferry quadrangle covers a portion of the northeast-plunging Blue Ridge-South Mountain anticlinorium, a west-verging allochthonous fold complex of the late Paleozoic Alleghanian orogeny. The core of the anticlinorium consists of high-grade paragneisses and granitic gneisses that are related to the Grenville orogeny. These rocks are intruded by Late Proterozoic metadiabase and metarhyolite dikes and are unconformably overlain by Late Proterozoic metasedimentary rocks of the Swift Run Formation and metavolcanic rocks of the Catoctin Formation, which accumulated during continental rifting of Laurentia (native North America) that resulted in the opening of the Iapetus Ocean. Lower Cambrian metasedimentary rocks of the Loudoun, Weverton, Harpers, and Antietam Formations and carbonate rocks of the Tomstown Formation were deposited in the rift-to-drift transition as the early Paleozoic passive continental margin evolved. The Short Hill fault is an early Paleozoic normal fault that was contractionally reactivated as a thrust fault and folded in the late Paleozoic. The Keedysville detachment is a folded thrust fault at the contact of the Antietam and Tomstown Formations. Late Paleozoic shear zones and thrust faults are common. These rocks were deformed and metamorphosed to greenschist-facies during the formation of the anticlinorium. The Alleghanian deformation was accompanied by a main fold phase and a regional penetrative axial plane cleavage, which was followed by a minor fold phase with crenulation cleavage. Early Jurassic diabase dikes transected the anticlinorium during Mesozoic continental rifting that resulted in the opening of the Atlantic Ocean. Cenozoic deposits that overlie the bedrock include bedrock landslides, terraces, colluvium, and alluvium.

Bulletin↗
USGS1995

Geologic, geochemical, and isotopic studies of a carbonate- and siliciclastic-hosted Pb-Zn deposit at Lion Hill, Vermont

Zn-, Pb-, Cu-, and Fe-bearing rocks of the Lion Hill area in western Vermont formed during the Early Cambrian by syngenetic sedimentary-exhalative and diagenetic replacement processes. Sphalerite, galena, chalcopyrite, pyrite, and, locally, magnetite form stratabound and broadly stratiform lenticular zones, -300 meters long and 25-50 meters thick, which are uneconomic at the present time. The lenses are structurally disrupted and metamorphosed to greenschist facies, probably due to the Taconic orogeny. Textural evidence suggests that mineralizing fluids permeated the sediments prior to lithification and that a dilatant fracture zone, possibly a feeder zone, contains some of the discordant veins at Lion Hill. The veins may have formed when the sediments were in a plastic, semiconsolidated state. The association of layered iron formation containing base-metal sulfide minerals provides possible lithologic evidence for syngenetic mineralization by submarine exhalative activity. Sand bars and tidal channels present in the sedimentary section could have acted as permeable pathways for movement of mineralizing fluids. The complex interlayering in the sedimentary sequence of carbonate and siliciclastic rock types having widely varying permeabilities created numerous fluid traps. Homogenization temperatures of primary and secondary inclusions in vein sphalerite range from 152°C to 196°C; salinities range from 11.5 to 14.0 equivalent weight percent NaCl. δ 34 S values of sulfides from Lion Hill vary from -25.9 to +10.0 per mil, and fall within the expected range for sulfide produced from bacteriogenic reduction of sulfate with δ 34 S values of 25 to 30 per mil. In addition, some pyrite probably formed from sulfate in trapped pore fluid that resulted in heavier isotopic values characteristic of more closed-system behavior. Three sphalerite samples that have heavier sulfur isotopic values may reflect a change in the source of sulfur during a later episode of mineralization, perhaps a change to a deep-seated source. Lead isotopic compositions of galenas from mineralized zones at Lion Hill range from 18.351 to 18.632 for 206 Pb/ 204 Pb, from 15.546 to 15.618 for 207 Pb/ 204 Pb, and from 38.126 to 38.496 for 208 Pb/ 204 Pb. The lead isotopic compositions of galena from Lion Hill and fluid inclusion and sulfur isotopic values for the Lion Hill sulfides are more like those of Pb-Zn-Ag deposits of Ireland than those of MVT or Appalachian-type Zn deposits. The prospect of an Irish-type sedimentary-exhalative origin for stratabound Pb-Zn deposits of the Paleozoic shelf of North America is of considerable importance to understanding the timing of mineralization relative to platform evolution and for evaluating the mineral resource potential of the region. Our study of the Lion Hill deposit indicates a potential for Irish-type Pb-Zn deposits in platform rocks of western Vermont; however, at Lion Hill they contain enrichments of Pb, Zn, and Cu rather than a Pb, Zn, and Ag association.

