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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↗

USGS2018

California State Waters Map Series — Offshore of Point Conception, 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 Offshore of Point Conception map area is in the westernmost 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 this region is presently undergoing north-south shortening. The offshore part of the map area lies south of the stee p south and west flanks of t he Santa Ynez Mountains . The crest of the range , which has a maximum elevation of about 340 m in the map area, lies about 5 km north and east of the arcuate shoreline. The onland part of the coastal zone is remote and sparsely populated. The road to Jalama Beach County Park provides the only public coastal access in the entire map area. North of this county park, the coastal zone is part of Vandenberg Air Force Base. South of Jalama Beach County Park, most of the coastal zone is part of the Cojo-Jalama Ranch, purchased by the Nature Conservancy in December 2017. A relatively small part of the coastal zone in the eastern part of the map area lies within the privately owned Hollister Ranch. The nearest significant commercial centers are Lompoc (population, about 42,000), about 10 km north of the map area, and Goleta (population, about 30,000), about 50 km east of the map area. The Union Pacific railroad tracks run west and northwest along the coast through the entire map area, within a few hundred meters of the shoreline. The map area has a long history of petroleum exploration, and the seafloor notably includes large asphalt mounds and pockmarks that result from petroleum seepage. Several offshore gas and oil fields were discovered, and some were developed, in and on the margin of California’s State Waters. Much of the shoreline in the Offshore of Point Conception map area is characterized by narrow beaches that have thin sediment cover above bedrock platforms, backed by low (10- to 20-m-high) cliffs that are capped by a 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 west-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 map area is mainly from relatively small coastal watersheds, including the Jalama Creek–Espada Creek drainage basin (about 63 km 2 ), as well as Cañada del Jolloru, Black Canyon, Wood Canyon, Cañada del Cojo, and Barranca Honda. 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. Following the coastline, the shelf bends to the north and northwest around Point Conception, and the trend of the shelf break changes from about 298° to 241° azimuth. Shelf width ranges from about 5 km south of Point Conception to about 11 km northwest of it; the slope ranges from about 1.0° to 1.2° to about 0.7° south and northwest of Point Conception, respectively. Southwest of Point Conception, the shelf break and upper slope are incised by a 600-m-wide, 20- to 30-m-deep, south-facing trough, one of five heads of the informally named Arguello submarine canyon. The map area is located at a major biogeographic transition zone between the east-west-trending Santa Barbara Channel region of the Southern California Bight and the northwest-trending central California coast. North of Point Conception, the coast is subjected to high wave exposure from the north, west, and south, as well as consistently strong upwelling that brings cold, nutrient-rich waters to the surface. Southeast of Point Conception, the Santa Barbara Channel is largely protected from strong north swells by Point Conception and from south swells by the Channel Islands; surface waters are warmer, and upwelling is weak and seasonal. 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 Point Conception 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 are attractive to groundfish. Below the steep shelf break, soft, unconsolidated sediment is interrupted by the heads of several submarine canyons, gullies, and rills, also good potential habitat for rockfish. The map area includes the large (58.3 km 2 ) Point Conception State Marine Reserve.

California↗

USGS2008

Mesozoic non-marine petroleum source rocks determined by palynomorphs in the Tarim Basin, Xinjiang, northwestern China

The Tarim Basin in Northwest China hosts petroleum reservoirs of Cambrian, Ordovician, Carboniferous, Triassic, Jurassic, Cretaceous and Tertiary ages. The sedimentary thickness in the basin reaches about 15 km and with an area of 560000 km2, the basin is expected to contain giant oil and gas fields. It is therefore important to determine the ages and depositional environments of the petroleum source rocks. For prospective evaluation and exploration of petroleum, palynological investigations were carried out on 38 crude oil samples collected from 22 petroleum reservoirs in the Tarim Basin and on additionally 56 potential source rock samples from the same basin. In total, 173 species of spores and pollen referred to 80 genera, and 27 species of algae and fungi referred to 16 genera were identified from the non-marine Mesozoic sources. By correlating the palynormorph assemblages in the crude oil samples with those in the potential source rocks, the Triassic and Jurassic petroleum source rocks were identified. Furthermore, the palynofloras in the petroleum provide evidence for interpretation of the depositional environments of the petroleum source rocks. The affinity of the miospores indicates that the petroleum source rocks were formed in swamps in brackish to lacustrine depositional environments under warm and humid climatic conditions. The palynomorphs in the crude oils provide further information about passage and route of petroleum migration, which is significant for interpreting petroleum migration mechanisms. Additionally, the thermal alternation index (TAI) based on miospores indicates that the Triassic and Jurassic deposits in the Tarim Basin are mature petroleum source rocks. ?? Cambridge University Press 2008.

