Source-rock geochemistry of the San Joaquin Basin Province, California: Chapter 11 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Peters, Kenneth E.; Magoon, Leslie B.; Valin, Zenon C.; Lillis, Paul G.

2007-01-01

Source-rock thickness and organic richness are important input parameters required for numerical modeling of the geohistory of petroleum systems. Present-day depth and thickness maps for the upper Miocene Monterey Formation, Eocene Tumey formation of Atwill (1935), Eocene Kreyenhagen Formation, and Cretaceous-Paleocene Moreno Formation source rocks in the San Joaquin Basin were determined using formation tops data from 266 wells. Rock-Eval pyrolysis and total organic carbon data (Rock-Eval/TOC) were collected for 1,505 rock samples from these source rocks in 70 wells. Averages of these data for each well penetration were used to construct contour plots of original total organic carbon (TOCo) and original hydrogen index (HIo) in the source rock prior to thermal maturation resulting from burial. Sufficient data were available to construct plots of TOCo and HIo for all source-rock units except the Tumey formation of Atwill (1935). Thick, organic-rich, oil-prone shales of the upper Miocene Monterey Formation occur in the Tejon depocenter in the southern part of the basin with somewhat less favorable occurrence in the Southern Buttonwillow depocenter to the north. Shales of the upper Miocene Monterey Formation generated most of the petroleum in the San Joaquin Basin. Thick, organic-rich, oil-prone Kreyenhagen Formation source rock occurs in the Buttonwillow depocenters, but it is thin or absent in the Tejon depocenter. Moreno Formation source rock is absent from the Tejon and Southern Buttonwillow depocenters, but thick, organic-rich, oil-prone Moreno Formation source rock occurs northwest of the Northern Buttonwillow depocenter adjacent to the southern edge of Coalinga field.

Assessment of undiscovered hydrocarbon resources of sub-Saharan Africa

USGS Publications Warehouse

Brownfield, Michael E.

2016-01-01

The assessment was geology-based and used the total petroleum system (TPS) concept. The geologic elements of a TPS are hydrocarbon source rocks (source rock maturation and hydrocarbon generation and migration), reservoir rocks (quality and distribution), and traps where hydrocarbon accumulates. Using these geologic criteria, 16 conventional total petroleum systems and 18 assessment units in the 13 provinces were defined. The undiscovered, technically recoverable oil and gas resources were assessed for all assessment units.

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

USGS Publications Warehouse

Klett, T.R.

2001-01-01

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

New insight on petroleum system modeling of Ghadames basin, Libya

NASA Astrophysics Data System (ADS)

Bora, Deepender; Dubey, Siddharth

2015-12-01

Underdown and Redfern (2008) performed a detailed petroleum system modeling of the Ghadames basin along an E-W section. However, hydrocarbon generation, migration and accumulation changes significantly across the basin due to complex geological history. Therefore, a single section can't be considered representative for the whole basin. This study aims at bridging this gap by performing petroleum system modeling along a N-S section and provides new insights on source rock maturation, generation and migration of the hydrocarbons using 2D basin modeling. This study in conjunction with earlier work provides a 3D context of petroleum system modeling in the Ghadames basin. Hydrocarbon generation from the lower Silurian Tanezzuft formation and the Upper Devonian Aouinet Ouenine started during the late Carboniferous. However, high subsidence rate during middle to late Cretaceous and elevated heat flow in Cenozoic had maximum impact on source rock transformation and hydrocarbon generation whereas large-scale uplift and erosion during Alpine orogeny has significant impact on migration and accumulation. Visible migration observed along faults, which reactivated during Austrian unconformity. Peak hydrocarbon expulsion reached during Oligocene for both the Tanezzuft and the Aouinet Ouenine source rocks. Based on modeling results, capillary entry pressure driven downward expulsion of hydrocarbons from the lower Silurian Tanezzuft formation to the underlying Bir Tlacsin formation observed during middle Cretaceous. Kinetic modeling has helped to model hydrocarbon composition and distribution of generated hydrocarbons from both the source rocks. Application of source to reservoir tracking technology suggest some accumulations at shallow stratigraphic level has received hydrocarbons from both the Tanezzuft and Aouinet Ouenine source rocks, implying charge mixing. Five petroleum systems identified based on source to reservoir correlation technology in Petromod*. This Study builds upon the original work of Underdown and Redfern, 2008 and offers new insights and interpretation of the data.

Jurassic-Cretaceous Composite Total Petroleum System and Geologic Assessment of Oil and Gas Resources of the North Cuba Basin, Cuba

USGS Publications Warehouse

,

2008-01-01

The purpose of the U.S. Geological Survey's (USGS) World Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the world. The U.S. Geological Survey (USGS) completed an assessment of the undiscovered oil and gas potential of the North Cuba Basin. The assessment is based on the geologic elements of the total petroleum system (TPS) defined in the province, including petroleum source rocks (source-rock maturation, generation, and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and petroleum traps (Trap formation and timing). Using this geologic framework, the USGS defined a Jurassic-Cretaceous Total Petroleum System in the North Cuba Basin Province. Within this TPS, three assessment units were defined and assessed for undiscovered oil and gas resources.

Egret-Hibernia(!), a significant petroleum system, northern Grand Banks area, offshore eastern Canada

USGS Publications Warehouse

Magoon, L.B.; Hudson, T.L.; Peters, K.E.

2005-01-01

Egret-Hibernia(!) is a well-explored petroleum system (3.25 billion barrels oil equivalent [BOE]) located in the Jeanne d'Arc Basin on the Labrador - Newfoundland shelf. Rifting and sediment fill began in the Late Triassic. Egret source rock was deposited in the Late Jurassic at about 153 Ma. After this time, alternating reservoir rock and seal rock were deposited with some syndepositional faulting. By the end of the Early Cretaceous, faults and folds had formed numerous structural traps. For the next 100 m.y., overburden rock thermally matured the source rock when it reached almost 4 km (2.5 mi) burial depth. For 2 km (1.25 mi) below this depth, oil and gas were expelled, until the source was depleted. The expelled petroleum migrated updip to nearby faulted, anticlinal traps, where much of it migrated across faults and upsection to the Hibernia Formation (44% recoverable oil) and Avalon Formation (28%). Accumulation size decreased, and gas content increased from west to east, independent of trap size. These changes correspond to a decrease in source rock richness and quality from west to east. Almost all (96%) of the discovered petroleum resides in the Lower Cretaceous or older reservoir rock units. All accumulations found to date are normally pressured in structural traps. Fifty-two exploration wells found eighteen discoveries. Their size ranges from 1.2 to 0.01 billion BOE. Most discoveries were made between 1979 and 1991. The discovery cycle began with larger accumulations and progressed to smaller accumulations. The estimated sizes of the larger accumulations have grown since 1990. Estimated mean value for undiscovered hydrocarbons is 3.8 billion BOE, thereby raising the ultimate size of Egret-Hibernia(!) to 6.19 billion BOE. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

A comparison of the rates of hydrocarbon generation from Lodgepole, False Bakken, and Bakken formation petroleum source rocks, Williston Basin, USA

DOE Office of Scientific and Technical Information (OSTI.GOV)

Jarvie, D.M.; Elsinger, R.J.; Inden, R.F.

1996-06-01

Recent successes in the Lodgepole Waulsortian Mound play have resulted in the reevaluation of the Williston Basin petroleum systems. It has been postulated that hydrocarbons were generated from organic-rich Bakken Formation source rocks in the Williston Basin. However, Canadian geoscientists have indicated that the Lodgepole Formation is responsible for oil entrapped in Lodgepole Formation and other Madison traps in portions of the Canadian Williston Basin. Furthermore, geoscientists in the U.S. have recently shown oils from mid-Madison conventional reservoirs in the U.S. Williston Basin were not derived from Bakken Formation source rocks. Kinetic data showing the rate of hydrocarbon formation frommore » petroleum source rocks were measured on source rocks from the Lodgepole, False Bakken, and Bakken Formations. These results show a wide range of values in the rate of hydrocarbon generation. Oil prone facies within the Lodgepole Formation tend to generate hydrocarbons earlier than the oil prone facies in the Bakken Formation and mixed oil/gas prone and gas prone facies in the Lodgepole Formation. A comparison of these source rocks using a geological model of hydrocarbon generation reveals differences in the timing of generation and the required level of maturity to generate significant amounts of hydrocarbons.« less

Late Jurassic – early Cretaceous inversion of rift structures, and linkage of petroleum system elements across post-rift unconformity, U.S. Chukchi Shelf, arctic Alaska

USGS Publications Warehouse

Houseknecht, David W.; Connors, Christopher D.

2015-01-01

Oil-prone source rocks, reservoir-quality sandstone, migration pathways, and structural closure are linked intimately across the Jurassic unconformity, which reflects inversion. Thus, all these key petroleum systems elements were in place when Triassic source rocks entered the oil generation window during Cretaceous–Cenozoic stratigraphic burial.

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

USGS Publications Warehouse

Klett, T.R.

2000-01-01

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).

Genetic features of petroleum systems in rift basins of eastern China

USGS Publications Warehouse

Qiang, J.; McCabe, P.J.

1998-01-01

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

Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Raton Basin - Sierra Grande Uplift Province, Colorado and New Mexico - USGS Province 41

USGS Publications Warehouse

Higley, Debra K.