Vermont↗
USGS2003

Well-Production Data and Gas-Reservoir Heterogeneity -- Reserve Growth Applications

Oil and gas well production parameters, including peakmonthly production (PMP), peak-consecutive-twelve month production (PYP), and cumulative production (CP), are tested as tools to quantify and understand the heterogeneity of reservoirs in fields where current monthly production is 10 percent or less of PMP. Variation coefficients, defined as VC= (F5-F95)/F50, where F5, F95, and F50 are the 5th, 95th, and 50th (median) fractiles of a probability distribution, are calculated for peak and cumulative production and examined with respect to internal consistency, type of production parameter, conventional versus unconventional accumulations, and reservoir depth. Well-production data for this study were compiled for 69 oil and gas fields in the Lower Pennsylvanian Morrow Formation of the Anadarko Basin, Oklahoma. Of these, 47 fields represent production from marine clastic facies. The Morrow data were supplemented by data from the Upper Cambrian and Lower Ordovician Arbuckle Group, Middle Ordovician Simpson Group, Middle Pennsylvanian Atoka Formation, and Silurian and Lower Devonian Hunton Group of the Anadarko Basin, one large gas field in Upper Cretaceous reservoirs of north-central Montana (Bowdoin field), and three areas of the Upper Devonian and Lower Mississippian Bakken Formation continuous-type (unconventional) oil accumulation in the Williston Basin, North Dakota and Montana. Production parameters (PMP, PYP, and CP) measure the net result of complex geologic, engineering, and economic processes. Our fundamental hypothesis is that well-production data provide information about subsurface heterogeneity in older fields that would be impossible to obtain using geologic techniques with smaller measurement scales such as petrographic, core, and well-log analysis. Results such as these indicate that quantitative measures of production rates and production volumes of wells, expressed as dimensionless variation coefficients, are potentially valuable tools for documenting reservoir heterogeneity in older fields for field redevelopment and risk analysis.

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USGS2001

Petroleum geology and resources of the North Caspian Basin, Kazakhstan and Russia

The North Caspian basin is a petroleum-rich but lightly explored basin located in Kazakhstan and Russia. It occupies the shallow northern portion of the Caspian Sea and a large plain to the north of the sea between the Volga and Ural Rivers and farther east to the Mugodzhary Highland, which is the southern continuation of the Ural foldbelt. The basin is bounded by the Paleozoic carbonate platform of the Volga-Ural province to the north and west and by the Ural, South Emba, and Karpinsky Hercynian foldbelts to the east and south. The basin was originated by pre-Late Devonian rifting and subsequent spreading that opened the oceanic crust, but the precise time of these tectonic events is not known. The sedimentary succession of the basin is more than 20 km thick in the central areas. The drilled Upper Devonian to Tertiary part of this succession includes a prominent thick Kungurian (uppermost Lower Permian) salt formation that separates strata into the subsalt and suprasalt sequences and played an important role in the formation of oil and gas fields. Shallow-shelf carbonate formations that contain various reefs and alternate with clastic wedges compose the subsalt sequence on the 1 basin margins. Basinward, these rocks grade into deep-water anoxic black shales and turbidites. The Kungurian salt formation is strongly deformed into domes and intervening depressions. The most active halokinesis occurred during Late Permian?Triassic time, but growth of salt domes continued later and some of them are exposed on the present-day surface. The suprasalt sequence is mostly composed of clastic rocks that are several kilometers thick in depressions between salt domes. A single total petroleum system is defined in the North Caspian basin. Discovered reserves are about 19.7 billion barrels of oil and natural gas liquids and 157 trillion cubic feet of gas. Much of the reserves are concentrated in the supergiant Tengiz, Karachaganak, and Astrakhan fields. A recent new oil discovery on the Kashagan structure offshore in the Caspian Sea is probably also of the supergiant status. Major oil and gas reserves are located in carbonate reservoirs in reefs and structural traps of the subsalt sequence. Substantially smaller reserves are located in numerous fields in the suprasalt sequence. These suprasalt fields are largely in shallow Jurassic and Cretaceous clastic reservoirs in salt dome-related traps. Petroleum source rocks are poorly identified by geochemical methods. However, geologic data indicate that the principal source rocks are Upper Devonian to Lower Permian deep-water black-shale facies stratigraphically correlative to shallow-shelf carbonate platforms on the basin margins. The main stage of hydrocarbon generation was probably in Late Permian and Triassic time, during deposition of thick orogenic clastics. Generated hydrocarbons migrated laterally into adjacent subsalt reservoirs and vertically, through depressions between Kungurian salt domes where the salt is thin or absent, into suprasalt clastic reservoirs. Six assessment units have been identified in the North Caspian basin. Four of them include Paleozoic subsalt rocks of the basin margins, and a fifth unit, which encompasses the entire total petroleum system area, includes the suprasalt sequence. All five of these assessment units are underexplored and have significant potential for new discoveries. Most undiscovered petroleum resources are expected in Paleozoic subsalt carbonate rocks. The assessment unit in subsalt rocks with the greatest undiscovered potential occupies the south basin margin. Petroleum potential of suprasalt rocks is lower; however, discoveries of many small to medium size fields are expected. The sixth identified assessment unit embraces subsalt rocks of the central basin areas. The top of subsalt rocks in these areas occurs at depths ranging from 7 to 10 kilometers and has not been reached by wells. Undiscovered resources of this unit did not rec

Bulletin↗
USGS2001

Petroleum geology and resources of the North Ustyurt Basin, Kazakhstan and Uzbekistan