Geological Magazine↗

USGS1990

Hydrothermally derived petroleum: examples from Guaymas Basin, Gulf of California, and Escanaba Trough, northeast Pacific Ocean

In the Guaymas Basin, a spreading axis in the Gulf of California, petroleum having a wide range of compositions forms by hydrothermal alteration of organic matter in Quaternary sediment composed mainly of marine diatomaceous ooze and muddy turbidites. In Escanaba Trough, at the southern end of the Gorda Ridge spreading axis offshore northern California, petroleum is formed by hydrothermal processes acting on mainly terrigenous organic material in Quaternary turbiditic river-derived sediment. Comparisons of the distributions of hydrocarbons - n-alkanes, isoprenoids, terpanes, steranes, and aromatics - show that chemical differences among four petroleum samples are such that two samples from Guaymas Basin can be distinguished from two samples from Escanaba Trough. Distinguishing characteristics resulting from differences in sources include n-alkane distributions and certain sterane ratios; distinguishing characteristics resulting from differences in thermal histories of the organic matter include hopane and sterane epimer ratios and various distributions of polycyclic aromatic hydrocarbons. These oils differ from conventionally derived petroleum in that they are admixtures of products generated over a wide range of thermal regimes, and their generation, expulsion, and migration occurred simultaneously over an instantaneous geological time period. The potential economic significance of hydrothermal derived petroleum is uncertain, but the fact that petroleum can form at active oceanic spreading axes adds a new facet to understanding the processes of petroleum generation, expulsion, and migration.

Escanaba Trough and Guaymas Basin in the system of↗

USGS2025

Characterizing sedimentary organic carbon in a hydrothermal spreading center, the Escanaba Trough

Sediments in critical marine mineral environments are of wide importance due to their preservation of both marine minerals and organic carbon (OC) stocks. However, OC storage and cycling is often overlooked in mineral system studies. This work characterizes sedimentary OC within the Escanaba Trough, a hydrothermal sulfide system off the coast of northern California. By utilizing ROV-based push coring, we collected sediments near and far from high temperature, low temperature, and inactive vents. We applied a multipronged organic geochemical approach, measuring bulk sediment, OC fractions of varying labilities, and biomarkers to tease apart the storage, source, and cycling of OC within this complex system. In contrast to past work indicating a primarily terrestrial source to deeper, Pleistocene sediments, our results suggest a primarily marine source in surface sediments at least 50 m away from active venting. Near active venting, we see evidence of locally produced chemosynthetic OC in addition to the background marine source. This chemosynthetic OC appears to be rapidly remineralized and supports more complex deep-sea food webs compared to hemipelagic sites. Still, the greatest contribution of labile OC was observed at inactive vent sites, which we suggest is due to hydrothermal fluid alteration of more labile OC at actively venting sites. Depending on fluid temperature, hydrothermally altered OC is either preserved in the sediments as petroleum or migrated with fluid flow. Considering inactive sites are those most likely to be targeted by potential mining, we suggest additional studies could verify if these results apply at other sedimented seafloor massive sulfide systems.

California↗

USGS2002

Hydrocarbon geochemistry of cold seeps in the Monterey Bay National Marine Sanctuary

Samples from four geographically and tectonically discrete cold seeps named Clam Flat, Clamfield, Horseshoe Scarp South, and Tubeworm City, within the Monterey Bay National Marine Sanctuary were analyzed for their hydrocarbon content. The sediment contains gaseous hydrocarbons and CO2, as well as high molecular weight aliphatic and aromatic hydrocarbons with various combinations of thermogenic and biogenic contributions from petroleum, marine, and terrigenous sources. Of particular interest is the cold seep site at Clamfield which is characterized by the presence of thermogenic hydrocarbons including oil that can likely be correlated with oil-saturated strata at Majors Creek near Davenport, CA, USA. At Clam Flat, the evidence for thermogenic hydrocarbons is equivocal. At Horseshoe Scarp South and Tubeworm City, hydrocarbon gases, mainly methane, are likely microbial in origin. These varied sources of hydrocarbon gases highlight the diverse chemical systems that appear at cold seep communities. ?? 2002 Elsevier Science B.V. All rights reserved.

Marine Geology↗

USGS2022

Focus areas for data acquisition for potential domestic resources of 13 critical minerals in the conterminous United States and Puerto Rico — Antimony, barite, beryllium, chromium, fluorspar, hafnium, helium, magnesium, manganese, potash, uranium, vanadium, and zirconium

The Earth Mapping Resources Initiative (Earth MRI) is conducted in phases to identify areas for acquiring new geologic framework data to identify potential domestic resources of the 35 mineral materials designated as critical minerals for the United States. This report describes the data sources and summary results for 13 critical minerals evaluated in the conterminous United States and Puerto Rico during phase 3 of the study (antimony, barite, beryllium, chromium, fluorspar, hafnium, helium, magnesium, manganese, potash, uranium, vanadium, and zirconium). Phases 1 and 2 of the Earth MRI addressed aluminum, cobalt, graphite, lithium, niobium, platinum-group elements (PGEs), rare earth elements (REEs), tantalum, tin, titanium, and tungsten. Critical minerals in Alaska are covered in a separate report. No focus areas for phase 3 critical minerals are delineated for Hawaii. The geologic, geochemical, topographic, and geophysical mapping provided by the Earth MRI documents geologic features that reflect the extent of individual mineral systems and provides information about critical mineral deposits that may not have been previously considered. The mineral-systems approach links critical mineral commodities to deposit types that represent the manifestations of large mineral systems. Each of the 13 critical mineral commodities for phase 3 of the Earth MRI is discussed in terms of its importance to the Nation’s economy, modes of occurrence, mineral systems, and deposit types, and is accompanied by maps and tables listing examples of focus areas in the conterminous United States and Puerto Rico. Examples of important mineral systems for this group of 13 critical minerals include basin brine path systems for barite and fluorspar, Carlin-type systems and Coeur d’Alene systems for antimony, chemical weathering and volcanogenic seafloor systems for manganese, Climax-type systems for beryllium, mafic magmatic systems for chromium, marine evaporite systems for potash and magnesium, meteoric recharge systems for uranium, petroleum systems for helium, and placer systems for zirconium and hafnium.