2007-01-01

Introduction The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The USGS recently completed an assessment of undiscovered oil and gas resources of the Raton Basin-Sierra Grande Uplift Province of southeastern Colorado and northeastern New Mexico (USGS Province 41). The Cretaceous Vermejo Formation and Cretaceous-Tertiary Raton Formation have production and undiscovered resources of coalbed methane. Other formations in the province exhibit potential for gas resources and limited production. This assessment is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). The USGS used this geologic framework to define two total petroleum systems and five assessment units. All five assessment units were quantitatively assessed for undiscovered gas resources. Oil resources were not assessed because of the limited potential due to levels of thermal maturity of petroleum source rocks.

National Assessment of Oil and Gas Project: petroleum systems and geologic assessment of oil and gas in the Southwestern Wyoming Province, Wyoming, Colorado and Utah

USGS Publications Warehouse

,

2005-01-01

The U.S. Geological Survey (USGS) completed an assessment of the undiscovered oil and gas potential of the Southwestern Wyoming Province of southwestern Wyoming, northwestern Colorado, and northeastern Utah (fig. 1). The USGS Southwestern Wyoming Province for this assessment included the Green River Basin, Moxa arch, Hoback Basin, Sandy Bend arch, Rock Springs uplift, Great Divide Basin, Wamsutter arch, Washakie Basin, Cherokee ridge, and the Sand Wash Basin. The assessment of the Southwestern Wyoming Province is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation, and migration), reservoir rocks (sequence stratigraphy, petrophysical properties), and hydrocarbon traps (trap types, formation, and timing). Using this geologic framework, the USGS defined 9 total petroleum systems (TPS) and 23 assessment units (AU) within these TPSs, and quantitatively estimated the undiscovered oil and gas resources within 21 of the 23 AUs.

Temperature and petroleum generation history of the Wilcox Formation, Louisiana

USGS Publications Warehouse

Pitman, Janet K.; Rowan, Elisabeth Rowan

2012-01-01

A one-dimensional petroleum system modeling study of Paleogene source rocks in Louisiana was undertaken in order to characterize their thermal history and to establish the timing and extent of petroleum generation. The focus of the modeling study was the Paleocene and Eocene Wilcox Formation, which contains the youngest source rock interval in the Gulf Coast Province. Stratigraphic input to the models included thicknesses and ages of deposition, lithologies, amounts and ages of erosion, and ages for periods of nondeposition. Oil-generation potential of the Wilcox Formation was modeled using an initial total organic carbon of 2 weight percent and an initial hydrogen index of 261 milligrams of hydrocarbon per grams of total organic carbon. Isothermal, hydrous-pyrolysis kinetics determined experimentally was used to simulate oil generation from coal, which is the primary source of oil in Eocene rocks. Model simulations indicate that generation of oil commenced in the Wilcox Formation during a fairly wide age range, from 37 million years ago to the present day. Differences in maturity with respect to oil generation occur across the Lower Cretaceous shelf edge. Source rocks that are thermally immature and have not generated oil (depths less than about 5,000 feet) lie updip and north of the shelf edge; source rocks that have generated all of their oil and are overmature (depths greater than about 13,000 feet) are present downdip and south of the shelf edge. High rates of sediment deposition coupled with increased accommodation space at the Cretaceous shelf margin led to deep burial of Cretaceous and Tertiary source rocks and, in turn, rapid generation of petroleum and, ultimately, cracking of oil to gas.

Timing and petroleum sources for the Lower Cretaceous Mannville Group oil sands of northern Alberta based on 4-D modeling

USGS Publications Warehouse

Higley, D.K.; Lewan, M.D.; Roberts, L.N.R.; Henry, M.

2009-01-01

The Lower Cretaceous Mannville Group oil sands of northern Alberta have an estimated 270.3 billion m3 (BCM) (1700 billion bbl) of in-place heavy oil and tar. Our study area includes oil sand accumulations and downdip areas that partially extend into the deformation zone in western Alberta. The oil sands are composed of highly biodegraded oil and tar, collectively referred to as bitumen, whose source remains controversial. This is addressed in our study with a four-dimensional (4-D) petroleum system model. The modeled primary trap for generated and migrated oil is subtle structures. A probable seal for the oil sands was a gradual updip removal of the lighter hydrocarbon fractions as migrated oil was progressively biodegraded. This is hypothetical because the modeling software did not include seals resulting from the biodegradation of oil. Although the 4-D model shows that source rocks ranging from the Devonian-Mississippian Exshaw Formation to the Lower Cretaceous Mannville Group coals and Ostracode-zone-contributed oil to Mannville Group reservoirs, source rocks in the Jurassic Fernie Group (Gordondale Member and Poker Chip A shale) were the initial and major contributors. Kinetics associated with the type IIS kerogen in Fernie Group source rocks resulted in the early generation and expulsion of oil, as early as 85 Ma and prior to the generation from the type II kerogen of deeper and older source rocks. The modeled 50% peak transformation to oil was reached about 75 Ma for the Gordondale Member and Poker Chip A shale near the west margin of the study area, and prior to onset about 65 Ma from other source rocks. This early petroleum generation from the Fernie Group source rocks resulted in large volumes of generated oil, and prior to the Laramide uplift and onset of erosion (???58 Ma), which curtailed oil generation from all source rocks. Oil generation from all source rocks ended by 40 Ma. Although the modeled study area did not include possible western contributions of generated oil to the oil sands, the amount generated by the Jurassic source rocks within the study area was 475 BCM (2990 billion bbl). Copyright ?? 2009. The American Association of Petroleum Geologists. All rights reserved.

Organic geochemistry and petrology of oil source rocks, Carpathian Overthrust region, southeastern Poland - Implications for petroleum generation

USGS Publications Warehouse

Kruge, M.A.; Mastalerz, Maria; Solecki, A.; Stankiewicz, B.A.

1996-01-01

The organic mailer rich Oligocene Menilite black shales and mudstones are widely distributed in the Carpathian Overthrust region of southeastern Poland and have excellent hydrocarbon generation potential, according to TOC, Rock-Eval, and petrographic data. Extractable organic matter was characterized by an equable distribution of steranes by carbon number, by varying amounts of 28,30-dinor-hopane, 18??(H)-oleanane and by a distinctive group of C24 ring-A degraded triterpanes. The Menilite samples ranged in maturity from pre-generative to mid-oil window levels, with the most mature in the southeastern portion of the study area. Carpathian petroleum samples from Campanian Oligocene sandstone reservoirs were similar in biomarker composition to the Menilite rock extracts. Similarities in aliphatic and aromatic hydrocarbon distributions between petroleum asphaltene and source rock pyrolyzates provided further evidence genetically linking Menilite kerogens with Carpathian oils.

Estimating thermal maturity in the Eagle Ford Shale petroleum system using gas gravity data

USGS Publications Warehouse

Birdwell, Justin E.; Kinney, Scott A.

2017-01-01

Basin-wide datasets that provide information on the geochemical properties of petroleum systems, such as source rock quality, product composition, and thermal maturity, are often difficult to come by or assemble from publically available data. When published studies are available and include these kinds of properties, they generally have few sampling locations and limited numbers and types of analyses. Therefore, production-related data and engineering parameters can provide useful proxies for geochemical properties that are often widely available across a play and in some states are reported in publically available or commercial databases. Gas-oil ratios (GOR) can be calculated from instantaneous or cumulative production data and can be related to the source rock geochemical properties like kerogen type (Lewan and Henry, 1999) and thermal maturity (Tian et al., 2013; U.S. Energy Information Administration [EIA], 2014). Oil density or specific gravity (SG), often reported in American Petroleum Institute units (°API = 141.5 /SG – 131.5), can also provide information on source rock thermal maturity, particularly when combined with GOR values in unconventional petroleum systems (Nesheim, 2017).

Evaluating Re-Os systematics in organic-rich sedimentary rocks in response to petroleum generation using hydrous pyrolysis experiments

USGS Publications Warehouse

Rooney, A.D.; Selby, D.; Lewan, M.D.; Lillis, P.G.; Houzay, J.-P.