The triangular-shaped North Ustyurt basin is located between the Caspian Sea and the Aral Lake in Kazakhstan and Uzbekistan and extends offshore both on the west and east. Along all its sides, the basin is bounded by the late Paleozoic and Triassic foldbelts that are partially overlain by Jurassic and younger rocks. The basin formed on a cratonic microcontinental block that was accreted northward to the Russian craton in Visean or Early Permian time. Continental collision and deformation along the southern and eastern basin margins occurred in Early Permian time. In Late Triassic time, the basin was subjected to strong compression that resulted in intrabasinal thrusting and faulting. Jurassic-Tertiary, mostly clastic rocks several hundred meters to 5 km thick overlie an older sequence of Devonian?Middle Carboniferous carbonates, Upper Precambrian massifs and deformed Caledonian foldbelts. The Carboniferous?Lower Permian clastics, carbonates, and volca-basement is at depths from 5.5 km on the highest uplifts to 11 nics, and Upper Permian?Triassic continental clastic rocks, pri-km in the deepest depressions. marily red beds. Paleogeographic conditions of sedimentation, Three total petroleum systems are identified in the basin. the distribution of rock types, and the thicknesses of pre-Triassic Combined volumes of discovered hydrocarbons in these sysstratigraphic units are poorly known because the rocks have been tems are nearly 2.4 billion barrels of oil and 2.4 trillion cubic penetrated by only a few wells in the western and eastern basin feet of gas. Almost all of the oil reserves are in the Buzachi Arch areas. The basement probably is heterogeneous; it includes and Surrounding Areas Composite Total Petroleum System in 2 Petroleum Geology, Resources?North Ustyurt Basin, Kazakhstan and Uzbekistan the western part of the basin. Oil pools are in shallow Jurassic and Neocomian sandstone reservoirs, in structural traps. Source rocks are absent in the total petroleum system area; therefore, the oil could have migrated from the adjacent North Caspian basin. The North Ustyurt Jurassic Total Petroleum System encompasses the rest of the basin area and includes Jurassic and younger rocks. Several oil and gas fields have been discovered in this total petroleum system. Oil accumulations are in Jurassic clastic reservoirs, in structural traps at depths of 2.5?3 km. Source rocks for the oil are lacustrine beds and coals in the continental Jurassic sequence. Gas fields are in shallow Eocene sandstones in the northern part of the total petroleum system. The origin of the gas is unknown. The North Ustyurt Paleozoic Total Petroleum System stratigraphically underlies the North Ustyurt Jurassic system and occupies the same geographic area. The total petroleum system is almost unexplored. Two commercial flows of gas and several oil and gas shows have been tested in Carboniferous shelf carbonates in the eastern part of the total petroleum system. Source rocks probably are adjacent Carboniferous deep-water facies interpreted from seismic data. The western extent of the total petroleum system is conjectural. Almost all exploration drilling in the North Ustyurt basin has been limited to Jurassic and younger targets. The underlying Paleozoic-Triassic sequence is poorly known and completely unexplored. No wells have been drilled in offshore parts of the basin. Each of three total petroleum systems was assessed as a single assessment unit. Undiscovered resources of the basin are small to moderate. Most of the undiscovered oil probably will be discovered in Jurassic and Neocomian stratigraphic and structural traps on the Buzachi arch, especially on its undrilled off-shore extension. Most of the gas discoveries are expected to be in Paleozoic carbonate reservoirs in the eastern part of the basin.

Bulletin↗
USGS2002

Petroleum geology and total petroleum systems of the Widyan Basin and Interior Platform of Saudi Arabia and Iraq