Open-File Report↗

USGS2023

Groundwater quality near the Montebello Oil Field, Los Angeles County, California

Groundwater quality and potential sources and migration pathways of chemical constituents associated with hydrocarbon-bearing formations were assessed by the U.S. Geological Survey for the California State Water Resources Control Board Oil and Gas Regional Monitoring Program (RMP). Groundwater samples were collected as part of the RMP from 21 preexisting wells used for public supply, monitoring, or irrigation in and near the Montebello Oil Field and analyzed for constituents associated with hydrocarbon-bearing formations and constituents used to identify recently recharged groundwater and older groundwater. The newly collected RMP data were supplemented with historical sample data from 849 groundwater wells and analyzed with respect to explanatory factors that have the potential to influence water quality. Potential sources and migration pathways of fluids (water, gas, or oil) from hydrocarbon-bearing formations that could affect groundwater quality in the Montebello Oil Field include large volumes of recycled produced water (water withdrawn from an oil well and brought to the surface that may include oil, water, and gas from the geologic formation and water or gas injected for enhanced recovery) that have been reinjected since the 1960s to enhance oil production, oil and gas wells with well-integrity issues, and oil and gas wells with an uncemented annulus that intersects groundwater resource zones. Trace amounts of dissolved petroleum hydrocarbons, thermogenic gas (propane through pentane range), or both, were detected in seven groundwater samples collected in 2014 and 2018 as part of the RMP. Five of those samples also contained manufactured volatile organic compounds and at least some modern-age groundwater (recharged during or after 1953), indicating that the hydrocarbons could have originated from surficial, or shallow, sources unrelated to oil and gas development. Two samples contained low concentrations of petroleum hydrocarbons (less than 0.1 microgram per liter) and did not contain detections of manufactured volatile organic compounds in pre-modern groundwater. These samples were collected from relatively deep wells (greater than 140 meters below land surface) with perforations completed in marine sediments that may contain water with similar compositions to produced water. The RMP sample results and available historical data in and near the Montebello Oil Field did not provide conclusive evidence that oil and gas development has adversely affected groundwater resources. All samples with detectable petroleum hydrocarbons, thermogenic gases, or both, were collected from sites that also are within 500 meters of anthropogenic hydrocarbon sources not associated with oil and gas development or sources. In addition, naturally occurring sources of hydrocarbons that exist at intervals shallower than, or are in areas outside of, economically productive oil- and gas-producing zones could affect groundwater quality. A definitive analysis of relations of groundwater quality to potential anthropogenic and natural explanatory factors was not possible because of the low density of new and historical sampling data, particularly in parts of the Montebello Oil Field where the largest relative risks to groundwater from hydrocarbon-bearing formations exist. Areas to consider for more detailed monitoring and analysis in the future that may present the largest relative potential risks to groundwater quality include (1) areas downgradient from historical surface ponds and sumps and (2) areas with co-located high net injection (oil reservoir injection exceeds production), old oil and gas wells that may be more likely to develop well-integrity issues than newer wells, and oil and gas wells with uncemented boreholes intersecting groundwater zones. To help fill gaps resulting from sparse groundwater wells, temperature and resistivity borehole log data could be analyzed to locate anomalies that identify potential areas where relatively warm or saline water from deeper hydrocarbon-bearing formations is present in groundwater.

