Search USGSSearch

SEARCH · Search USGS

Results for “World Oil”

Search indexed USGS publications on groundwater, aquifers, geologic maps, mineral resources and earthquakes. Explore source records by subject and place.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 145 records · Page 8Linked to original sources

Gas shale/oil shale

The production of natural gas from shales continues to increase in North America, and shale gas exploration is on the rise in other parts of the world since the previous report by this committee was published by American Association of Petroleum Geologists, Energy Minerals Division (2009). For the United States, the volume of proved reserves of natural gas increased 11% from 2008 to 2009, the increase driven largely by shale gas development (Energy Information Administration 2010c). Furthermore, shales have increasingly become targets of exploration for oil and condensate as well as gas, which has served to greatly expand their significance as ‘‘unconventional’’ petroleum reservoirs. This report provides information about specific shales across North America and Europe from which gas (biogenic or thermogenic), oil, or natural gas liquids are produced or is actively being explored. The intent is to reflect the recently expanded mission of the Energy Minerals Division (EMD) Gas Shales Committee to serve as a single point of access to technical information on shales regardless of the type of hydrocarbon produced from them. The contents of this report were drawn largely from contributions by numerous members of the EMD Gas Shales Advisory Committee, with much of the data being available from public websites such as state or provincial geological surveys or other public institutions. Shales from which gas or oil is being produced in the United States are listed in alphabetical order by shale name. Information for Canada is presented by province, whereas for Europe, it is presented by country.

Natural Resources Research

California State Waters Map Series: Offshore of Coal Oil Point, California

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 (to about 100 m) subsurface geology. The Offshore of Coal Oil Point map area lies within the central Santa Barbara Channel region of the Southern California Bight. This geologically complex region forms a major biogeographic transition zone, separating the cold-temperate Oregonian province north of Point Conception from the warm-temperate California province to the south. The map area is in the southern part of the Western Transverse Ranges geologic province, which is north of the California Continental Borderland. Significant clockwise rotation—at least 90°—since the early Miocene has been proposed for the Western Transverse Ranges province, and geodetic studies indicate that the region is presently undergoing north-south shortening. Uplift rates (as much as 2.0 mm/yr) that are based on studies of onland marine terraces provide further evidence of significant shortening. The cities of Goleta and Isla Vista, the main population centers in the map area, are in the western part of a contiguous urban area that extends eastward through Santa Barbara to Carpinteria. This urban area is on the south flank of the east-west-trending Santa Ynez Mountains, on coalescing alluvial fans and uplifted marine terraces underlain by folded and faulted Miocene bedrock. In the map area, the relatively low-relief, elevated coastal bajada narrows from about 2.5 km wide in the east to less than 500 m wide in the west. Several beaches line the actively utilized coastal zone, including Isla Vista County Park beach, Coal Oil Point Reserve, and Goleta Beach County Park. The beaches are subject to erosion each winter during storm-wave attack, and then they undergo gradual recovery or accretion during the more gentle wave climate of the late spring, summer, and fall months. The Offshore of Coal Oil Point map area lies in the central part of the Santa Barbara littoral cell, which is characterized by littoral drift to the east-southeast. Longshore drift rates have been reported to range from about 160,000 to 800,000 tons/yr, averaging 400,000 tons/yr. Sediment supply to the western and central parts of the littoral cell, including the map area, is largely from relatively small transverse coastal watersheds. Within the map area, these coastal watersheds include (from east to west) Las Llagas Canyon, Gato Canyon, Las Varas Canyon, Dos Pueblos Canyon, Eagle Canyon, Tecolote Canyon, Winchester Canyon, Ellwood Canyon, Glen Annie Canyon, and San Jose Creek. The Santa Ynez and Santa Maria Rivers, the mouths of which are about 100 to 140 km northwest of the map area, are not significant sediment sources because Point Conception and Point Arguello provide obstacles to downcoast sediment transport and also because much of their sediment load is trapped in dams. The Ventura and Santa Clara Rivers, the mouths of which are about 45 to 55 km southeast of the map area, are much larger sediment sources. Still farther east, eastward-moving sediment in the littoral cell is trapped by Hueneme and Mugu Canyons and then transported to the deep-water Santa Monica Basin. The offshore part of the map area consists of a relatively flat and shallow continental shelf, which dips gently seaward (about 0.8° to 1.0°) so that water depths at the shelf break, roughly coincident with the California’s State Waters limit, are about 90 m. This part of the Santa Barbara Channel is relatively well protected from large Pacific swells from the north and northwest by Point Conception and from the south and southwest by offshore islands and banks. The shelf is underlain by variable amounts of upper Quaternary marine and fluvial sediments deposited as sea level fluctuated in the late Pleistocene. The large (130 km2) Goleta landslide complex lies along the shelf break in the southern part of the map area. This compound slump complex may have been initiated more than 200,000 years ago, but it also includes three recent failures that may have been generated between 8,000 to 10,000 years ago. A local, 5- to 10-m-high tsunami may have been generated from these failure events. The map area has had a long history of hydrocarbon development, which began in 1928 with discovery of the Ellwood oil field. Subsequent discoveries in the offshore include South Ellwood offshore oil field, Coal Oil Point oil field, and Naples oil and gas field. Development of South Ellwood offshore field began in 1966 from platform “Holly,” the last platform to be installed in California’s State Waters. The area also is known for “the world’s most spectacular marine hydrocarbon seeps,” and large tar seeps are exposed on beaches east of the mouth of Goleta Slough. Offshore seeps adjacent to South Ellwood oil field release about 40 tons per day of methane and about 19 tons per day of ethane, propane, butane, and higher hydrocarbons. Seafloor habitats in the broad Santa Barbara Channel region consist of significant amounts of soft sediment and isolated areas of rocky habitat that support kelp-forest communities nearshore and rocky-reef communities in deep water. The potential marine benthic habitat types mapped in the Offshore of Coal Oil Point map area are directly related to its Quaternary geologic history, geomorphology, and active sedimentary processes. These potential habitats, which lie primarily within the Shelf (continental shelf) but also partly within the Flank (basin flank or continental slope) megahabitats, range from soft, unconsolidated sediment to hard sedimentary bedrock. This heterogeneous seafloor provides promising habitat for rockfish, groundfish, crabs, shrimp, and other marine benthic organisms.