Two total petroleum systems are associated with the Widyan Basin - Interior Platform Province in northern Saudi Arabia and western Iraq. In the Paleozoic Qusaiba/Akkas/Abba/ Mudawwara Total Petroleum System, which consists of one assessment unit - the Horst/Graben-Related Oil and Gas Assessment Unit - high-gravity, low-sulfur crude oil, as well as natural gas, occurs in horst/graben-related traps that formed prior to, during, and after Hercynian deformation (Carboniferous). The source of oil and gas is from organic-rich marine shale at the base of the Silurian sedimentary sequence (Qusaiba, Akkas, Mudawwara, and Abba Formations) that was deposited under dysoxic to anoxic conditions in an intra-shelf basin located north of the Central Arabian Arch. Onset of oil generation in Iraq began about 250 million years ago (Ma) and in eastern Saudi Arabia about 160 Ma, reaching peak generation, expulsion, migration, and entrapment during the Jurassic Period. In Saudi Arabia, petroleum migrated into fluvial and eolian quartzose sandstones of the Carboniferous-Early Permian Unayzah Formation that overlies the Hercynian unconformity, filling in rifts and half-grabens to thicknesses ranging to more than 400 meters. Combined stratigraphic-structural traps exist where the Unayzah Formation is the reservoir, as is the case in central Saudi Arabia. Oil and gas are sealed in those reservoirs by overlying tight carbonate- evaporite strata, and by subunconformity pinchouts of Pre-Unayzah clastic reservoir units against impermeable facies. In Iraq, reservoirs are sandstones of the Ordovician Upper Khabour and Silurian Akkas Formations. Over most of the Southwestern Desert of Iraq, Lower Silurian shale is a seal for hydrocarbons in the underlying Ordovician Khabour Formation. The Jurassic Gotnia/Barsarin/Sargelu/Najmah Total Petroleum System has two assessment units: the Platform Horst/Graben- Related Oil Assessment Unit and the Basinal Oil and Gas Assessment Unit. All reservoirs are in the Upper Jurassic Najmah Limestone and Gotnia Formation in Iraq, and the correlative Arab Formation in Saudi Arabia, occurring as lenses of marine bar or shelf-margin calcarenites, calcarenitic limestone, and dolomite. These strata grade eastward into organic-rich source rocks that were deposited under anoxic and dysoxic conditions in three restricted intra-shelf basins - from north to south, the Gotnia, Arabian, and Southern Arabian Gulf Basins. Maturation of the Upper Jurassic source-rock formations (Sargelu and Naokelekan Formations in Iraq) began around 90 Ma; peak generation took place from 85 to 13 Ma. With time, the oil migrated updip and was trapped in calcarenite lenses. Later, oil remigrated and was trapped in anticlines that began to form in Early Cretaceous time. Younger Jurassic shale and anhydrite seal rocks are distributed throughout the total petroleum system. The Widyan Basin-Interior Platform Province (2023) ranks 17th in the world, exclusive of the United States, with 62.5 billion barrels of oil equivalent of total petroleum endowment (cumulative production plus remaining petroleum plus estimated mean undiscovered volumes). Mean estimates of undiscovered petroleum for the province, which includes both Paleozoic and Jurassic petroleum systems as well as portions of three additional total petroleum systems from adjacent provinces, are 21.22 billion barrels of oil, 94.75 trillion cubic feet of gas (15.8 billion barrels of oil equivalent), and 6.85 billion barrels of natural gas liquids. The Paleozoic total petroleum system is dominantly gas prone, whereas the volumetrically larger Jurassic total petroleum system is oil prone - resulting in the characterization of the province as an oil province. The discovery maturity for the province is a relatively low 31 percent, meaning that much of the province petroleum potential lies in the future.

Arabian Peninsula↗
USGS2003

Qingshankou-Putaohua/Shaertu and Jurassic Coal-Denglouku/Nongan total petroleum systems in the Songliao Basin, China

The Qingshankou-Putaohua/Shaertu petroleum system involves the generation of oil and gas from a mature pod of lacustrine source rock near the center of the Songliao Basin in northeastern China. The primary source rock is the Lower Cretaceous Qingshankou Formation, and a secondary source rock is Member 1 of the Lower Cretaceous Nenjiang Formation. The most productive of six sandstone reservoirs are the Putaohua reservoir (Member 1 of the Lower Cretaceous Yaojia Formation) and the Shaertu reservoir (Members 2 and 3 of the Yaojia Formation and Member 1 of the Nenjiang Formation). Most oil and associated gas generated from the Qingshankou Formation and Nenjiang Formation (Member 1) are trapped in large faulted anticlines, fault blocks, and faulted anticlinal noses in combination with facies-change and (or) diagenetic stratigraphic traps. Two assessment units are defined in the petroleum system: (1) an anticlinal assessment unit; and (2) a subtle-traps assessment unit consisting of (a) anticlinal noses in combination with fault or stratigraphic traps, (b) stratigraphic traps, and (c) unconventional reservoirs. Undiscovered conventional oil and gas resources are expected in both assessment units in small (5?10 million barrels of oil; 30?60 billion ft3 gas) and medium (10?25 million barrels of oil; 60?150 billion ft3 of gas) fields. Also, undiscovered conventional oil and gas resources are expected in several large fields (25?73 million barrels of oil; 150?173 billion ft3 of gas). The Jurassic coal?Dengloukou/Nongan petroleum system involves the generation of natural gas from multiple pods of mature source rock in graben structures at the base of the Songliao Basin. Sandstone and conglomeratic sandstone in the Lower Cretaceous Denglouku Formation and the Lower Cretaceous Quantou Formation are the major reservoir rocks. Most of the known natural gas is trapped in anticlines, anticlinal noses, and fault blocks. This petroleum system is largely unexplored in comparison to the Qingshankou-Putaohua/Shaertu petroleum system and has good potential for undiscovered gas in the structural traps assessment unit. Undiscovered conventional gas is expected in small (30?60 billion ft3 of gas), medium (60?150 billion ft3 of gas), and large (150?395 billion ft3 of gas) fields. The U.S. Geological Survey World Energy Assessment Team (2000) estimated that the Songliao Basin has, at a mean value, about 1.03 billion barrels of undiscovered conventional oil resources and 5.71 trillion ft3 of undiscovered conventional gas resources.