California↗

USGS1987

Mineral Resources of the Antelope Wilderness Study Area, Nye County, Nevada

At the request of the U.S. Bureau of land Management, 83,100 acres of the Antelope Wilderness Study Area (NV-4)60-231/241) was studied. In this report the studied area is called the 'wilderness study area', or simply the 'study area.' No identified mineral or energy resources occur within the study area. The southern part of the area has moderate mineral resource potential for undiscovered gold and silver, and the Woodruff Formation in the southern part of the area has high resource potential for undiscovered vanadium, zinc, selenium, molybdenum, and silver (fig. 1). This assessment is based on field geochemical studies in 1984 and 1985 by the U.S. Bureau of Mines and field geochemical studies and geologic mapping by the U.S. Geological Survey in 1984 and 1985. The remainder of the study area has low resource potential for undiscovered gold, silver, lead, zinc, manganese, tin, and molybdenum. The study area also has low resource potential for undiscovered oil and gas resources. The Antelope Wilderness Study Area is about midway between Tonopah and Eureka, Nev., in the northern Hot Creek Range and southern Antelope Range of central Nevada. It is accessible by unimproved dirt roads extending 20 mi (miles) north from U.S. Highway 6 and 40 mi south from U.S. Highway 50 (fig. 2). Most of the study area consists of rugged mountainous terrain having approximately 2,600 ft (feet) of relief. The mountain range is a block tilted gently to the east and bounded on both sides by normal faults that dip steeply to moderately west and have major displacements. Most of the study area is underlain by a thick sequence of Tertiary volcanic rocks that predominantly consist of silicic ash-flow tuff, the Windous Butte Formation. Paleozoic and lower Mesozoic (see geologic time chart in appendix) marine sediments occur along the southern margin of the study area, and lower Paleozoic rocks are exposed in the northeast corner. The areas of exposed Paleozoic-Mesozoic rocks along the southern margin of the study area have moderate mineral resource potential for gold and silver in sediment-hosted, disseminated, epithermal (low-temperature) gold-silver deposits (fig. 1). These rocks consist of folded and thrust-faulted, fine-grained clastic sediments and limestone and dolomite that locally have been brecciated and hydrothermally altered. The alteration (locally, strong silicification) and geochemical associations of these rocks indicate a favorable environment for such deposits. Exploration for disseminated gold deposits in the same geologic environment is currently being conducted just south of the study area. The remainder of the study area has low resource potential for epithermal gold and silver vein deposits in the Tertiary volcanic rocks. The Cenozoic sedimentary basins adjacent to the fault-bounded mountain block have moderate potential for petroleum resources; the study area itself has low potential for petroleum resources.

Bulletin↗

USGS2007

Organic metamorphism in the Lower Mississippian-Upper Devonian Bakken shales. Part 1: Rock-Eval pyrolysis and vitrinite reflectance

Detailed organic geochemistry has been performed on a large number of Lower Mississippian-Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and 28 oils mainly from Mississippian Madison Group rocks from different basinal areas. Here we report results of Rock-Eval pyrolysis and vitrinite reflectance ( R o ) analyses. Variable paleoheat flows in the Williston Basin caused the threshold of intense hydrocarbon generation to occur at different depths in different basinal areas. In higher paleogeothermal gradient basinal areas, this event occurred at depths of 7,650-8,000 ft, and at 10,000 ft or deeper in lower paleogeothermal gradient areas of the Basin. Distinct organic metamorphic imprints in Williston Basin sediments were also caused by extreme, but variable, paleoheat flows in the basin, as well as secondary migration of crude oils from deep basinal source areas. The high paleoheat flows are postulated as being due to a Late Cretaceous - Paleocene aborted rift event. Only a small volume of Bakken shales in restricted areas of the Williston Basin was responsible for the oil found reservoired in Mississippian Madison Group rocks. However, this small shale volume has been responsible for a relatively large amount of crude oil. R o profiles in the Tertiary through Middle Jurassic rocks in the Williston Basin had steep, linear R o versus depth gradients, with strong reversals of R o values occurring in the Lower Jurassic rocks. The lower Mesozoic through Paleozoic rocks of the Basin had strongly suppressed R o values compared to the values in the Tertiary through Middle Jurassic rocks. This was especially true of the R o values in the Bakken shales. This R o suppression was due to a change in organic matter (OM) type from oxygen-rich terrestrially derived OM in the younger rocks, to a hydrogen-rich marine derived OM in the deeper, older rocks. The threshold of intense oil generation (TIHG) occurred in the Bakken shales of the Williston Basin at R o values somewhere between 0.9 and 1.7% (best estimate 0.9), as would be read in oxygen-rich OM. Much higher burial temperatures (and consequently R o values) than usually held to be necessary were required for both the TIHG as well as mainstage hydrocarbon generation in the Bakken shales. These results are most likely applicable in general to source rocks with hydrogen-rich OM. The data of this study have major implications to petroleum exploration as well as to petroleum resource assessment.

Journal of Petroleum Geology↗

USGS2019

Geology and assessment of undiscovered oil and gas resources of the Northwest Canada Interior Basins Province, Arctic Canada

The Northwest Canada Interior Basins Province is bounded by the Mackenzie and Richardson Mountains on the southwest and west, by the Eskimo Lakes Arch on the northwest, and by the erosional limit of Paleozoic strata on the east. It lies within the far northwest part of the Paleozoic continent of Laurentia. During early Paleozoic time, it was part of a passive margin formed when the Neoproterozoic supercontinent Rodinia broke apart. A Cambrian marine transgressive sequence gave way to an evaporitic intrashelf basin, succeeded by a westward-building carbonate bank from Late Cambrian through Middle Devonian time. In Late Devonian and early Carboniferous time, the region was buried by a thick succession of south-prograding clastic strata derived from orogenic belts to the northeast and north. A subsequent period of inactivity and erosion persisted until sedimentation resumed as the opening of the Canada Basin initiated an Early Cretaceous marine transgression over much of the region. Later in Cretaceous time, clastic strata derived from Cordilleran uplifts to the southwest began to prograde north, ending with eventual Laramide uplift and deformation in latest Cretaceous and Paleogene time. Two petroleum systems are known within the province. A petroleum system in Cambrian to Middle Devonian strata, sourced by alginitic Cambrian shales and sealed by Cambrian evaporites, is proven by modest gas discoveries in the Colville Hills; generation is attributed to burial under the Upper Devonian clastic wedge. An Upper Devonian petroleum system, proven by the presence of the 250-million-barrel Norman Wells field at the southern edge of the province, was sourced by organic-rich shale of the Canol Formation. Generation is similarly inferred to have been driven by burial beneath the Devonian clastic wedge, perhaps augmented locally by additional Cretaceous burial. Potential reservoirs include Devonian reefs and sandstones stratigraphically below and laterally equivalent to the source rocks, as well as overlying sandstones in the clastic wedge. Subordinate source rocks could include organic-rich shales within the clastic wedge. Principal risks to the lower Paleozoic petroleum system include (1) inadequate reservoir volume for a field of the minimum size and (2) petroleum loss by remigration caused by Laramide deformation. One lower Paleozoic assessment unit (AU) was quantitatively assessed, with estimated resources of 0 to 117 million barrels of oil (MMBO), mean 23 MMBO; and 0 to 1,364 billion cubic feet of gas (BCFG), mean 310 BCFG. The principle risks to the Devonian petroleum system were considered to be (1) lack of preservation due to extensive erosion before the Cretaceous, and (2) inadequate reservoir volume, because the best potential reservoir strata, Devonian reefs, may be absent throughout most of the province owing to either lack of deposition or erosion. These risks were sufficiently high that the single AU defined in the Devonian petroleum system was not quantitatively assessed, because the chance of a field of the minimum size, 50 million barrels of oil equivalent, was estimated to be only 0.1.