California

Assessment of the undiscovered oil and gas of the Senegal province, Mauritania, Senegal, the Gambia, and Guinea-Bissau, northwest Africa

Undiscovered, conventional oil and gas resources were assessed in the Senegal Province as part of the U.S. Geological Survey World Petroleum Assessment 2000 (U.S. Geological Survey World Energy Assessment Team, 2000). Although several total petroleum systems may exist in the province, only one composite total petroleum system, the Cretaceous-Tertiary Composite Total Petroleum System, was defined with one assessment unit, the Coastal Plain and Offshore Assessment Unit, having sufficient data to allow quantitative assessment. The primary source rocks for the Cretaceous-Tertiary Composite Total Petroleum System are the Cenomanian-Turonian marine shales. The Turonian shales can be as much as 150 meters thick and contain Type II organic carbon ranging from 3 to 10 weight percent. In the Senegal Province, source rocks are mature even when situated at depths relatively shallow for continental passive margin basins. Reservoir rocks consist of Upper Cretaceous sandstones and lower Tertiary clastic and carbonate rocks. The Lower Cretaceous platform carbonate rocks (sealed by Cenomanian shales) have porosities ranging from 10 to 23 percent. Oligocene carbonate rock reservoirs exist, such as the Dome Flore field, which contains as much as 1 billion barrels of heavy oil (10? API, 1.6 percent sulfur) in place. The traps are a combination of structural closures and stratigraphic pinch-outs. Hydrocarbon production in the Senegal Province to date has been limited to several small oil and gas fields around Cape Verde (also known as the Dakar Peninsula) from Upper Cretaceous sandstone reservoirs bounded by normal faults, of which three fields (two gas and one oil) exceed the minimum size assessed in this study (1 MMBO; 6 BCFG). Discovered known oil resources in the Senegal Province are 10 MMBO, with known gas resources of 49 BCFG (Petroconsultants, 1996). This study estimates that 10 percent of the total number of potential oil and gas fields (both discovered and undiscovered) of at least the minimum size have been discovered. The estimated mean size and number of assessed, undiscovered oil fields are 13 MMBO and 13 fields, respectively, whereas the mean size and number of undiscovered gas fields are estimated to be 50 BCFG and 11 fields. The mean estimates for undiscovered conventional petroleum resources are 157 MMBO, 856 BCFG, and 43 MMBNGL (table 2). The mean sizes of the largest anticipated undiscovered oil and gas fields are 66 MMBO and 208 BCFG, respectively. The Senegal Province is underexplored considering its large size. The province has hydrocarbon potential in both the offshore and onshore, and undiscovered gas resources may be significant and accessible in areas where the zone of oil generation is relatively shallow.