Bulletin↗
USGS2005

Transylvanian Composite Total Petroleum System of the Transylvanian Basin Province, Romania, Eastern Europe

The Transylvanian Composite Total Petroleum System and the Transylvanian Neogene Suprasalt Gas Assessment Unit were identified in the Transylvanian Basin Province (4057), which lies entirely within the country of Romania. The assessment unit is composed of middle Miocene (Badenian) to Pliocene strata. Gas from the assessment unit is biogenic and originated from bacterial activity on dispersed organic matter in shales and siltstones. Gas migration is believed to be minimal, both vertically and laterally, with gases trapped in local stratigraphic traps and in structural traps (most likely domes and anticlinal folds created by salt diapirism) in the central part of the basin. For this reason, the gas fields also are concentrated in the central part of the basin. Reservoirs are isolated and composed of vertically stacked sandstones and siltstones sealed by shales and possibly by evaporite layers. Traps result from stratigraphic and facies changes within the entire assessment unit stratigraphic section. Some gas fields contain as much or more than a trillion cubic feet, but in most, the estimated resources are between 6 billion and 96 billion cubic feet. Petroleum exploration in the province is in the mature stage, which, combined with the geologic complexity of the region, is considered to limit future discoveries to a relatively few small fields. The undiscovered resources for the Transylvanian Basin Neogene Suprasalt Composite AU in the Transylvanian Hybrid Total Petroleum System (4057) are, at the mean, 2.083 trillion cubic feet of gas. No oil is produced in the basin. Rocks underlying the salt layers were not assessed for hydrocarbon potential.

Bulletin↗
USGS2004

Sylhet-Kopili/Barail-Tipam Composite Total Petroleum System, Assam Geologic Province, India

The Sylhet-Kopili/Barail-Tipam Composite total petroleum system (TPS) (803401) is located in the Assam Province in northeasternmost India and includes the Assam Shelf south of the Brahmaputra River. The area is primarily a southeast-dipping shelf overthrust by the Naga Hills on the southeast and the Himalaya Mountain range to the north. The rocks that compose this TPS are those of the Sylhet-Kopili/Barail-Tipam composite petroleum system. These rocks are those of the Eocene-Oligocene Jaintia Group Sylhet and Kopili Formations, the Oligocene Barail Group, the Oligocene-Miocene Surma and Tipam Groups. These groups include platform carbonates, shallow marine shales and sandstones, and the sandstones, siltstones, shales, and coals of deltaic and lagoonal facies. Source rocks include the Sylhet and Kopili Formation shales, Barail Group coals and shales, and in the south the Surma Group shales. Total organic content is generally low, averaging from 0.5 to 1.8 percent; it is as high as 9 percent in the Barail Coal Shales. Maturities are generally low, from Ro 0.45 to 0.7 percent where sampled. Maturity increases to the southeast near the Naga thrust fault and can be expected to be higher in the subthrust. Generation began in early Pliocene. Migration is primarily updip to the northwest (< 5 to 15 kilometers) along the northeast-trending slope of the Assam Shelf, and vertical migration occurs through reactivated basement-rooted faults associated with the plate collisions. Reservoir rocks are carbonates of the Sylhet Formation, interbedded sandstones of the Kopili Formation and sandstones of the Barail, Surma, and Tipam Groups. Permeability ranges from less than 8 mD (millidarcies) to as high as 800 mD in the Tipam Group. Porosity ranges from less than 7 percent to 30 percent. Traps are primarily anticlines and faulted anticlines with a few subtle stratigraphic traps. There is also a likelihood of anticlinal traps in the subthrust. Seals include interbedded Oligocene and Miocene shales and clays, and the thick clays of the Pliocene Gurjan Group.

Bulletin↗
USGS1915

The fauna of the Batesville sandstone of northern Arkansas

The beds in northern Arkansas that lie between the Boone limestone (commonly regarded as representing the Burlington and Keokuk epochs) and the Pennsylvanian have been divided into several formations, named, in ascending order, Moorefield shale, Batesville sandstone, Fayetteville shale, and Pitkin limestone. These formations presumably are equivalent to those that hold a corresponding position in the typical Mississippian section of Iowa, Missouri, and Illinois, but the faunas which they have furnished show noteworthy differences from the typical faunas. It has therefore seemed desirable to investigate these faunas, especially as the facies which they present is found also in the faunas of several of the Southern States, such as Oklahoma, Mississippi, and Alabama. With this object in view, I published in 1911 a report on the fossils of the Moorefield shale. The fauna next to be considered in a systematic pursuance of such a plan as I have mentioned is that of the Batesville sandstone, but the fauna of the Batesville sandstone, as is well known, has already been described in a treatise by Prof. Stuart Weller. At first I considered the possibility of pretermitting the Batesville fauna and of substituting Prof. Weller's report for my own in a series of little monographs that are under contemplation. It soon became evident, however, that this would not be satisfactory because, whether by reason of having collections from a number of new localities or by reason of having more extensive collections from old ones, I found that the material at my command considerably increased the number of types known from the Batesville sandstone, among them being a few which were undescribed. In fact, while Prof. Weller's paper discusses only 30 species (aside from a few Bryozoan types not even generically distinguished) the present paper discusses 128 species. On this account it seemed to me essential to redescribe the fauna.