Northwest Canada Interior Basins Province↗

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↗

USGS1979

United States Geological Survey Yearbook, fiscal year 1978

Fiscal year 1978 saw the U.S. Geological Survey continuing to perform its basic historical missions of collecting, analyzing, and disseminating information about the Earth, its processes, and its water and mineral resources. Classifying Federal lands and supervising lessee mineral extraction operations on those lands were also major Survey concerns during the year. In addition, substantial progress was made in the exploration and assessment of the petroleum potential of the National Petroleum Reserve in Alaska, a recently assigned mission. These basic missions found expression in a wide range of program activities and interests as diverse as the sands of Mars and the volcanoes of Hawaii. Programs included assessment of numerous potential energy and mineral resources, study of earthquakes and other geologic hazards, appraisal of the magnitude and quality of the Nation's water resources, and supervision of lease operations on Federal lands. The Survey also was involved in developing data on land use and producing topographic, geologic, and hydrologic maps for public and private use. In cooperation with other Federal agencies, the Survey participated in studies under the U.S. Climate Program and continued its analysis of data received from the two Viking landers on the surface of Mars. On April 3, 1978, Dr. H. William Menard became the 10th Director of the U.S. Geological Survey. Dr. Menard, who, until his appointment, was Professor of Geology at the Scripps Institution of Oceanography, San Diego, Calif., brings to the Director's post the experience gained in a long and successful career as a marine geologist and oceanographer. He succeeds Dr. Vincent E. McKelvey, who continues with the Survey as a senior research scientist.

Yearbook↗

USGS2003

Total petroleum systems of the Paleozoic and Jurassic, Greater Ghawar Uplift and adjoining provinces of central Saudi Arabia and northern Arabian-Persian Gulf

The greater Paleozoic and Jurassic petroleum systems of the Arabian Peninsula form two of the most prolific petroleum-producing systems in the world. Source rocks of these systems extend throughout the eastern Arabian Peninsula and Arabian-Persian Gulf. Primary elements of these Paleozoic and Jurassic petroleum systems - source, reservoir, and seal rocks - are of great areal extent and exceptional quality. The combination of these regionally extensive, exceptional petroleum-system elements, and the formation of large subtle structural closures prior to, or coincident with, peak oil generation and migration, have produced oil and gas fields with reserve volumes second to none. Two total petroleum systems (TPS), one of Paleozoic age and one of Jurassic age, in the central part of the Arabian Peninsula are identified in this report. The Central Arabia Qusaiba-Paleozoic TPS and the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS of Jurassic age encompass the Greater Ghawar Uplift Province (USGS Province 2021) and portions of adjoining geologic provinces. Structures that trap hydrocarbons in these systems are mostly (1) large, gentle anticlines formed from reactivated basement fault blocks, (2) salt domes that resulted from halokinesis, or (3) structural traps resulting from a combination of these two processes. Major tectonic events that created these structures resulted from early Zagros rifting during the Early Triassic and two Alpine tectonic episodes that occurred during the Late Cretaceous and middle to late Tertiary. Hydrocarbons of the Central Arabia Qusaiba-Paleozoic TPS are sourced mainly by organic-rich, so-called "hot shale" that occurs in the basal part of the Lower Silurian Qusaiba Member of the Qalibah Formation. Oil and gas are produced mainly from sandstones of the Permian Unayzah and Devonian Jauf Formations, and from basal transgressive marine sandstones and cyclic, dolomitic shelf-carbonates of the Late Permian Khuff Formation. Two assessment units (AU) are recognized in the Central Arabia Qusaiba-Paleozoic TPS that are related to type of structural trap and presence of underlying Infracambrian salt: (1) the onshore Central Arch Horst-Block Anticlinal Oil and Gas AU, and (2) the mostly offshore North Gulf Salt Basin Structural Gas AU. The mean total volume of undiscovered resource for the Central Arabia Qusaiba-Paleozoic TPS is estimated at about 108 billion barrels of oil equivalent (BBOE). Oil of the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS is sourced by organic-rich, marine carbonates of the Jurassic Tuwaiq Mountain and Hanifa Formations. These source rocks were deposited in two of three intraplatform basins during the Jurassic and, where thermally mature, have generated a superfamily of oils with distinctive geochemical characteristics. Oils were generated and expelled from these source rocks beginning in the Cretaceous at about 75 Ma. Hydrocarbon production is from 3 cyclic carbonate-rock reservoirs of the Arab Formation that are sealed by overlying anhydrite. Several giant and supergiant fields, including the world's largest oil field at Ghawar, Saudi Arabia, produce mostly from the Arab carbonate-rock reservoirs. Two assessment units are also recognized in the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS that are similarly related to structural trap style and presence of underlying Infracambrian salt: (1) an onshore Horst-Block Anticlinal Oil AU, and (2) a mostly offshore Salt-Involved Structural Oil AU. The mean total volume of undiscovered resource for the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS is estimated at about 49 billion barrels of oil equivalent (42 billion barrels of oil, 34 trillion feet of gas, and 1.4 billion barrels of natural gas liquids).