2012-01-01

Successful application of the 187Re–187Os geochronometer has enabled the determination of accurate and precise depositional ages for organic-rich sedimentary rocks (ORS) as well as establishing timing constraints of petroleum generation. However, we do not fully understand the systematics and transfer behaviour of Re and Os between ORS and petroleum products (e.g., bitumen and oil). To more fully understand the behaviour of Re–Os systematics in both source rocks and petroleum products we apply hydrous pyrolysis to two immature hydrocarbon source rocks: the Permian Phosphoria Formation (TOC = 17.4%; Type II-S kerogen) and the Jurassic Staffin Formation (TOC = 2.5%; Type III kerogen). The laboratory-based hydrous pyrolysis experiments were carried out for 72 h at 250, 300, 325 and 350 °C. These experiments provided us with whole rock, extracted rock and bitumen and in some cases expelled oil and asphaltene for evaluation of Re–Os isotopic and elemental abundance. The data from these experiments demonstrate that the majority (>95%) of Re and Os are housed within extracted rock and that thermal maturation does not result in significant transfer of Re or Os from the extracted rock into organic phases. Based on existing thermodynamic data our findings suggest that organic chelating sites have a greater affinity for the quadravalent states of Re and Os than sulphides. Across the temperature range of the hydrous pyrolysis experiments both whole rock and extracted rock 187Re/188Os ratios show small variations (3.3% and 4.7%, for Staffin, respectively and 6.3% and 4.9% for Phosphoria, respectively). Similarly, the 187Os/188Os ratios show only minor variations for the Staffin and Phosphoria whole rock and extracted rock samples (0.6% and 1.4% and 1.3% and 2.2%). These isotopic data strongly suggest that crude oil generation through hydrous pyrolysis experiments does not disturb the Re–Os systematics in ORS as supported by various studies on natural systems. The elemental abundance data reveal limited transfer of Re and Os into the bitumen from a Type III kerogen in comparison to Type II-S kerogen (0.02% vs. 3.7%), suggesting that these metals are very tightly bound in Type III kerogen structure. The 187Os/188Os data from the pyrolysis generated Phosphoria bitumens display minor variation (4%) across the experimental temperatures, with values similar to that of the source rock. This indicates that the isotopic composition of the bitumen reflects the isotopic composition of the source rock at the time of petroleum generation. These data further support the premise that the Os isotopic composition of oils and bitumens can be used to fingerprint petroleum deposits to specific source rocks. Oil generated through the hydrous pyrolysis experiments does not contain appreciable quantities of Re or Os (~120 and ~3 ppt, respectively), in contrast to natural oils (2–50 ppb and 34–288 ppt for Re and Os, respectively), which may suggest that kinetic parameters are fundamental to the transfer of Re and Os from source rocks to oils. From this we hypothesise that, at the temperatures employed in hydrous pyrolysis, Re and Os are assimilated into the extracted rock as a result of cross-linking reactions.

Evaluating Re-Os systematics in organic-rich sedimentary rocks in response to petroleum generation using hydrous pyrolysis experiments

NASA Astrophysics Data System (ADS)

Rooney, Alan D.; Selby, David; Lewan, Michael D.; Lillis, Paul G.; Houzay, Jean-Pierre

2012-01-01

Successful application of the 187Re-187Os geochronometer has enabled the determination of accurate and precise depositional ages for organic-rich sedimentary rocks (ORS) as well as establishing timing constraints of petroleum generation. However, we do not fully understand the systematics and transfer behaviour of Re and Os between ORS and petroleum products (e.g., bitumen and oil). To more fully understand the behaviour of Re-Os systematics in both source rocks and petroleum products we apply hydrous pyrolysis to two immature hydrocarbon source rocks: the Permian Phosphoria Formation (TOC = 17.4%; Type II-S kerogen) and the Jurassic Staffin Formation (TOC = 2.5%; Type III kerogen). The laboratory-based hydrous pyrolysis experiments were carried out for 72 h at 250, 300, 325 and 350 °C. These experiments provided us with whole rock, extracted rock and bitumen and in some cases expelled oil and asphaltene for evaluation of Re-Os isotopic and elemental abundance. The data from these experiments demonstrate that the majority (>95%) of Re and Os are housed within extracted rock and that thermal maturation does not result in significant transfer of Re or Os from the extracted rock into organic phases. Based on existing thermodynamic data our findings suggest that organic chelating sites have a greater affinity for the quadravalent states of Re and Os than sulphides. Across the temperature range of the hydrous pyrolysis experiments both whole rock and extracted rock 187Re/188Os ratios show small variations (3.3% and 4.7%, for Staffin, respectively and 6.3% and 4.9% for Phosphoria, respectively). Similarly, the 187Os/188Os ratios show only minor variations for the Staffin and Phosphoria whole rock and extracted rock samples (0.6% and 1.4% and 1.3% and 2.2%). These isotopic data strongly suggest that crude oil generation through hydrous pyrolysis experiments does not disturb the Re-Os systematics in ORS as supported by various studies on natural systems. The elemental abundance data reveal limited transfer of Re and Os into the bitumen from a Type III kerogen in comparison to Type II-S kerogen (0.02% vs. 3.7%), suggesting that these metals are very tightly bound in Type III kerogen structure. The 187Os/188Os data from the pyrolysis generated Phosphoria bitumens display minor variation (4%) across the experimental temperatures, with values similar to that of the source rock. This indicates that the isotopic composition of the bitumen reflects the isotopic composition of the source rock at the time of petroleum generation. These data further support the premise that the Os isotopic composition of oils and bitumens can be used to fingerprint petroleum deposits to specific source rocks. Oil generated through the hydrous pyrolysis experiments does not contain appreciable quantities of Re or Os (∼120 and ∼3 ppt, respectively), in contrast to natural oils (2-50 ppb and 34-288 ppt for Re and Os, respectively), which may suggest that kinetic parameters are fundamental to the transfer of Re and Os from source rocks to oils. From this we hypothesise that, at the temperatures employed in hydrous pyrolysis, Re and Os are assimilated into the extracted rock as a result of cross-linking reactions.

Total petroleum systems of the Bonaparte Gulf Basin area, Australia; Jurassic, Early Cretaceous-Mesozoic; Keyling, Hyland Bay-Permian; Milligans-Carboniferous, Permian

USGS Publications Warehouse

Bishop, M.G.

1999-01-01

The Bonaparte Gulf Basin Province (USGS #3910) of northern Australia contains three important hydrocarbon source-rock intervals. The oldest source-rock interval and associated reservoir rocks is the Milligans-Carboniferous, Permian petroleum system. This petroleum system is located at the southern end of Joseph Bonaparte Gulf and includes both onshore and offshore areas within a northwest to southeast trending Paleozoic rift that was initiated in the Devonian. The Milligans Formation is a Carboniferous marine shale that sources accumulations of both oil and gas in Carboniferous and Permian deltaic, marine shelf carbonate, and shallow to deep marine sandstones. The second petroleum system in the Paleozoic rift is the Keyling, Hyland Bay-Permian. Source rocks include Lower Permian Keyling Formation delta-plain coals and marginal marine shales combined with Upper Permian Hyland Bay Formation prodelta shales. These source-rock intervals provide gas and condensate for fluvial, deltaic, and shallow marine sandstone reservoirs primarily within several members of the Hyland Bay Formation. The Keyling, Hyland Bay-Permian petroleum system is located in the Joseph Bonaparte Gulf, north of the Milligans-Carboniferous, Permian petroleum system, and may extend northwest under the Vulcan graben sub-basin. The third and youngest petroleum system is the Jurassic, Early Cretaceous-Mesozoic system that is located seaward of Joseph Bonaparte Gulf on the Australian continental shelf, and trends southwest-northeast. Source-rock intervals in the Vulcan graben sub-basin include deltaic mudstones of the Middle Jurassic Plover Formation and organic-rich marine shales of the Upper Jurassic Vulcan Formation and Lower Cretaceous Echuca Shoals Formation. These intervals produce gas, oil, and condensate that accumulates in, shallow- to deep-marine sandstone reservoirs of the Challis and Vulcan Formations of Jurassic to Cretaceous age. Organic-rich, marginal marine claystones and coals of the Plover Formation (Lower to Upper Jurassic), combined with marine claystones of the Flamingo Group and Darwin Formation (Upper Jurassic to Lower Cretaceous) comprise the source rocks for the remaining area of the system. These claystones and coals source oil, gas, and condensate accumulations in reservoirs of continental to marine sandstones of the Plover Formation and Flamingo Group. Shales of the regionally distributed Lower Cretaceous Bathurst Island Group and intraformational shales act as seals for hydrocarbons trapped in anticlines and fault blocks, which are the major traps of the province. Production in the Bonaparte Gulf Basin Province began in 1986 using floating production facilities, and had been limited to three offshore fields located in the Vulcan graben sub-basin. Cumulative production from these fields totaled more than 124 million barrels of oil before the facilities were removed after production fell substantially in 1995. Production began in 1998 from three offshore wells in the Zone of Cooperation through floating production facilities. After forty years of exploration, a new infrastructure of pipelines and facilities are planned to tap already discovered offshore reserves and to support additional development.

South Atlantic sag basins: new petroleum system components

DOE Office of Scientific and Technical Information (OSTI.GOV)

Henry, S.G.; Mello, M.R.

Newly discovered pre-salt source rocks, reservoirs and seals need to be included as components to the petroleum systems of both sides of the South Atlantic. These new components lie between the pre-salt rift strata and the Aptian salt layers, forming large, post-rift, thermal subsidence sag basins. These are differentiated from the older rift basins by the lack of syn-rift faulting and a reflector geometry that is parallel to the base salt regional unconformity rather than to the Precambrian basement. These basins are observed in deep water regions overlying areas where both the mantle and the crust have been involved inmore » the extension. This mantle involvement creates post-rift subsiding depocenters in which deposition is continuous while proximal rift-phase troughs with little or no mantle involvement are bypassed and failed to accumulate potential source rocks during anoxic times. These features have been recognized in both West African Kwanza Basin and in the East Brasil Rift systems. The pre-salt source rocks that are in the West African sag basins were deposited in lacustrine brackish to saline water environment and are geochemically distinct from the older, syn-rift fresh to brackish water lakes, as well as from younger, post-salt marine anoxic environments of the drift phase. Geochemical analyses of the source rocks and their oils have shown a developing source rock system evolving from isolated deep rift lakes to shallow saline lakes, and culminating with the infill of the sag basin by large saline lakes to a marginally marine restricted gulf. Sag basin source rocks may be important in the South Atlantic petroleum system by charging deep-water prospects where syn-rift source rocks are overmature and the post-salt sequences are immature.« less

Petroleum Systems and Geologic Assessment of Undiscovered Oil and Gas, Navarro and Taylor Groups, Western Gulf Province, Texas

USGS Publications Warehouse

,

2006-01-01

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The USGS recently completed an assessment of undiscovered oil and gas potential of the Late Cretaceous Navarro and Taylor Groups in the Western Gulf Province in Texas (USGS Province 5047). The Navarro and Taylor Groups have moderate potential for undiscovered oil resources and good potential for undiscovered gas resources. This assessment is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). The USGS used this geologic framework to define one total petroleum system and five assessment units. Five assessment units were quantitatively assessed for undiscovered oil and gas resources.