Arkansas↗
USGS2007

Regional Fluid Flow and Basin Modeling in Northern Alaska

The foothills of the Brooks Range contain an enormous accumulation of zinc (Zn) in the form of zinc sulfide and barium (Ba) in the form of barite in Carboniferous shale, chert, and mudstone. Most of the resources and reserves of Zn occur in the Red Dog deposit and others in the Red Dog district; these resources and reserves surpass those of most deposits worldwide in terms of size and grade. In addition to zinc and lead sulfides (which contain silver, Ag) and barite, correlative strata host phosphate deposits. Furthermore, prolific hydrocarbon source rocks of Carboniferous and Triassic to Early Jurassic age generated considerable amounts of petroleum that may have contributed to the world-class petroleum resources of the North Slope. Deposits of Zn-Pb-Ag or barite as large as those in the Brooks Range are very rare on a global basis and, accordingly, multiple coincident favorable factors must be invoked to explain their origins. To improve our understanding of these factors and to contribute to more effective assessments of resources in sedimentary basins of northern Alaska and throughout the world, the Mineral Resources Program and the Energy Resources Program of the U.S. Geological Survey (USGS) initiated a project that was aimed at understanding the petroleum maturation and mineralization history of parts of the Brooks Range that were previously poorly characterized. The project, titled “Regional Fluid Flow and Basin Modeling in Northern Alaska,” was undertaken in collaboration with industry, academia, and other government agencies. This Circular contains papers that describe the results of the recently completed project. The studies that are highlighted in these papers have led to a better understanding of the following: The complex sedimentary facies relationships and depositional settings and the geochemistry of the sedimentary rocks that host the deposits (sections 2 and 3). The factors responsible for formation of the barite and zinc deposits (sections 4 and 5). The geochemical indicators or exploration tools that might be used to locate other large deposits of similar character in the Red Dog district and elsewhere (section 6). The isotopic compositions of barite and sulfide deposits (sections 7 and 8) The distribution and nature of phosphate and metalliferous oil shale localities (sections 9 and 10). The architecture, kinematics, and timing of the complex thrust systems that disrupted and redistributed the Carboniferous and younger rocks; these studies are necessary in order to make a realistic palinspastic reconstruction of the basin (sections 11 and 12). The nature and extent of the petroleum system sourced from Mississippian rocks (section 13).

Circular↗
USGS1983

Petroleum geology and resources of southeastern Mexico, northern Guatemala, and Belize

Petroleum deposits in southeastern Mexico and Guatemala occur in two main basinal provinces, the Gulf Coast Tertiary basin area, which includes the Reforma and offshore Campeche Mesozoic fields, and the Peten basin of eastern Chiapas State (Mexico) and Guatemala. Gas production is mainly from Tertiary sandstone reservoirs of Miocene age. Major oil production, in order of importance, is from Cretaceous, Paleocene, and Jurassic carbonate reservoirs in the Reforma and offshore Campeche areas. Several small oil fields have been discovered in Cretaceous carbonate reservoirs in west-central Guatemala, and one major discovery has been reported in northwestern Guatemala. Small- to medium-sized oil accumulations also occur in Miocene sandstone reservoirs on salt structures in the Isthmus Saline basin of western Tabasco State, Mexico. Almost all important production is in salt structure traps or on domes and anticlines that may be related to deep-seated salt structures. Some minor oil production has occurred in Cretaceous carbonate reservoirs in a buried overthrust belt along the west flank of the Veracruz basin. The sedimentary cover of Paleozoic through Tertiary rocks ranges in thickness from about 6,000 m (20,000 ft) to as much as 12,000 m (40,000 ft) or more in most of the region. Paleozoic marine carbonate and clastic rocks 1,000 to 2,000 m (3,300 to 6,500 ft) thick overlie the metamorphic and igneous basement in part of the region; Triassic through Middle Jurassic red beds and evaporite deposits, including halite, apparently are present throughout the region, deposited in part in a Triassic graben system. Upper Jurassic (Oxfordian) through Cretaceous rocks make up the bulk of the Mesozoic regional carbonate bank complex, which dominates most of the area. Tertiary marine and continental clastic rocks, some of deep water origin, 3,000 to 10,000 m (10,000 to 35,000 ft) thick, are present in the coastal plain Tertiary basins. These beds grade eastward into a carbonate sequence that overlies the Mesozoic carbonate complex on the Yucatan platform. During the past 10 years, about 50 large oil fields were discovered in the Reforma and offshore Campeche areas. Oil is produced from intensely microfractured Cretaceous, Paleocene, and Upper Jurassic dolomite reservoirs on blockfaulted salt swells or domes. Most fields are located in the Mesozoic carbonate-bank margin and forebank talus (Tamabra) facies, which passes through the offshore Campeche and onshore Reforma areas. Oil source rocks are believed to be organic-rich shales and shaly carbonate rocks of latest Jurassic and possibly Early Cretaceous age. At least six of the Mesozoic discoveries are giant or supergiant fields. The largest is the Cantarell complex (about 8 billion to 10 billion barrels (BB)) in the offshore Campeche area and the Bermudez complex (about 8 BB) in the Reforma onshore area. Oil columns are unusually large (from 50 m to as much as 1,000 m, or 160 ft to 3,300 ft). Production rates are extremely high, averaging at least 3,000 to 5,000 barrels of oil per day (bo/d); some wells produce more than 20,000 bo/d, particularly in the offshore Campeche area, where 30,000- to 60,000-bo/d wells are reported. Tertiary basin fields produce primarily from Miocene sandstone reservoirs. About 50 of these are oil fields ranging from 1 million barrels (MMB) to 200 MMB in size, located on faulted salt structures in the Isthmus Saline basin. Another 30 are gas or gas-condensate fields of a few billion cubic feet to 3 trillion to 4 trillion cubic feet (Tcf) located on salt structures or probable salt structures in the Macuspana, Comalcalco, Isthmus Saline, and Veracruz basins. Source rocks for the gas are believed to be carbonaceous shales interbedded with the sandstone reservoir bodies. Identified reserves in the southeastern Mexico-Guatemala area, almost all in the Mesozoic fields, are about 53 BB of oil, 3 BB of natural gas liquids, and 65 Tcf of gas. The estimat