Bulletin

The Putumayo-Oriente-Maranon Province of Colombia, Ecuador, and Peru; Mesozoic-Cenozoic and Paleozoic petroleum systems

This report is an evaluation of oil and gas resources for petroleum systems of the Putumayo-Oriente-Maranon province of Columbia, Ecuador, and Peru. This assessment is a product of the World Energy Project of the U.S. Geological Survey, under the direction of Thomas Ahlbrandt. Described in this explanation of the petroleum geology of the Putumayo-Oriente-Maranon province are thermal maturation of hydrocarbon source rocks, primary reservoir formations, areas and volumes of oil and (or) gas production, and the history of exploration. Complete oil and gas resource assessment results are planned for a later publication, although some data and results are contained in this report.

Data Series

Mechanisms of impact and potential recovery of nearshore vertebrate predators following the 1989 Exxon Valdez oil spill

The 1989 spill of some 42 million L of crude oil into Prince William Sound, Alaska, represents not only the largest tanker spill in United States history, but the world’s largest spill in northern waters. Acute effects have been studied extensively. However, efforts to quantify the spill’s long-term chronic effects and develop defensible restoration measures have been plagued by varying levels of scientific uncertainty. That such uncertainty exists is not unexpected. The spill occurred in Prince William Sound’s highly variable physical setting typified by its complex oceanography and fjord-like geomorphology. Additionally, uncertainty was driven by the scarcity of precise pre-spill population estimates and spotty life-history information for most species. The research reported herein in, structured in eight primary papers and 27 supporting papers (appendices), documents the state of recovery and assessments of continuing constraints to population recovery for four vertebrate predators (sea otter Enhydra lutris , harlequin duck Histrionicus histrionicus , river otter Lontra canadensis , and pigeon guillemot Cepphus columba ) whose recovery status remained uncertain some 5 years after the Exxon Valdez oil spill. These species are used in a collective weight of evidence approach to better understand the process of coastal community recovery. Each species is examined for the strength of information it brings in health, population, and trophic metrics to support or reject the hypothesis of continuing oil effects in the nearshore system versus the alternatives that food constraints or demographic bottlenecks limit these focal species. While data for individual species contain various levels of uncertainty, scientific confidence is developed in the following picture when examined across species, metric, and hypothesis: Within the nearshore coastal environment, sporadic releases of residual oil are occurring, and benthic species, primarily invertebrates, are being exposed in a temporally and spatially patchy manner sufficient to transport oil up through the food chain. Thus, for the two invertebrate-feeders, sea otter and harlequin duck, evidence exists over several lines of investigation to suggest that local-scale populations continue to be constrained not by food availability or natural demographic processes, but by increased levels of mortality coincident with continued exposure to residual oil. Conversely, weight of evidence suggests that only limited direct oil-related effects are being transferred through the fish trophic pathway. Sufficient evidence suggests recovery is occurring in river otter populations, while the lack of recovery in pigeon guillemot may be attributed to food limitations (both natural and indirectly related to the spill) and/or slow demographic response to initial acute mortalities. Individual lines of investigation often contained uncertainty, but the collective weight of evidence presented in this multipaper volume indicates lack of full recovery of the nearshore ecosystem from the Exxon Valdez oil spill nearly a decade following the event. Integrated, multispecies approaches can allow sufficient weight of evidence to develop despite inherent system variability or data limitations and, thus, facilitate both better societal understanding of such pollution events and development of appropriate restoration responses.