Source rock contributions to the Lower Cretaceous heavy oil accumulations in Alberta: a basin modeling study

USGS Publications Warehouse

Berbesi, Luiyin Alejandro; di Primio, Rolando; Anka, Zahie; Horsfield, Brian; Higley, Debra K.

2012-01-01

The origin of the immense oil sand deposits in Lower Cretaceous reservoirs of the Western Canada sedimentary basin is still a matter of debate, specifically with respect to the original in-place volumes and contributing source rocks. In this study, the contributions from the main source rocks were addressed using a three-dimensional petroleum system model calibrated to well data. A sensitivity analysis of source rock definition was performed in the case of the two main contributors, which are the Lower Jurassic Gordondale Member of the Fernie Group and the Upper Devonian–Lower Mississippian Exshaw Formation. This sensitivity analysis included variations of assigned total organic carbon and hydrogen index for both source intervals, and in the case of the Exshaw Formation, variations of thickness in areas beneath the Rocky Mountains were also considered. All of the modeled source rocks reached the early or main oil generation stages by 60 Ma, before the onset of the Laramide orogeny. Reconstructed oil accumulations were initially modest because of limited trapping efficiency. This was improved by defining lateral stratigraphic seals within the carrier system. An additional sealing effect by biodegraded oil may have hindered the migration of petroleum in the northern areas, but not to the east of Athabasca. In the latter case, the main trapping controls are dominantly stratigraphic and structural. Our model, based on available data, identifies the Gordondale source rock as the contributor of more than 54% of the oil in the Athabasca and Peace River accumulations, followed by minor amounts from Exshaw (15%) and other Devonian to Lower Jurassic source rocks. The proposed strong contribution of petroleum from the Exshaw Formation source rock to the Athabasca oil sands is only reproduced by assuming 25 m (82 ft) of mature Exshaw in the kitchen areas, with original total organic carbon of 9% or more.

Total Petroleum Systems of the Carpathian - Balkanian Basin Province of Romania and Bulgaria

USGS Publications Warehouse

Pawlewicz, Mark

2007-01-01

The U.S. Geological Survey defined the Moesian Platform Composite Total Petroleum System and the Dysodile Schist-Tertiary Total Petroleum System, which contain three assessment units, in the Carpathian-Balkanian Basin Province of Romania and Bulgaria. The Moesian Platform Assessment Unit, contained within the Moesian Platform Composite Total Petroleum System, is composed of Mesozoic and Cenozoic rocks within the Moesian platform region of southern Romania and northern Bulgaria and also within the Birlad depression in the northeastern platform area. In Romania, hydrocarbon sources are identified as carbonate rocks and bituminous claystones within the Middle Devonian, Middle Jurassic, Lower Cretaceous, and Neogene stratigraphic sequences. In the Birlad depression, Neogene pelitic strata have the best potential for generating hydrocarbons. In Bulgaria, Middle and Upper Jurassic shales are the most probable hydrocarbon sources. The Romania Flysch Zone Assessment Unit in the Dysodile Schist-Tertiary Total Petroleum System encompasses three structural and paleogeographic subunits within the Pre-Carpathian Mountains region: (1) the Getic depression, a segment of the Carpathian foredeep; (2) the flysch zone of the eastern Carpathian Mountains (also called the Marginal Fold nappe); and (3) the Miocene zone (also called the Sub-Carpathian nappe). Source rocks are interpreted to be Oligocene dysodile schist and black claystone, along with Miocene black claystone and marls. Also part of the Dysodile Schist-Tertiary Total Petroleum System is the Romania Ploiesti Zone Assessment Unit, which includes a zone of diapir folds. This zone lies between the Rimnicu Sarat and Dinibovita valleys and between the folds of the inner Carpathian Mountains and the external flanks of the Carpathian foredeep. The Oligocene Dysodile Schist is considered the main hydrocarbon source rock and Neogene black marls and claystones are likely secondary sources; all are thought to be at their maximum thermal maturation. Undiscovered resources in the Carpathian-Balkanian Basin Province are estimated, at the mean, to be 2,076 billion cubic feet of gas, 1,013 million barrels of oil, and 116 million barrels of natural gas liquids.

Geologic Assessment of Undiscovered, Technically Recoverable Coalbed-Gas Resources in Cretaceous and Tertiary Rocks, North Slope and Adjacent State Waters, Alaska

USGS Publications Warehouse

Roberts, Stephen B.

2008-01-01

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geology-based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States, focusing on the distribution, quantity, and availability of oil and natural gas resources. The USGS has completed an assessment of the undiscovered, technically recoverable coalbed-gas resources in Cretaceous and Tertiary rocks underlying the North Slope and adjacent State waters of Alaska (USGS Northern Alaska Province 5001). The province is a priority Energy Policy and Conservation Act (EPCA) province for the National Assessment because of its potential for oil and gas resources. The assessment of this province is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (stratigraphy, sedimentology, petrophysical properties), and hydrocarbon traps (trap formation and timing). In the Northern Alaska Province, the USGS used this geologic framework to define one composite coalbed gas total petroleum system and three coalbed gas assessment units within the petroleum system, and quantitatively estimated the undiscovered coalbed-gas resources within each assessment unit.

Origin and accumulation mechanisms of petroleum in the Carboniferous volcanic rocks of the Kebai Fault zone, Western Junggar Basin, China

NASA Astrophysics Data System (ADS)

Chen, Zhonghong; Zha, Ming; Liu, Keyu; Zhang, Yueqian; Yang, Disheng; Tang, Yong; Wu, Kongyou; Chen, Yong

2016-09-01

The Kebai Fault zone of the West Junggar Basin in northwestern China is a unique region to gain insights on the formation of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks are widespread in the Kebai Fault zone and consist of basalt, basaltic andesite, andesite, tuff, volcanic breccia, sandy conglomerate and metamorphic rocks. The volcanic oil reservoirs are characterized by multiple sources and multi-stage charge and filling history, characteristic of a complex petroleum system. Geochemical analysis of the reservoir oil, hydrocarbon inclusions and source rocks associated with these volcanic rocks was conducted to better constrain the oil source, the petroleum filling history, and the dominant mechanisms controlling the petroleum accumulation. Reservoir oil geochemistry indicates that the oil contained in the Carboniferous volcanic rocks of the Kebai Fault zone is a mixture. The oil is primarily derived from the source rock of the Permian Fengcheng Formation (P1f), and secondarily from the Permian Lower Wuerhe Formation (P2w). Compared with the P2w source rock, P1f exhibits lower values of C19 TT/C23 TT, C19+20TT/ΣTT, Ts/(Ts + Tm) and ααα-20R sterane C27/C28 ratios but higher values of TT C23/C21, HHI, gammacerane/αβ C30 hopane, hopane (20S) C34/C33, C29ββ/(ββ + αα), and C29 20S/(20S + 20R) ratios. Three major stages of oil charge occurred in the Carboniferous, in the Middle Triassic, Late Triassic to Early Jurassic, and in the Middle Jurassic to Late Jurassic periods, respectively. Most of the oil charged during the first stage was lost, while moderately and highly mature oils were generated and accumulated during the second and third stages. Oil migration and accumulation in the large-scale stratigraphic reservoir was primarily controlled by the top Carboniferous unconformity with better porosity and high oil enrichment developed near the unconformity. Secondary dissolution pores and fractures are the two major reservoir storage-space types in the reservoirs. Structural highs and reservoirs near the unconformity are two favorable oil accumulation places. The recognition of the large-scale Carboniferous volcanic reservoirs in the Kebai Fault zone and understanding of the associated petroleum accumulation mechanisms provide new insights for exploring various types of volcanic reservoir plays in old volcanic provinces, and will undoubtedly encourage future oil and gas exploration of deeper strata in the region and basins elsewhere with similar settings.

Oil and gas geochemistry and petroleum systems of the Fort Worth Basin

USGS Publications Warehouse

Hill, R.J.; Jarvie, D.M.; Zumberge, J.; Henry, M.; Pollastro, R.M.