Circular↗
USGS1987

The Alaska Mineral Resource Assessment Program: Background information to accompany folio of geologic and mineral resource maps of the Circle quadrangle, Alaska

The geology, geochemistry, geophysics, and Landsat imagery of the Circle quadrangle were investigated by an interdisciplinary research team for the purpose of assessing the mineral potential of the area. The quadrangle covers approximately 15,765 km 2 in east-central Alaska; most of it is included in the mountainous Yukon-Tanana Upland physiographic division, but the northernmost part is in the low-lying Yukon Flats section. The Circle mining district, in the east-central part of the quadrangle, has been a major producing area of placer gold since its discovery in 1893. For descriptive purposes, the Circle quadrangle is divided into three areas: the northwest Circle quadrangle, the area north of the Tintina fault zone, and the area south of the Tintina fault zone. The Tintina fault zone extends northwesterly through the northern part of the quadrangle. The northwest Circle quadrangle contains mostly folded and faulted, slightly metamorphosed sedimentary rocks that are intruded by Tertiary granitic plutons. In the northern part of the area north of the Tintina fault zone (Little Crazy Mountains and northern east Crazy Mountains), the rocks consist primarily of the gabbro and basalt of the Circle Volcanics and minor associated chert, graywacke, and limestone. Elsewhere in this area (south of the Circle Volcanics and in the western Crazy Mountains), the rocks are mostly slightly metamorphosed Paleozoic sedimentary rocks that have been folded and faulted. Rocks in the largest part of the quadrangle, the area south of the Tintina fault zone, consist largely of pelitic rocks that are regionally metamorphosed to greenschist and amphibolite facies. Felsic plutons, mostly Tertiary in age, occur throughout the area. The metamorphic rocks are separated from sedimentary rocks on the northwest by thrust faulting. The aeromagnetic and gravity data show clear differences between the areas north and south of the Tintina fault zone. The metamorphic terrane to the south has low overall gravity and local gravity lows over exposed granitic plutons. It is hypothesized that magnetic chlorite schist infolded with nonmagnetic quartzite and schist account for east-northeast-trending magnetic highs that approximately parallel the regional strike of the most prominent foliation in the metamorphic rocks. North of the Tintina fault zone, the Circle Volcanics are characterized by high gravity and east-west-trending magnetic highs. The Tintina fault zone has an intense magnetic high near the western margin of the Circle quadrangle overlying the magnetic granodiorite of the Victoria Mountain pluton. A magnetic high near Circle Hot Springs is less intense, but broader, and could reflect a buried magnetic pluton similar to that of the Victoria Mountain pluton. Computer-enhanced Landsat images of the Circle quadrangle show trends and patterns of concentrations of linear features. Features trending northeast-southwest predominate throughout the quadrangle; northwest-southeast-trending linear features are found mostly south of the Tintina fault zone. High concentrations of linear features were not found to correspond to areas of known mineralization in any consistent or significant way that could presently be used in locating areas of mineralization. Geochemical and mineralogical studies of stream sediment and heavy-mineral concentrates from the Circle quadrangle identify areas of anomalous concentrations of metallic elements, including gold, silver, tin, tungsten, lead, antimony, zinc, thorium, uranium, and beryllium. The data delineate areas of known mineral occurrences and areas that may contain undiscovered mineral resources. To date, placer gold has been the only significant metallic mineral resource from the Circle quadrangle, but the general geologic setting, especially the presence of post-orogenic plutons, is similar to that of regions that contain tin greisen deposits, tungsten skarn deposits, lode gold deposits in metasedimentary rocks, and uranium vein deposits. Six areas or tracts were identified in which such deposits might occur, and two more tracts were delineated as possible for the occurrence of shale-hosted Lead-zinc deposits. The discovery of two diamonds in the gravels of Cooked Creek point to the slight possibility of finding placer or lode diamond deposits. Although most of the past and present gold mining has taken place in four areas in the quadrangle, a sedimentary basin near the town of Central was identified as possibly containing buried placer gold deposits or sedimentary uranium deposits.