Alaska

Assessment of undiscovered conventional oil and gas resources of the Arabian Peninsula and Zagros Fold Belt, 2012

Using a geology-based assessment methodology, the U.S. Geological Survey estimated means of 86 billion barrels of oil and 336 trillion cubic feet of undiscovered natural gas resources in the Arabian Peninsula and Zagros Fold Belt. The USGS assessed the potential for undiscovered conventional oil and gas accumulations within the Arabian Peninsula and Zagros Fold Belt as part of the USGS World Petroleum Resources Project. Twenty-three assessment units within seven petroleum systems were quantitatively assessed in this study, which represents a reassessment of this area last published in 2000.

Fact Sheet

Areas of historical oil and gas exploration and production in the United States

This report contains maps and associated spatial data showing historical oil and gas exploration and production in the United States. Because of the proprietary nature of many oil and gas well databases, the United States was divided into cells one-quarter square mile and the production status of all wells in a given cell was aggregated. Base-map reference data are included, using the U.S. Geological Survey (USGS) National Map, the USGS and American Geological Institute (AGI) Global GIS, and a World Shaded Relief map service from the ESRI Geography Network. A hardcopy map was created to synthesize recorded exploration data from 1859, when the first oil well was drilled in the U.S., to 2005. In addition to the hardcopy map product, the data have been refined and made more accessible through the use of Geographic Information System (GIS) tools. The cell data are included in a GIS database constructed for spatial analysis via the USGS Internet Map Service or by importing the data into GIS software such as ArcGIS. The USGS internet map service provides a number of useful and sophisticated geoprocessing and cartographic functions via an internet browser. Also included is a video clip of U.S. oil and gas exploration and production through time.

Data Series

Attenuation of barium, strontium, cobalt, and nickel plumes formed during microbial iron-reduction in a crude-oil-contaminated aquifer

We assessed the spatial distribution of 35 elements in aquifer sediments and groundwater of a crude-oil-contaminated aquifer and show evidence of the dissolution of barium (Ba), strontium (Sr), cobalt (Co), and nickel (Ni) during hydrocarbon oxidation coupled to historic microbial Fe(III)-reduction near the oil. Trace element plumes occur in the crude-oil-contaminated aquifer, where 50% Co, 47% Ni, 24% Ba, and 15% Sr have been mobilized from the sediment near the oil into groundwater, resulting in dissolved masses >33, 18, three, and two times greater than estimated dissolved masses prior to contamination, respectively. Ba 2+ and Ni 2+ concentrations exceeded the World Health Organization’s drinking-water guidelines of 700 and 20 μg/L, respectively. Sediments attenuate trace element plumes in two geochemically distinct zones, resulting in <0.01% total trace element masses dissolved in groundwater, despite the substantial mobilization near the oil body. Geochemical modeling of the modern Fe(III)-reducing zone suggests trace elements are likely attenuated via coprecipitation with/without sorption on iron carbonate precipitates. In the suboxic transition zone at the leading edge of the plume, Fe(III)-hydroxides sorb Ba 2+ , Sr 2+ , Co 2+ , and Ni 2+ . This study emphasizes that slow but persistent biogeochemical activity can substantially alter aquifer chemistry over decadal timeframes, a phenomenon we term biogeochemical gradualism.

Minnesota

Maps showing geology, oil and gas fields, and geologic provinces of the Arctic

Introduction This CD-ROM was compiled according to the methodology developed by the U.S. Geological Survey's World Energy Project . The geologic map of the Arctic was compiled and synthesized from the Circumpolar Geological Map of the Arctic, by Okulitch A.V., Lopatin B.G., and Jackson H.R., scale 1:6,000,000, published by the Geological Survey of Canada in 1989 (see References ). Specific details of the data sources are given in the metadata files on this CD-ROM. Map units were kept as close as possible to original map (more than 100 unique values). These Arctic maps were compiled using Environmental Systems Research Institute Inc. (ESRI) ARC/INFO software. Political boundaries and cartographic representations on this map are shown (with permission) from ESRI's ArcWorld 1:3M digital coverage. They have no political significance and are displayed as general reference only. Portions of this database covering the coastline, rivers and country boundaries contain proprietary property of ESRI. (© 1992 and 1996, Environmental Systems Research Institute Inc. All rights reserved. The bathymetric data were derived from the International Bathymetric Chart of the Arctic Ocean (IBCAO) which was downloaded from the NOAA web site. Oil and gas centerpoints were derived from Probe 4.0 database - proprietary property of Petroleum Information/Dwights LLC d/b/a/IHS Energy Group. Specific details of the data sources and map compilation are given in the metadata files on this CD-ROM.