Arabian-Persian Gulf↗

USGS1980

Summary of regional geology, petroleum potential, resource assessment and environmental considerations for oil and gas lease sale area #56

This report summarizes our general knowledge of the petroleum potential, as well as problems and hazards associated with development of petroleum resources in the area proposed for nominations for lease sale number 56. This area includes the U.S. eastern continental margin from the North Carolina-Virginia border south to approximately Cape Canaveral, Florida and from three miles from shore, seaward to include the upper Continental Slope and inner Blake Plateau. The area for possible sales is shown in figure 1; major physiographic features of the region are shown in figure 2. No wells have been drilled for petroleum within this proposed lease area and no significant commercial production has been obtained onshore in the Southeast Georgia Embayment. The COST GE-1 stratigraphic test well, drilled on the Continental Shelf off Jacksonville, Fla. (fig- 1), reached basement at 3,300 m. The bottom third of the section consists of dominantly continental rocks that are typically poor sources of petroleum (Scholle, 1979) and the rocks that contain organic carbon adequate for generation of petroleum at the well are seen in seismic profiles always at shallow subbottom depths, so they probably have not reached thermal maturity. However, seismic profiles indicate that the sedimentary deposits thicken markedly in a seaward direction where more of the section was deposited under marine conditions; therefore, commercial accumulations of petroleum offshore are more likely. Several potential sources of environmental hazard exist. Among the most important are hurricanes, the Gulf Stream, and earthquakes. The potential danger from high wind, waves, storm surges, and storm-driven currents associated with hurricanes is obvious. Evidence for significant bottom scour by the Gulf Stream is abundant; such scour is a threat to the stability of bottom-mounted structures. The fast-flowing water also will hamper floating drill rigs and control of drill strings. A major earthquake of about magnitude 6.8 struck Charleston in 1886; it may have been associated with a zone of active seismicity that crosses South Carolina. The likelihood of a repetition of the 1886 event is presently not predictable but a seismic hazard must be assumed to exist.

Open-File Report↗

USGS1997

Geochemistry of oils from the Junggar basin, northwest China

The Junggar basin of northwestern China is a structural basin containing a thick sequence of Paleozoic-Pleistocene rocks with estimated oil reserves of as much as 5 billion bbl. Analyses of 19 oil samples from nine producing fields and two oil-stained cores in the Junggar basin revealed the presence of at least five genetic oil types. The geochemistry of the oils indicates source organic matter deposited in fresh to brackish lake and marine environments, including coaly organic matter sources. The volumetrically most important oil type discovered to date is produced from Late Carboniferous-Middle Triassic reservoirs in the giant Karamay field and nearby fields located along the northwestern margin of the Junggar basin. Oil produced from the Mahu field, located downdip in a depression east of the Karamay field, is from a different source than Karamay oils. Unique oil types are also produced from an upper Permian reservoir at Jimusar field in the southeastern part of the basin, and from Tertiary (Oligocene) rocks at Dushanzi field and Lower Jurassic rocks at Qigu field, both located along the southern margin of the basin. Previous studies have demonstrated the presence of Upper Permian source rocks, and the possibility of Mesozoic or Tertiary sources has been proposed, but not tested by geochemical analysis, although analyses of some possible Jurassic coal source rocks have been reported. Our findings indicate that several effective source rocks are present in the basin, including local sources of Mesozoic or younger age for oil accumulations along the southern and southeastern margins of the basin. Future exploration or assessment of petroleum potential of the basin can be improved by considering the geological relationships among oil types, possible oil source rocks, and reservoirs.