Alaska↗
USGS2007

Sedimentary properties of shallow marine cores collected in June and September 2006, Hanalei Bay, Kaua'i, Hawai'i

Sedimentary facies, short-lived isotopes 7 Be, 137 Cs, and 210 Pb, and magnetic properties of sediment cores in Hanalei Bay, Kaua‘i, Hawai‘i, were used to assess sediment sources and patterns of deposition associated with seasonal flooding of the Hanalei River. Sediment cores were collected from the seafloor in June and September of 2006 to supplement similar data collected during the summer of 2005. The youngest and thickest terrigenous sediment was observed on the east side of the bay: near the Hanalei River mouth and in a bathymetric depression, known locally as the Black Hole, that acts as a temporary sediment sink. Deposits from floods that occurred between February and April 2006 left flood deposits in the eastern bay that, by June of 2006, were on the order of 10 cm thick. A flood occurred on August 7, 2006, that was smaller than floods that occurred the previous winter but was a substantial discharge event for the summer season. Deposits from the winter 2006 floods continued to dominate the sedimentary record in the eastern bay through early fall, even after the addition of newer sediment during the August 7 flood; this is consistent with the much higher sediment input of the winter floods compared with the August 7 flood. Broad variations in magnetic grain size and relative magnetite-hematite abundance in several sediment cores indicate many sources of upland terrigenous sediment. As a group, recent flood deposits show much less variation in these properties compared with older deposits, implying either that the 2006 winter–spring flood sediment originated from one or more distinct upland settings, or that substantial mixing of sediment from multiple sources occurred during transport. Sediment is most readily remobilized and advected out of the bay during winter, when oceanic conditions are energetic. In summer, wave and current measurements made concurrently with this study showed weak currents and little wave energy, indicating that sediment delivered during summer floods most likely remains in the bay until winter storms can remove it. Increased turbidity and sedimentation on corals resulting from floods of the Hanalei River could affect the sustainability of coral reefs and their many associated species. This possibility is of particular concern during summer months when wave energy is low and sediment is not readily remobilized and transported out of the bay. The timing (seasonality) and magnitude of sediment input to the coastal ocean relative to seasonal variations in wave and current energy could have significant ecological consequences for coral-reef communities in the Hawaiian Islands.

Hawai'i↗
USGS2008

Multibeam Sonar Mapping and Modeling of a Submerged Bryophyte Mat in Crater Lake, Oregon

Traditionally, multibeam data have been used to map sea floor or lake floor morphology as well as the distribution of surficial facies in order to characterize the geologic component of benthic habitats. In addition to using multibeam data for geologic studies, we want to determine if these data can also be used directly to map the distribution of biota. Multibeam bathymetry and acoustic backscatter data collected in Crater Lake, Oregon, in 2000 are used to map the distribution of a deep-water bryophyte mat, which will be extremely useful for understanding the overall ecology of the lake. To map the bryophyte's distribution, depth range, acoustic backscatter intensity, and derived bathymetric index grids are used as inputs into a hierarchical decision-tree classification model. Observations of the bryophyte mat from over 23 line kilometers of lake-floor video collected in the summer of 2006 are used as controls for the model. The resulting map matches well with ground-truth information and shows that the bryophyte mat covers most of the platform surrounding Wizard Island as well as on outcrops around the caldera wall.

Data Series↗
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↗
USGS2007

Subsurface stratigraphic cross sections of cretaceous and lower tertiary rocks in the Wind River Basin, central Wyoming: Chapter 9 in Petroleum systems and geologic assessment of oil and gas resources in the Wind River Basin Province, Wyoming

The stratigraphic cross sections presented in this report were constructed as part of a project conducted by the U.S. Geological Survey to characterize and evaluate the undiscovered oil and gas resources of the Wind River Basin (WRB) in central Wyoming. The primary purpose of the cross sections is to show the stratigraphic framework and facies relations of Cretaceous and lower Tertiary rocks in this large, intermontane structural and sedimentary basin, which formed in the Rocky Mountain foreland during the Laramide orogeny (Late Cretaceous through early Eocene time). The WRB is nearly 200 miles (mi) long, 70 mi wide, and encompasses about 7,400 square miles (mi 2 ) (fig. 1). The basin is structurally bounded by the Owl Creek and Bighorn Mountains on the north, the Casper arch on the east, the Granite Mountains on the south, and the Wind River Range on the west.

Wyoming↗
USGS2014

Maps and geospatial data for the Shorty’s Island and Myrtle Bend substrate enhancement pilot projects, Kootenai River near Bonners Ferry, Idaho, 2014

The U.S. Geological Survey, in cooperation with the Idaho Department of Fish and Game, conducted a study to characterize the physical habitat occupied by Kootenai River white sturgeon during spawning and early-life phases. The objective was to gain a better understanding of spawning behavior, site selection, and type of habitat used during egg incubation in two sub-reaches of the Kootenai River. Habitat characterizations generated by this study will assist in the design of a substrate enhancement pilot project. This report presents the methods used to develop georeferenced portable document format maps and geospatial data that describe spawning locations and physical habitat characteristics (including egg mat locations, bathymetry, surficial sediment facies, and streamflow velocity) within the substrate enhancement pilot project study area. The results are presented as two maps illustrating the physical habitat characteristics along with proposed habitat enhancement areas, aerial imagery, and hydrography. The results of this study will assist researchers, policy makers, and management agencies in deciding the spatial location and extent of the substrate enhancement pilot project.

Idaho↗