Open-File Report

Monitoring long-term effects of offshore oil and gas development along the Southern California outer continental shelf and slope: Background environmental conditions in the Santa Maria Basin

Potential environmental impacts of materials discharged from oil and gas development and production platforms off the coast of southern California (Santa Maria Basin) are being monitored during an ongoing, long-term (fiveyear) field program. The study combines hypothesis testing of platform effects with basic research on the structure and dynamics of the regional ecosystem over a time series encompassing both seasonal and repeated annual scales. Oceanographic features and processes that are being measured focus on the benthos and include biological community indices and species abundances for hard-bottom and soft-bottom (macroinfauna and meiofauna) assemblages; levels and distributions of trace metals and hydrocarbons in bottom sediments, suspended particulates, animal tissues, and pore waters; water currents and otherphysical-oceanographicfeatures; various sedimentological properties (sediment grain size, total organic carbon, shear strength, distribution of mineral types, radioisotope profiles, and degrees of sediment mixing as a result of bioturbation); sediment and pollutant-transport processes; and animal-sediment-pollutant interactions. Synoptic measurement of these different environmental variables over the extended sampling period provides an opportunity to examine long-term variability in the benthic environment with respect to both natural and anthropogenic causes. Efforts to distinguish between natural variability and low-level cumulative impacts of drilling are given special attention. Results obtained during the first two years of sampling provide a basis for beginning to understand environmental processes and relations important in detecting and interpreting any subsequent impacts caused by drilling activities in this complex and productive region of the California outer continental shelf and slope. Background chemical, physical, and biological data generated during this period demonstrate that impacts of discharges from oil and gas operations should be detectable, if they occur, and should be distinguishable from natural environmental variability. Small inputs of barium and petroleum hydrocarbons have been detected and appear to be associated with the minor drilling activities that have occurred in the area thus far, however, these initial inputs have not led to any noticeable biological impacts. These initial results are hopefully of value for two reasons: (1) in providing a summary of basic chemical, physical, and biological features of the benthic environment within the Santa Maria Basin; and (2) in presenting information on research strategies that should be considered in designing studies dealing with similar resource-management problems in other parts of the world.

California

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

Total petroleum systems of the Illizi Province, Algeria and Libya; Tanezzuft-Illizi

Undiscovered conventional oil and gas resources were assessed within a total petroleum system of the Illizi Province (2056) as part of the U.S. Geological Survey World Petroleum Assessment 2000. The Illizi Province is in eastern Algeria and a small portion of western Libya. The province and its total petroleum system coincide with the Illizi Basin. Although several total petroleum systems may exist within the Illizi Province, only one “composite” total petroleum system is identified. This total petroleum system comprises a single assessment unit. The main source rocks are the Silurian Tanezzuft Formation (or lateral equivalents) and Middle to Upper Devonian mudstone. The total petroleum system was named after the oldest major source rock and the basin in which it resides. The estimated means of the undiscovered conventional petroleum volumes in the Tanezzuft-Illizi Total Petroleum System are 2,814 million barrels of oil (MMBO), 27,785 billion cubic feet of gas (BCFG), and 873 million barrels of natural gas liquids (MMBNGL).