Junggar Basin↗

USGS2017

Groundwater quality in the Western San Joaquin Valley study unit, 2010: California GAMA Priority Basin Project

Water quality in groundwater resources used for public drinking-water supply in the Western San Joaquin Valley (WSJV) was investigated by the USGS in cooperation with the California State Water Resources Control Board (SWRCB) as part of its Groundwater Ambient Monitoring and Assessment (GAMA) Program Priority Basin Project. The WSJV includes two study areas: the Delta–Mendota and Westside subbasins of the San Joaquin Valley groundwater basin. Study objectives for the WSJV study unit included two assessment types: (1) a status assessment yielding quantitative estimates of the current (2010) status of groundwater quality in the groundwater resources used for public drinking water, and (2) an evaluation of natural and anthropogenic factors that could be affecting the groundwater quality. The assessments characterized the quality of untreated groundwater, not the quality of treated drinking water delivered to consumers by water distributors. The status assessment was based on data collected from 43 wells sampled by the U.S. Geological Survey for the GAMA Priority Basin Project (USGS-GAMA) in 2010 and data compiled in the SWRCB Division of Drinking Water (SWRCB-DDW) database for 74 additional public-supply wells sampled for regulatory compliance purposes between 2007 and 2010. To provide context, concentrations of constituents measured in groundwater were compared to U.S. Environmental Protection Agency (EPA) and SWRCB-DDW regulatory and non-regulatory benchmarks for drinking-water quality. The status assessment used a spatially weighted, grid-based method to estimate the proportion of the groundwater resources used for public drinking water that has concentrations for particular constituents or class of constituents approaching or above benchmark concentrations. This method provides statistically unbiased results at the study-area scale within the WSJV study unit, and permits comparison of the two study areas to other areas assessed by the GAMA Priority Basin Project statewide. Groundwater resources used for public drinking water in the WSJV study unit are among the most saline and most affected by high concentrations of inorganic constituents of all groundwater resources used for public drinking water that have been assessed by the GAMA Priority Basin Project statewide. Among the 82 GAMA Priority Basin Project study areas statewide, the Delta–Mendota study area ranked above the 90th percentile for aquifer-scale proportions of groundwater resources having concentrations of total dissolved solids (TDS), sulfate, chloride, manganese, boron, chromium(VI), selenium, and strontium above benchmarks, and the Westside study area ranked above the 90th percentile for TDS, sulfate, manganese, and boron. In the WSJV study unit as a whole, one or more inorganic constituents with regulatory or non-regulatory, health-based benchmarks were present at concentrations above benchmarks in about 53 percent of the groundwater resources used for public drinking water, and one or more organic constituents with regulatory health-based benchmarks were detected at concentrations above benchmarks in about 3 percent of the resource. Individual constituents present at concentrations greater than health-based benchmarks in greater than 2 percent of groundwater resources used for public drinking water included: boron (51 percent, SWRCB-DDW notification level), chromium(VI) (25 percent, SWRCB-DDW maximum contaminant level (MCL)), arsenic (10 percent, EPA MCL), strontium (5.1 percent, EPA Lifetime health advisory level (HAL)), nitrate (3.9 percent, EPA MCL), molybdenum (3.8 percent, EPA HAL), selenium (2.6 percent, EPA MCL), and benzene (2.6 percent, SWRCB-DDW MCL). In addition, 50 percent of the resource had TDS concentrations greater than non-regulatory, aesthetic-based SWRCB-DDW upper secondary maximum contaminant level (SMCL), and 44 percent had manganese concentrations greater than the SWRCB-DDW SMCL. Natural and anthropogenic factors that could affect the groundwater quality were evaluated by using results from statistical testing of associations between constituent concentrations and values of potential explanatory factors, inferences from geochemical and age-dating tracer results, and by considering the water-quality results in the context of the hydrogeologic setting of the WSJV study unit. Natural factors, particularly the lithologies of the source areas for groundwater recharge and of the aquifers, were the dominant factors affecting groundwater quality in most of the WSJV study unit. However, where groundwater resources used for public supply included groundwater recharged in the modern era, mobilization of constituents by recharge of water used for irrigation also affected groundwater quality. Public-supply wells in the Westside study area had a median depth of 305 m and primarily tapped groundwater recharged hundreds to thousands of years ago, whereas public-supply wells in the Delta–Mendota study area had a median depth of 85 m and primarily tapped either groundwater recharged within the last 60 years or groundwater consisting of mixtures of this modern recharge and older recharge. Public-supply wells in the WSJV study unit are screened in the Tulare Formation and zones above and below the Corcoran Clay Member are used. The Tulare Formation primarily consists of alluvial sediments derived from the Coast Ranges to the west, except along the valley trough at the eastern margin of the WSJV study unit where the Tulare Formation consists of fluvial sands derived from the Sierra Nevada to the east. Groundwater from wells screened in the Sierra Nevada sands had manganese-reducing or manganese- and iron-reducing oxidation-reduction (redox) conditions. These redox conditions commonly were associated with elevated arsenic or molybdenum concentrations, and the dominance of arsenic(III) in the dissolved arsenic supports reductive dissolution of iron and manganese oxyhydroxides as the mechanism. In addition, groundwater from many wells screened in Sierra Nevada sands contained low concentrations of nitrite or ammonium, indicating reduction of nitrate by denitrification or dissimilatory processes, respectively. Geology of the Coast Ranges westward of the study unit strongly affects groundwater quality in the WSJV. Elevated concentrations of TDS, sulfate, boron, selenium and strontium in groundwater were primarily associated with aquifer sediments and recharge derived from areas of the Coast Ranges dominated by Cretaceous-to-Miocene age, organic-rich, reduced marine shales, known as the source of selenium in WSJV soils, surface water, and groundwater. Low sulfur-isotopic values (δ34S) of dissolved sulfate indicate that the sulfate was largely derived from oxidation of biogenic pyrite from the shales, and correlations with trace element concentrations, geologic setting, and groundwater geochemical modeling indicated that distributions of sulfate, strontium, and selenium in groundwater were controlled by dissolution of secondary sulfate minerals in soils and sediments. Elevated concentrations of chromium(VI) were primarily associated with aquifer sediments and recharge derived from areas of the Coast Ranges dominated by the Franciscan Complex and ultramafic rocks. The Franciscan Complex also has boron-rich, sodium-chloride dominated hydrothermal fluids that contribute to elevated concentrations of boron and TDS. Groundwater from wells screened in Coast Ranges alluvium was primarily oxic and relatively alkaline (median pH value of 7.55) in the Delta–Mendota study area, and primarily nitrate-reducing or suboxic and alkaline (median pH value of 8.4) in the Westside study area. Many groundwater samples from those wells have elevated concentrations of arsenic(V), molybdenum, selenium, or chromium(VI), consistent with desorption of metal oxyanions from mineral surfaces under those geochemical conditions. High concentrations of benzene were associated with deep wells located in the vicinity of petroleum deposits at the southern end of the Westside study area. Groundwater from these wells had premodern age and anoxic geochemical conditions, and the ratios among concentrations of hydrocarbon constituents were different from ratios found in fuels and combustion products, which is consistent with a geogenic source for the benzene rather than contamination from anthropogenic sources. Water stable-isotope compositions, groundwater recharge temperatures, and groundwater ages were used to infer four types of groundwater: (1) groundwater derived from natural recharge of water from major rivers draining the Sierra Nevada; (2) groundwater primarily derived from natural recharge of water from Coast Ranges runoff; (3) groundwater derived from recharge of pumped groundwater applied to the land surface for irrigation; and (4) groundwater derived from recharge during a period of much cooler paleoclimate. Water previously used for irrigation was found both above and below the Corcoran Clay, supporting earlier inferences that this clay member is no longer a robust confining unit. Recharge of water used for irrigation has direct and indirect effects on groundwater quality. Elevated nitrate concentrations and detections of herbicides and fumigants in the Delta–Mendota study area generally were associated with greater agricultural land use near the well and with water recharged during the last 60 years. However, the extent of the groundwater resource affected by agricultural sources of nitrate was limited by groundwater redox conditions sufficient to reduce nitrate. The detection frequency of perchlorate in Delta–Mendota groundwater was greater than expected for natural conditions. Perchlorate, nitrate, selenium, and strontium concentrations were correlated with one another and were greater in groundwater inferred to be recharge of previously pumped groundwater used for irrigation. The source of the perchlorate, selenium, and strontium appears to be salts deposited in the soils and sediments of the arid WSJV that are dissolved and flushed into groundwater by the increased amount of recharge caused by irrigation. In the Delta–Mendota study area, the groundwater with elevated concentrations of selenium was found deeper in the aquifer system than it was reported by a previous study 25 years earlier, suggesting that this transient front of groundwater with elevated concentrations of constituents derived from dissolution of soil salts by irrigation recharge is moving down through the aquifer system and is now reaching the depth zone used for public drinking water supply.