2007-01-01

Detailed biomarker and light hydrocarbon geochemistry confirm that the marine Mississippian Barnett Shale is the primary source rock for petroleum in the Fort Worth Basin, north-central Texas, although contributions from other sources are possible. Biomarker data indicate that the main oil-generating Barnett Shale facies is marine and was deposited under dysoxic, strong upwelling, normal salinity conditions. The analysis of two outcrop samples and cuttings from seven wells indicates variability in the Barnett Shale organic facies and a possibility of other oil subfamilies being present. Light hydrocarbon analyses reveal significant terrigenous-sourced condensate input to some reservoirs, resulting in terrigenous and mixed marine-terrigenous light hydrocarbon signatures for many oils. The light hydrocarbon data suggest a secondary, condensate-generating source facies containing terrigenous or mixed terrigenous-marine organic matter. This indication of a secondary source rock that is not revealed by biomarker analysis emphasizes the importance of integrating biomarker and light hydrocarbon data to define petroleum source rocks. Gases in the Fort Worth Basin are thermogenic in origin and appear to be cogenerated with oil from the Barnett Shale, although some gas may also originate by oil cracking. Isotope data indicate minor contribution of biogenic gas. Except for reservoirs in the Pennsylvanian Bend Group, which contain gases spanning the complete range of observed maturities, the gases appear to be stratigraphically segregated, younger reservoirs contain less mature gas, and older reservoirs contain more mature gas. We cannot rule out the possibility that other source units within the Fort Worth Basin, such as the Smithwick Shale, are locally important petroleum sources. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

The effect of oil-water-rock partitioning on the occurrence of alkylphenols in petroleum systems

DOE Office of Scientific and Technical Information (OSTI.GOV)

Taylor, P.; Larter, S.; Jones, M.

1997-05-01

Low molecular weight (C{sub 0}-C{sub 3}) alkylphenols are ubiquitous constituents of crude oils and formation waters of petroleum systems, and they represent legislatively monitored pollutants in produced oils and waters from offshore petroleum facilities. Their origin and the controls on their abundance are uncertain. Analysis of forty-four oils from various petroleum provinces, together with laboratory partitioning experiments, has provided further information on these controls. Although phenols are clearly partitioned between oil and water in petroleum systems, the consistency of most nondegraded petroleum phenol distributions (despite the apparent decrease of phenol concentrations in petroleums with increasing secondary migration distance) requires phenolmore » partitioning between petroleum, water, and solid phases-chiefly kerogen in the carrier bed. The retention of significant phenol concentrations in petroleums that have migrated tens of kilometres does indicate that petroleum typically only equilibrates with minor volumes of rock and associated waters. Laboratory experiments indicate that oils which have migrated approximately 25 km in the North Sea Tampen Spur through Jurassic sandstones may have equilibrated with less than 20 vol of rock and water, and possibly much less than 1 vol, depending on the sorbing phases within the rock (i.e., mineral or organic matter) and the wetting phase (oil or water). We conclude, supporting the hypothesis of Ioppolo-Armanios et al. (1995), that although ortho-substituted isomers dominate the phenol distributions of many petroleums, this reflects catalytic alkylation/isomerisation of unknown alkylphenol precursors in source rocks, rather than selective removal of meta- and para-substituted alkylphenol isomers from petroleum by water washing. 35 refs., 7 figs., 2 tabs.« less

Geology and hydrocarbon potential of the Hartford-Deerfield Basin, Connecticut and Massachusetts

USGS Publications Warehouse

Coleman, James

2016-01-01

The Hartford-Deerfield basin, a Late Triassic to Early Jurassic rift basin located in central Connecticut and Massachusetts, is the northernmost basin of the onshore Mesozoic rift basins in the eastern United States. The presence of asphaltic petroleum in outcrops indicates that at least one active petroleum system has existed within the basin. However, to-date oil and gas wells have not been drilled in the basin to test any type of petroleum trap. There are good to excellent quality source rocks (up to 3.8% present day total organic carbon) within the Jurassic East Berlin and Portland formations. While these source rock intervals are fairly extensive and at peak oil to peak gas stages of maturity, individual source rock beds are relatively thin (typically less than 1 m) based solely on outcrop observations. Potential reservoir rocks within the Hartford-Deerfield basin are arkosic conglomerates, pebbly sandstones, and finer grained sandstones, shales, siltstones, and fractured igneous rocks of the Triassic New Haven and Jurassic East Berlin and Portland formations (and possibly other units). Sandstone porosity data from 75 samples range from less than 1% to 21%, with a mean of 5%. Permeability is equally low, except around joints, fractures, and faults. Seals are likely to be unfractured intra-formational shales and tight igneous bodies. Maturation, generation, and expulsion likely occurred during the late synrift period (Early Jurassic) accentuated by an increase in local geothermal gradient, igneous intrusions, and hydrothermal fluid circulation. Migration pathways were likely along syn- and postrift faults and fracture zones. Petroleum resources, if present, are probably unconventional (continuous) accumulations as conventionally accumulated petroleum is likely not present in significant volumes.

Rock-Eval pyrolysis and vitrinite reflectance results from the Sheep Creek 1 well, Susitna basin, south-central Alaska

USGS Publications Warehouse

Stanley, Richard G.; Lillis, Paul G.; Pawlewicz, Mark J.; Haeussler, Peter J.

2014-01-01

We used Rock-Eval pyrolysis and vitrinite reflectance to examine the petroleum source potential of rock samples from the Sheep Creek 1 well in the Susitna basin of south-central Alaska. The results show that Miocene nonmarine coal, carbonaceous shale, and mudstone are potential sources of hydrocarbons and are thermally immature with respect to the oil window. In the samples that we studied, coals are more organic-rich and more oil-prone than carbonaceous shales and silty mudstones, which appear to be potential sources of natural gas. Lithologically similar rocks may be present in the deeper parts of the subsurface Susitna basin located west of the Sheep Creek 1 well, where they may have been buried deeply enough to generate oil and (or) gas. The Susitna basin is sparsely drilled and mostly unexplored, and no commercial production of hydrocarbons has been obtained. However, the existence of potential source rocks of oil and gas, as shown by our Rock-Eval results, suggests that undiscovered petroleum accumulations may be present in the Susitna basin.

In search of a Silurian total petroleum system in the Appalachian basin of New York, Ohio, Pennsylvania, and West Virginia: Chapter G.11 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Ryder, Robert T.; Swezey, Christopher S.; Trippi, Michael H.; Lentz, Erika E.; Avary, K. Lee; Harper, John A.; Kappel, William M.; Rea, Ronald G.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

Although the TOC analyses in this study indicate that good to very good source rocks are present in the Salina Group and Wills Creek Formation of southwestern Pennsylvania and northern West Virginia, data are insufficient to propose a new Silurian total petroleum system in the Appalachian basin. However, the analytical results of this investigation are encouraging enough to undertake more systematic studies of the source rock potential of the Salina Group, Wills Creek Formation, and perhaps the Tonoloway Formation (Limestone) and McKenzie Limestone (or Member).

Mapping the petroleum system - An investigative technique to explore the hydrocarbon fluid system

USGS Publications Warehouse

Magoon, L.B.; Dow, W.G.

2000-01-01

Creating a petroleum system map includes a series of logical steps that require specific information to explain the origin in time and space of discovered hydrocarbon occurrences. If used creatively, this map provides a basis on which to develop complementary plays and prospects. The logical steps include the characterization of a petroleum system (that is, to identify, map, and name the hydrocarbon fluid system) and the summary of these results on a folio sheet. A petroleum system map is based on the understanding that there are several levels of certainty from "guessing" to "knowing" that specific oil and gas accumulations emanated from a particular pod of active source rock. Levels of certainty start with the close geographic proximity of two or more accumulations, continues with the close stratigraphic proximity, followed by the similarities in bulk properties, and then detailed geochemical properties. The highest level of certainty includes the positive geochemical correlation of the hydrocarbon fluid in the accumulations to the extract of the active source rock. A petroleum system map is created when the following logic is implemented. Implementation starts when the oil and gas accumulations of a petroleum province are grouped stratigraphically and geographically. Bulk and geochemical properties are used to further refine the groups through the determination of genetically related oil and gas types. To this basic map, surface seeps and well shows are added. Similarly, the active source rock responsible for these hydrocarbon occurrences are mapped to further define the extent of the system. A folio sheet constructed for a hypothetical case study of the Deer-Boar(.) petroleum system illustrates this methodology.

Executive Summary -- assessment of undiscovered oil and gas resources of the San Joaquin Basin Province of California, 2003: Chapter 1 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Gautier, Donald L.; Scheirer, Allegra Hosford; Tennyson, Marilyn E.; Peters, Kenneth E.; Magoon, Leslie B.; Lillis, Paul G.; Charpentier, Ronald R.; Cook, Troy A.; French, Christopher D.; Klett, Timothy R.; Pollastro, Richard M.; Schenk, Christopher J.

2007-01-01

In 2003, the U.S. Geological Survey (USGS) completed an assessment of the oil and gas resource potential of the San Joaquin Basin Province of California (fig. 1.1). The assessment is based on the geologic elements of each Total Petroleum System defined in the province, including hydrocarbon source rocks (source-rock type and maturation and hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined five total petroleum systems and ten assessment units within these systems. Undiscovered oil and gas resources were quantitatively estimated for the ten assessment units (table 1.1). In addition, the potential was estimated for further growth of reserves in existing oil fields of the San Joaquin Basin.

The North Sakhalin Neogene total petroleum system of eastern Russia

USGS Publications Warehouse

Lindquist, S.J.