Bulletin

Total petroleum systems of the Trias/Ghadames Province, Algeria, Tunisia, and Libya; the Tanezzuft-Oued Mya, Tanezzuft-Melrhir, and Tanezzuft-Ghadames

Undiscovered conventional oil and gas resources were assessed within total petroleum systems of the Trias/Ghadames Province (2054) as part of the U.S. Geological Survey World Petroleum Assessment 2000. The Trias/Ghadames Province is in eastern Algeria, southern Tunisia, and westernmost Libya. The province and its total petroleum systems generally coincide with the Triassic Basin. The province includes the Oued Mya Basin, Melrhir Basin, and Ghadames (Berkine) Basin. Although several total petroleum systems may exist within each of these basins, only three “composite” total petroleum systems were identified. Each total petroleum system occurs in a separate basin, and each comprises a single assessment unit. The main source rocks are the Silurian Tanezzuft Formation (or lateral equivalents) and Middle to Upper Devonian mudstone. Maturation history and the major migration pathways from source to reservoir are unique to each basin. The total petroleum systems were named after the oldest major source rock and the basin in which it resides. The estimated means of the undiscovered conventional petroleum volumes in total petroleum systems of the Trias/Ghadames Province are as follows [MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels of natural gas liquids]: Tanezzuft-Oued Mya 830 MMBO 2,341 BCFG 110 MMBNGL Tanezzuft-Melrhir 1,875 MMBO 4,887 BCFG 269 MMBNGL Tanezzuft-Ghadames 4,461 MMBO 12,035 BCFG 908 MMBNGL

Bulletin

Total petroleum systems of the Pelagian Province, Tunisia, Libya, Italy, and Malta; the Bou Dabbous, Tertiary and Jurassic-Cretaceous composite

Undiscovered conventional oil and gas resources were assessed within total petroleum systems of the Pelagian Province (2048) as part of the U.S. Geological Survey World Petroleum Assessment 2000. The Pelagian Province is located mainly in eastern Tunisia and northwestern Libya. Small portions of the province extend into Malta and offshore Italy. Although several petroleum systems may exist, only two ?composite? total petroleum systems were identified. Each total petroleum system comprises a single assessment unit. These total petroleum systems are called the Bou Dabbous?Tertiary and Jurassic-Cretaceous Composite, named after the source-rock intervals and reservoir-rock ages. The main source rocks include mudstone of the Eocene Bou Dabbous Formation; Cretaceous Bahloul, Lower Fahdene, and M?Cherga Formations; and Jurassic Nara Formation. Known reservoirs are in carbonate rocks and sandstone intervals throughout the Upper Jurassic, Cretaceous, and Tertiary sections. Traps for known accumulations include fault blocks, low-amplitude anticlines, high-amplitude anticlines associated with reverse faults, wrench fault structures, and stratigraphic traps. The estimated means of the undiscovered conventional petroleum volumes in total petroleum systems of the Pelagian Province are as follows: [MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels of natural gas liquids] Total Petroleum System MMBO BCFG MMBNGL Bou Dabbous?Tertiary 667 2,746 64 Jurassic-Cretaceous Composite 403 2,280 27

Bulletin

Land subsidence due to withdrawal of fluids

Land-surface subsidence due to the withdrawal of fluids by man has become relatively common in the United States since 1940 and has been described at several other places throughout the world. This paper reviews the known examples of appreciable land subsidence caused by fluid withdrawal. Those related to exploitation of oil and gas fields include Goose Creek, Texas; Wilmington, California; Lake Maracaibo, Venezuela; Niigata, Japan; and the Po Delta in Italy. The areas of major subsidence related to ground-water withdrawal include areas in Japan; Mexico City, Mexico; and Texas, Arizona, Nevada, and California. The areas of greatest extent and maximum subsidence are in California. The principles involved in the compaction of sediments and of aquifer systems, basically the increase in effective stress, are examined briefly, together with their application to subsidence problems involving head decline both under water table and confined conditions. The amount of compaction that a confined aquifer system will experience is a function of compressibility. Other factors that influence compaction (and, in part, compressibility) include particle size and shape, clay mineralogy, geochemistry of pore water in the clayey beds and of the water in contiguous aquifers, and secondary compression. Land subsidence has caused great damage in some areas. At several of these places, subsidence problems are being alleviated in one or more of several ways; these include (1) cessation of withdrawal and (2) increase or restoration of reservoir pressure by reduction in production rate, artificial recharge, or repressuring by injection of water. The greatest subsidence control measures are being taken at Wilmington, California, where subsidence that had reached 27 feet at the center now is nearly stopped; in addition, significant rebound has occurred.