California↗

USGS2020

EMD Gas Hydrates Committee annual report

Global research on the potential commercial viability of gas extraction from gas hydrates is continuing, predominantly in Asia and in the United States, where recent efforts have focused on the exploration and characterization of gas hydrate petroleum systems and conducting controlled production tests of gas hydrate deposits hosted in mostly sand-rich reservoir systems. In 2017, gas hydrate production testing was conducted in marine settings in the offshore of Japan and China. An additional test was conducted in the Shenhu region of the South China Sea in 2020 to further evaluate the effectiveness of various well completion technologies to produce gas from gas hydrates. Late in 2018, a research partnership led by the U.S. Department of Energy National Energy Technology Laboratory and the Japan Oil, Gas and Metals National Corporation established a new Alaska North Slope test site for an extended gas hydrate production pilot with the completion of a stratigraphic test well. With the successful completion of the Prudhoe Bay Unit Hydrate-01 stratigraphic test well, planning is now underway for drilling of three additional wells at the Alaska test site, which will include a geoscience data well and two production test wells. In 2019, the Government of India released the results of one of the most comprehensive gas hydrate scientific drilling investigations ever undertaken, the leadership of the Indian National Gas Hydrate Program Expedition 02 reported on the discovery of several significant gas hydrate accumulations that were considered suitable for future gas hydrate production testing. In September of 2019, the U.S. Geological Survey released a new assessment of the technically recoverable gas hydrate resources on the Alaska North Slope. In 2018, the University of Texas at Austin released a comprehensive report describing the operational and initial technical results of the UT-GOM2-1 Hydrate Pressure Coring Expedition, which drilled and partially cored two wells in Green Canyon Block 955 in the deepwater Gulf of Mexico. The results of these recently complete gas hydrate geologic and production studies have been further reviewed in this AAPG-EMD Gas Hydrate Committee report.

Alaska↗