2000-01-01

The North Sakhalin Basin Province of eastern Russia contains one Total Petroleum System (TPS) ? North Sakhalin Neogene ? with more than 6 BBOE known, ultimately recoverable petroleum (61% gas, 36% oil, 3% condensate). Tertiary rocks in the basin were deposited by the prograding paleo-Amur River system. Marine to continental, Middle to Upper Miocene shale to coaly shale source rocks charged marine to continental Middle Miocene to Pliocene sandstone reservoir rocks in Late Miocene to Pliocene time. Fractured, self-sourced, Upper Oligocene to Lower Miocene siliceous shales also produce hydrocarbons. Geologic history is that of a Mesozoic Asian passive continental margin that was transformed into an active accretionary Tertiary margin and Cenozoic fold belt by the collision of India with Eurasia and by the subduction of Pacific Ocean crustal plates under the Asian continent. The area is characterized by extensional, compressional and wrench structural features that comprise most known traps.

Unconventional energy resources: 2015 review. Shale gas and liquids

USGS Publications Warehouse

Fishman, Neil S.; Bowker, Kent; Cander, Harris; Cardott, Brian; Charette, Marc; Chew, Kenneth; Chidsey, Thomas; Dubiel, Russell F.; Egenhoff, Sven O.; Enomoto, Catherine B.; Hammes, Ursula; Harrison, William; Jiang, Shu; LeFever, Julie A.; McCracken, Jock; Nordeng, Stephen; Nyahay, Richard; Sonnenberg, Stephen; Vanden Berg, Michael; ,

2015-01-01

Introduction As the source rocks from which petroleum is generated, organic-rich shales have always been considered an important component of petroleum systems. Over the last few years, it has been realized that in some mudrocks, sufficient hydrocarbons remain in place to allow for commercial development, although advanced drilling and completion technology is typically required to access hydrocarbons from these reservoirs. Tight oil reservoirs (also referred to as continuous oil accumulations) contain hydrocarbons migrated from source rocks that are geologically/stratigraphically interbedded with or occur immediately overlying/underlying them. Migration is minimal in charging these tight oil accumulations (Gaswirth and Marra 2014). Companies around the world are now successfully exploiting organic-rich shales and tight rocks for contained hydrocarbons, and the search for these types of unconventional petroleum reservoirs is growing. Unconventional reservoirs range in geologic age from Ordovician to Tertiary (Silverman et al. 2005; EIA 2013a). 

Chapter 5: Geologic Assessment of Undiscovered Petroleum Resources in the Waltman Shale Total Petroleum System,Wind River Basin Province, Wyoming

USGS Publications Warehouse

Roberts, Steve B.; Roberts, Laura N.R.; Cook, Troy

2007-01-01

The Waltman Shale Total Petroleum System encompasses about 3,400 square miles in the Wind River Basin Province, Wyoming, and includes accumulations of oil and associated gas that were generated and expelled from oil-prone, lacustrine shale source rocks in the Waltman Shale Member of the Paleocene Fort Union Formation. Much of the petroleum migrated and accumulated in marginal lacustrine (deltaic) and fluvial sandstone reservoirs in the Shotgun Member of the Fort Union, which overlies and intertongues with the Waltman Shale Member. Additional petroleum accumulations derived from Waltman source rocks are present in fluvial deposits in the Eocene Wind River Formation overlying the Shotgun Member, and also might be present within fan-delta deposits included in the Waltman Shale Member, and in fluvial sandstone reservoirs in the uppermost part of the lower member of the Fort Union Formation immediately underlying the Waltman. To date, cumulative production from 53 wells producing Waltman-sourced petroleum exceeds 2.8 million barrels of oil and 5.8 billion cubic feet of gas. Productive horizons range from about 1,770 feet to 5,800 feet in depth, and average about 3,400 to 3,500 feet in depth. Formations in the Waltman Shale Total Petroleum System (Fort Union and Wind River Formations) reflect synorogenic deposition closely related to Laramide structural development of the Wind River Basin. In much of the basin, the Fort Union Formation is divided into three members (ascending order): the lower unnamed member, the Waltman Shale Member, and the Shotgun Member. These members record the transition from deposition in dominantly fluvial, floodplain, and mire environments in the early Paleocene (lower member) to a depositional setting characterized by substantial lacustrine development (Waltman Shale Member) and contemporaneous fluvial, and marginal lacustrine (deltaic) deposition (Shotgun Member) during the middle and late Paleocene. Waltman Shale Member source rocks have total organic carbon values ranging from 0.93 to 6.21 weight percent, averaging about 2.71 weight percent. The hydrocarbon generative potential of the source rocks typically exceeds 2.5 milligrams of hydrocarbon per gram of rock and numerous samples had generative potentials exceeding 6.0 milligrams of hydrocarbon per gram of rock. Waltman source rocks are oil prone, and contain a mix of Type-II and Type-III kerogen, indicating organic input from a mix of algal and terrestrial plant matter, or a mix of algal and reworked or recycled material. Thermal maturity at the base of the Waltman Shale Member ranges from a vitrinite reflectance value of less than 0.60 percent along the south basin margin to projected values exceeding 1.10 percent in the deep basin west of Madden anticline. Burial history reconstructions for three wells in the northern part of the Wind River Basin indicate that the Waltman Shale Member was well within the oil window (Ro equal to or greater than 0.65 percent) by the time of maximum burial about 15 million years ago; maximum burial depths exceeded 10,000 feet. Onset of oil generation calculated for the base of the Waltman Shale member took place from about 49 million years ago to about 20 million years ago. Peak oil generation occurred from about 31 million years ago to 26 million years ago in the deep basin west of Madden anticline. Two assessment units were defined in the Waltman Shale Total Petroleum System: the Upper Fort Union Sandstones Conventional Oil and Gas Assessment Unit (50350301) and the Waltman Fractured Shale Continuous Oil Assessment Unit (50350361). The conventional assessment unit primarily relates to the potential for undiscovered petroleum accumulations that are derived from source rocks in the Waltman Shale Member and trapped within sandstone reservoirs in the Shotgun Member (Fort Union Formation) and in the lower part of the overlying Wind River Formation. The potential for Waltman-sourced oil accumulations in fan-delta depos

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

USGS Publications Warehouse

Klett, T.R.

2000-01-01

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 MMBNGLTanezzuft-Melrhir 1,875 MMBO 4,887 BCFG 269 MMBNGLTanezzuft-Ghadames 4,461 MMBO 12,035 BCFG 908 MMBNGL

Report list Arizona's oil, gas potential

USGS Publications Warehouse

Rauzi, S.L.

2001-01-01

This article is a summary of Arizona geological survey circular 29, which addresses the petroleum geology of Arizona, USA. Eight areas have been identified with fair to excellent oil and gas potential, and some Tertiary basins have evidence of source or reservoir rocks. The following are considered here: production history, lands status and services, regulation and permitting, petroleum geology, hydrocarbon indications, and areas with hydrocarbon potential and their petroleum geology and characteristics. The full report contains detailed figures of each of these basin areas, a descriptive tabulation of seeps and petroliferous rocks and extensive references.

High resolution study of petroleum source rock variation, Lower Cretaceous (Hauterivian and Barremian) of Mikkelsen Bay, North Slope, Alaska

USGS Publications Warehouse

Keller, Margaret A.; Macquaker, Joe H.S.; Lillis, Paul G.

2001-01-01

Open File Report 01-480 was designed as a large format poster for the Annual Meeting of the American Association of Petroleum Geologists and the Society for Sedimentary Geology in Denver Colorado in June 2001. It is reproduced here in digital format to make widely available some unique images of mudstones. The images include description, interpretation, and Rock-Eval data that resulted from a high-resolution study of petroleum source rock variation of the Lower Cretaceous succession of the Mobil-Phillips Mikkelsen Bay State #1 well on the North Slope of Alaska. Our mudstone samples with Rock-Eval data plus color images are significant because they come from one of the few continuously cored and complete intervals of the Lower Cretaceous succession on the North Slope. This succession, which is rarely preserved in outcrop and very rarely cored in the subsurface, is considered to include important petroleum source rocks that have not previously been described nor explained Another reason these images are unique is that the lithofacies variability within mudstone dominated successions is relatively poorly known in comparison with that observed in coarser clastic and carbonate successions. They are also among the first published scans of thin sections of mudstone, and are of excellent quality because the sections are well made, cut perpendicular to bedding, and unusually thin, 20 microns. For each of 15 samples, we show a thin section scan (cm scale) and an optical photomicrograph (mm scale) that illustrates the variability present. Several backscattered SEM images are also shown. Rock-Eval data for the samples can be compared with the textures and mineralogy present by correlating sample numbers and core depth.

Geology and total petroleum systems of the West-Central Coastal province (7203), West Africa

USGS Publications Warehouse

Brownfield, Michael E.; Charpentier, Ronald R.