Arizona, California, Colorado, Georgia, Honshu, Ne

Recent trends in Cuba’s mining and petroleum industries

In response to recent diplomatic developments between Cuba and the United States, the National Minerals Information Center compiled available information on the mineral industries of Cuba. This fact sheet highlights a new map and table that identify mines, mineral processing facilities, and petroleum facilities as well as information on location, operational status, and ownership. It also addresses the current status of known mineral industry projects, historical developments, and trends of the Cuban economy with an emphasis on mineral industries, and the supply and demand for Cuba’s mineral resources. In 2013, Cuba was estimated to be among the world’s top ten producers of cobalt and nickel, which are the country’s leading exports. Cuba’s current crude oil and associated natural gas production from onshore and shallow water coastal reservoirs is approximately 50,000 barrels per day of liquids and about 20,000 barrels per day oil equivalent of natural gas. In 2013, the value of mining and quarrying activities accounted for 0.6 percent of Cuba’s gross domestic product (GDP), compared with 1.4 percent in 2000. The value of production from Cuba’s industrial manufacturing sector increased by 88 percent between 1993 and 2013, whereas the sector’s share in the GDP decreased by about 3 percent during the same time period reflecting economic growth in other sectors of the economy.

Fact Sheet

Total petroleum systems of the Grand Erg/Ahnet Province, Algeria and Morocco; the Tanezzuft-Timimoun, Tanezzuft-Ahnet, Tanezzuft-Sbaa, Tanezzuft Mouydir, Tanezzuft-Benoud, and Tanezzuft-Bechar/Abadla

Undiscovered, conventional oil and gas resources were assessed within total petroleum systems of the Grand Erg/Ahnet Province (2058) as part of the U.S. Geological Survey World Petroleum Assessment 2000. The majority of the Grand Erg/ Ahnet Province is in western Algeria; a very small portion extends into Morocco. The province includes the Timimoun Basin, Ahnet Basin, Sbaa Basin, Mouydir Basin, Benoud Trough, Bechar/Abadla Basin(s), and part of the Oued Mya Basin. Although several petroleum systems may exist within each of these basins, only seven ?composite? total petroleum systems were identified. Each total petroleum system occurs in a separate basin, and each comprises a single assessment unit. The main source rocks are the Silurian Tanezzuft Formation (or lateral equivalents) and Middle to Upper Devonian mudstone. Maturation history and the major migration pathways from source to reservoir are unique to each basin. The total petroleum systems were named after the oldest major source rock and the basin in which it resides. The estimated means of the undiscovered conventional petroleum volumes in total petroleum systems of the Grand Erg/ Ahnet Province are as follows: [MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels of natural gas liquids] Total Petroleum System MMBO BCFG MMBNGL Tanezzuft-Timimoun 31 1,128 56 Tanezzuft-Ahnet 34 2,973 149 Tanezzuft-Sbaa 162 645 11 Tanezzuft-Mouydir 12 292 14 Tanezzuft-Benoud 72 2,541 125 Tanezzuft-Bechar/Abadla 16 441 22

Bulletin

Oil and gas reserve growth-a model for the Volga-Ural Province, Russia

An understanding of reserve growth in known oil and gas fields has become a critical component of energy resource analysis. Significant statistical studies of reserve growth have been published in the U.S., whereas little information is available on other regions of the world. It may be expected that in many countries the magnitude of reserve growth is different from that in the U.S. because of differences in reporting systems and in exploration and production practices. This paper describes the results of a reserve growth study in a group of largest oil and gas fields of the Volga-Ural petroleum province, Russia. The dynamics of reserve growth in these fields shows rapid reserve additions during the first 5 years of field exploration and development, which results from intensive step-out and delineation drilling. Later reserve growth is slow and is related to improvements in recovery technologies and discoveries of new pools and extensions. These two stages of reserve growth are described by two different groups of empirical models. A comparison of these models with the models developed for the lower 48 states and Gulf Coast offshore of the U.S. demonstrates that the reserve growth in the Volga-Ural province is significantly lower than in the U.S. The proposed models may be used for assessment of future reserve additions in known fields of countries that presently have or recently had a centrally-planned economic system.

Conference Paper