2006-01-01

The West-Central Coastal Province of the Sub-Saharan Africa Region consists of the coastal and offshore areas of Cameroon, Equatorial Guinea, Gabon, Democratic Republic of the Congo, Republic of the Congo, Angola (including the disputed Cabinda Province), and Namibia. The area stretches from the east edge of the Niger Delta south to the Walvis Ridge. The West-Central Coastal Province includes the Douala, Kribi-Campo, Rio Muni, Gabon, Congo, Kwanza, Benguela, and Namibe Basins, which together form the Aptian salt basin of equatorial west Africa. The area has had significant exploration for petroleum; more than 295 oil fields have been discovered since 1954. Since 1995, several giant oil fields have been discovered, especially in the deep-water area of the Congo Basin. Although many total petroleum systems may exist in the West-Central Coastal Province, only four major total petroleum systems have been defined. The area of the province north of the Congo Basin contains two total petroleum systems: the Melania-Gamba Total Petroleum System, consisting of Lower Cretaceous source and reservoir rocks, and the Azile-Senonian Total Petroleum System, consisting of Albian to Turonian source rocks and Cretaceous reservoir rocks. Two assessment units are defined in the West-Central Coastal Province north of the Congo Basin: the Gabon Subsalt and the Gabon Suprasalt Assessment Units. The Congo Basin contains the Congo Delta Composite Total Petroleum System, consisting of Lower Cretaceous to Tertiary source and reservoir rocks. The Central Congo Delta and Carbonate Platform and the Central Congo Turbidites Assessment Units are defined in the Congo Delta Composite Total Petroleum System. The area south of the Congo Basin contains the Cuanza Composite Total Petroleum System, consisting of Lower Cretaceous to Tertiary source and reservoir rocks. The Cuanza-Namibe Assessment Unit is defined in the Cuanza Composite Total Petroleum System. The U.S. Geological Survey (USGS) assessed the potential for undiscovered conventional oil and gas resources in this province as part of its World Petroleum Assessment 2000. The USGS estimated a mean of 29.7 billion barrels of undiscovered conventional oil, 88.0 trillion cubic feet of gas, and 4.2 billion barrels of natural gas liquids. Most of the hydrocarbon potential remains in the offshore waters of the province in the Central Congo Turbidites Assessment Unit. Large areas of the offshore parts of the Kwanza, Douala, Kribi-Campo, and Rio Muni Basins are underexplored, considering their size, and current exploration activity suggests that the basins have hydrocarbon potential. Since about 1995, the offshore part of the Congo Basin has become a major area for new field discoveries and for hydrocarbon exploration, and many deeper water areas in the basin have excellent hydrocarbon potential. Gas resources may be significant and accessible in areas where the zone of oil generation is relatively shallow.

National Assessment of Oil and Gas Project: Petroleum systems and assessment of undiscovered oil and gas in the Denver Basin Province, Colorado, Kansas, Nebraska, South Dakota, and Wyoming - USGS Province 39

USGS Publications Warehouse

Higley, Debra K.

2007-01-01

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The USGS recently completed an assessment of undiscovered oil and gas resources of the Denver Basin Province (USGS Province 39), Colorado, Kansas, Nebraska, South Dakota, and Wyoming. Petroleum is produced in the province from sandstone, shale, and limestone reservoirs that range from Pennsylvanian to Upper Cretaceous in age. This assessment is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). The USGS used this geologic framework to define seven total petroleum systems and twelve assessment units. Nine of these assessment units were quantitatively assessed for undiscovered oil and gas resources. Gas was not assessed for two coal bed methane assessment units due to lack of information and limited potential; oil resources were not assessed for the Fractured Pierre Shale Assessment Unit due to its mature development status.

Petroleum surface oil seeps from Palaeoproterozoic petrified giant oilfield

NASA Astrophysics Data System (ADS)

Melezhik, V.; Fallick, A.; Filippov, M.; Lepland, A.; Rychanchik, D.; Deines, Yu.; Medvedev, P.; Romashkin, A.; Strauss, H.

2009-04-01

Evidence of petroleum generation and migration has been previously reported from rocks dating as early as 3.25 Ga. Micron-size carbonaceous streaks and bitumen micronodules were found in abundance in Archaean rocks across the Pilbara craton in Australia suggesting pervasive petroleum generation and migration. However, none of the Archaean petroleum deposits has been reported to be preserved in quantity due to destructive effects of deformation and thermal obliteration during metamorphism. During the Palaeoproterozoic, unprecedented accumulation of Corg-rich rocks worldwide, known as the 2.0 Ga Shunga Event, occurred during the early stage of progressive oxidation of terrestrial environments, and in the aftermath of the Lomagundi-Jatuli isotopic event, which based on the magnitude and duration of positive d13C was the greatest perturbation of the global carbon cycle in Earth history. C. 2.0 Ga Zaonezhskaya Formation (ZF) rocks from the Onega Basin in Russian Fennoscandia contain evidence for substantial accumulation and preservation of organic matter (up to 75 wt.-% total organic carbon) with an estimated original petroleum potential comparable to a modern supergiant oilfield. The basin contains a uniquely preserved petrified oilfield including evidence of oil traps and oil migration pathways. Here, we report the discovery of the surface expression of a migration pathway, along which petroleum was flowing from the sub-surface. This surface oil seep, the first occurrence ever reported from the Palaeoproterozoic, appears as originally bitumen clasts redeposited in Palaeoproterozoic lacustrine turbidites of the Kondopozhskaya Formation. The d13Corg of clastic pyrobitumen ranges between -35.4 and -36.0 per mill (n = 14) which is within the range of interbed- and vein-trapped fossil oil (-46 and -24 per mill), suggesting similar source. Biogenic organic matter, whose isotopic composition was modified during thermal maturation, is the likely source for the migrated hydrocarbon. Oil seeps, being a very common attribute of almost every major petroleum-producing province in the world, highlight the scale of oil generation and migration in the Onega Basin. The large d13C variability in interbed-trapped pyrobitumen and in organic matter (OM) of the ZF can be entirely explained neither by isotopic fractionation during petroleum generation nor by metamorphic processes, thus it might reflect a primary feature. The source material could have had a wide range of compositions that could have reacted in various ways to the subsequent maturation and alteration. We tentatively suggest that small-scale pyrobitumen accumulations may reflect the initial isotope heterogeneity of the source. In contrast, the seeps d13C are homogeneous, thus perhaps reflecting a large-scale migration and accumulation of composite oil produced by mixing and homogenisation of various oil sources. However, the low H/C of OM and pyrobitumens suggests that the source rock's various components with apparent diversity of original d13C have been over-matured. Although these values are compatible with being the source of the seeps, robust source-reservoir correlation cannot be made. In the evolutionary context, it is significant that the 2.0 Ga OM-rich rocks and generation of supergiant oilfields occurred in the aftermath of the Lomagundi-Jatuli isotopic event, and during the course of the early stage of oxidation of the terrestrial atmosphere. Whether enhanced biomass or change in the preservation potential caused such unprecedented OM accumulation and large-scale oil generation remains to be investigated.

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

USGS Publications Warehouse

Ulmishek, Gregory F.

2001-01-01

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

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

USGS Publications Warehouse

Klett, T.R.

2000-01-01

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

Circum-Arctic petroleum systems identified using decision-tree chemometrics

USGS Publications Warehouse

Peters, K.E.; Ramos, L.S.; Zumberge, J.E.; Valin, Z.C.; Scotese, C.R.; Gautier, D.L.

2007-01-01

Source- and age-related biomarker and isotopic data were measured for more than 1000 crude oil samples from wells and seeps collected above approximately 55??N latitude. A unique, multitiered chemometric (multivariate statistical) decision tree was created that allowed automated classification of 31 genetically distinct circumArctic oil families based on a training set of 622 oil samples. The method, which we call decision-tree chemometrics, uses principal components analysis and multiple tiers of K-nearest neighbor and SIMCA (soft independent modeling of class analogy) models to classify and assign confidence limits for newly acquired oil samples and source rock extracts. Geochemical data for each oil sample were also used to infer the age, lithology, organic matter input, depositional environment, and identity of its source rock. These results demonstrate the value of large petroleum databases where all samples were analyzed using the same procedures and instrumentation. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

Visualizing petroleum systems with a combination of GIS and multimedia technologies: An example from the West Siberia Basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Walsh, D.B.; Grace, J.D.

1996-12-31

Petroleum system studies provide an ideal application for the combination of Geographic Information System (GIS) and multimedia technologies. GIS technology is used to build and maintain the spatial and tabular data within the study region. Spatial data may comprise the zones of active source rocks and potential reservoir facies. Similarly, tabular data include the attendant source rock parameters (e.g. pyroloysis results, organic carbon content) and field-level exploration and production histories for the basin. Once the spatial and tabular data base has been constructed, GIS technology is useful in finding favorable exploration trends, such as zones of high organic content, maturemore » source rocks in positions adjacent to sealed, high porosity reservoir facies. Multimedia technology provides powerful visualization tools for petroleum system studies. The components of petroleum system development, most importantly generation, migration and trap development typically span periods of tens to hundreds of millions of years. The ability to animate spatial data over time provides an insightful alternative for studying the development of processes which are only captured in {open_quotes}snapshots{close_quotes} by static maps. New multimedia-authoring software provides this temporal dimension. The ability to record this data on CD-ROMs and allow user- interactivity further leverages the combination of spatial data bases, tabular data bases and time-based animations. The example used for this study was the Bazhenov-Neocomian petroleum system of West Siberia.« less

Visualizing petroleum systems with a combination of GIS and multimedia technologies: An example from the West Siberia Basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Walsh, D.B.; Grace, J.D.

1996-01-01

Petroleum system studies provide an ideal application for the combination of Geographic Information System (GIS) and multimedia technologies. GIS technology is used to build and maintain the spatial and tabular data within the study region. Spatial data may comprise the zones of active source rocks and potential reservoir facies. Similarly, tabular data include the attendant source rock parameters (e.g. pyroloysis results, organic carbon content) and field-level exploration and production histories for the basin. Once the spatial and tabular data base has been constructed, GIS technology is useful in finding favorable exploration trends, such as zones of high organic content, maturemore » source rocks in positions adjacent to sealed, high porosity reservoir facies. Multimedia technology provides powerful visualization tools for petroleum system studies. The components of petroleum system development, most importantly generation, migration and trap development typically span periods of tens to hundreds of millions of years. The ability to animate spatial data over time provides an insightful alternative for studying the development of processes which are only captured in [open quotes]snapshots[close quotes] by static maps. New multimedia-authoring software provides this temporal dimension. The ability to record this data on CD-ROMs and allow user- interactivity further leverages the combination of spatial data bases, tabular data bases and time-based animations. The example used for this study was the Bazhenov-Neocomian petroleum system of West Siberia.« less

National Assessment of Oil and Gas Project: Geologic Assessment of Undiscovered Oil and Gas Resources of the Eastern Great Basin Province, Nevada, Utah, Idaho, and Arizona

USGS Publications Warehouse

,

2007-01-01

Introduction The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered oil and gas potential of the Eastern Great Basin Province of eastern Nevada, western Utah, southeastern Idaho, and northwestern Arizona. This assessment is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). The USGS used this geologic framework to define one total petroleum system and three assessment units. All three assessment units were quantitatively assessed for undiscovered oil and gas resources.

Distribution, richness, quality, and thermal maturity of source rock units on the North Slope of Alaska

USGS Publications Warehouse

Peters, K.E.; Bird, K.J.; Keller, M.A.; Lillis, P.G.; Magoon, L.B.

2003-01-01

Four source rock units on the North Slope were identified, characterized, and mapped to better understand the origin of petroleum in the area: Hue-gamma ray zone (Hue-GRZ), pebble shale unit, Kingak Shale, and Shublik Formation. Rock-Eval pyrolysis, total organic carbon analysis, and well logs were used to map the present-day thickness, organic quantity (TOC), quality (hydrogen index, HI), and thermal maturity (Tmax) of each unit. To map these units, we screened all available geochemical data for wells in the study area and assumed that the top and bottom of the oil window occur at Tmax of ~440° and 470°C, respectively. Based on several assumptions related to carbon mass balance and regional distributions of TOC, the present-day source rock quantity and quality maps were used to determine the extent of fractional conversion of the kerogen to petroleum and to map the original organic richness prior to thermal maturation.

Geologic Assessment of Undiscovered Gas Resources of the Eastern Oregon and Washington Province

USGS Publications Warehouse

U.S. Geological Survey Eastern Oregon and Washington Province Assessment Team, (compiler)

2008-01-01

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geology-based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States, focusing on the distribution, quantity, and availability of oil and natural gas resources. The USGS has completed an assessment of the undiscovered oil and gas potential of the Eastern Oregon and Washington Province of Oregon and Washington (USGS Province 5005). The province is a priority Energy Policy and Conservation Act (EPCA) province for the National Assessment because of its potential for oil and gas resources. The assessment of this province is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (stratigraphy, sedimentology, petrophysical properties), and hydrocarbon traps (trap formation and timing). In the Eastern Oregon and Washington Province, the USGS used this geologic framework to define one total petroleum system and two assessment units within the total petroleum system, and quantitatively estimated the undiscovered gas resources within each assessment unit.

Petroleum systems and geologic assessment of undiscovered oil and gas, Cotton Valley group and Travis Peak-Hosston formations, East Texas basin and Louisiana-Mississippi salt basins provinces of the northern Gulf Coast region. Chapters 1-7.

USGS Publications Warehouse

,

2006-01-01

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The USGS recently completed an assessment of undiscovered oil and gas potential of the Cotton Valley Group and Travis Peak and Hosston Formations in the East Texas Basin and Louisiana-Mississippi Salt Basins Provinces in the Gulf Coast Region (USGS Provinces 5048 and 5049). The Cotton Valley Group and Travis Peak and Hosston Formations are important because of their potential for natural gas resources. This assessment is based on geologic principles and uses the total petroleum system concept. The geologic elements of a total petroleum system include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). The USGS used this geologic framework to define one total petroleum system and eight assessment units. Seven assessment units were quantitatively assessed for undiscovered oil and gas resources.

A novel molecular index for secondary oil migration distance

PubMed Central

Zhang, Liuping; Li, Maowen; Wang, Yang; Yin, Qing-Zhu; Zhang, Wenzheng

2013-01-01

Determining oil migration distances from source rocks to reservoirs can greatly help in the search for new petroleum accumulations. Concentrations and ratios of polar organic compounds are known to change due to preferential sorption of these compounds in migrating oils onto immobile mineral surfaces. However, these compounds cannot be directly used as proxies for oil migration distances because of the influence of source variability. Here we show that for each source facies, the ratio of the concentration of a select polar organic compound to its initial concentration at a reference point is independent of source variability and correlates solely with migration distance from source rock to reservoir. Case studies serve to demonstrate that this new index provides a valid solution for determining source-reservoir distance and could lead to many applications in fundamental and applied petroleum geoscience studies. PMID:23965930

Regional Stratigraphy and Petroleum Systems of the Michigan Basin, North America

USGS Publications Warehouse

Swezey, Christopher S.

2008-01-01

Although more than 100 years of research have gone into deciphering the stratigraphy of the Michigan basin of North America, it remains a challenge to visualize the basin stratigraphy on a regional scale and to describe stratigraphic relations within the basin. Similar difficulties exist for visualizing and describing the regional distribution of petroleum source rocks and reservoir rocks. This publication addresses these difficulties by combining data on Paleozoic and Mesozoic stratigraphy and petroleum geology of the Michigan basin. The areal extent of this structural basin is presented along with data in eight schematic chronostratigraphic sections arranged from north to south, with time denoted in equal increments along the sections. The stratigraphic data are modified from American Association of Petroleum Geologists (AAPG) (1984), Johnson and others (1992), Sanford (1993), and Cross (1998), and the time scale is taken from Harland and others (1990). Informal North American chronostratigraphic terms from AAPG (1984) are shown in parentheses. Stratigraphic sequences as defined by Sloss (1963, 1988) and Wheeler (1963) also are included, as well as the locations of major petroleum source rocks and major petroleum plays. The stratigraphic units are colored according to predominant lithology, in order to emphasize general lithologic patterns and to provide a broad overview of the Michigan basin. For purposes of comparison, schematic depictions of stratigraphy and interpreted events in the Michigan basin and adjacent Appalachian basin are shown. The paper version of this map is available for purchase from the USGS Store.

Petroleum systems of the Northwest Java Province, Java and offshore southeast Sumatra, Indonesia

USGS Publications Warehouse

Bishop, Michele G.

2000-01-01

Mature, synrift lacustrine shales of Eocene to Oligocene age and mature, late-rift coals and coaly shales of Oligocene to Miocene age are source rocks for oil and gas in two important petroleum systems of the onshore and offshore areas of the Northwest Java Basin. Biogenic gas and carbonate-sourced gas have also been identified. These hydrocarbons are trapped primarily in anticlines and fault blocks involving sandstone and carbonate reservoirs. These source rocks and reservoir rocks were deposited in a complex of Tertiary rift basins formed from single or multiple half-grabens on the south edge of the Sunda Shelf plate. The overall transgressive succession was punctuated by clastic input from the exposed Sunda Shelf and marine transgressions from the south. The Northwest Java province may contain more than 2 billion barrels of oil equivalent in addition to the 10 billion barrels of oil equivalent already identified.

A new petroleum system in offshore Campeche, Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Limon, M.

1996-08-01

A new petroleum system in the Sonda de Campeche of Mexico has been recently defined. This system is entirely Oxfordian in age, comprising eolian and beach sandstone reservoirs overlain by evaporates, which provide the seal, and in turn, overlain by organically rich, low energy carbonate mudstones, which are source rocks. This petroleum system was created during the late stages of opening of the Gulf of Mexico. The source rocks are composed of an algal mudstone overlying the evaporite sequence. Geochemistry, isotopic and biomarkers analyses allowed us to identify the Oxfordian source rock and also to obtain an excellent correlation withmore » the Oxfordian oils reservoired in the discoveries. Oxfordian sandstones in the Sonda de Campeche exhibit excellent reservoir quality, ranging from 6 to 26% porosity and 2 to 2730 md permeability. The porosity is principally secondary due to the dissolution of dolomite, anhydrite and cement, but intergranular porosity can also be observed. The tectonic evolution of the Gulf of Mexico in the Sonda de Campeche produced three types of traps (1) faulted blocks of {open_quotes}domino{close_quotes} style, developed during the extensional stage; (2) faulted anticlines formed during the Middle Miocene compressive event; and (3) traps related to diapirism of salt of the Middle Miocene-Pleistocene. The seal rocks are mainly composed by Oxfordian evaporates. Oil generation was initiated in the Middle Miocene following the compressional stage. The potential source rocks reached maturity beneath a thick Tertiary overburden in downthrown fault blocks and expelled hydrocarbons which migrated in a predominantly vertical direction. The oils do not show any diagnostic evidence of bacterial alteration.« less

A new petroleum system in offshore Campeche, Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gonzalez, R.; Cruz, P.; Limon, M.

1995-08-01

A new petroleum system in the Sonda de Campeche of Mexico has been recently defined. This system is entirely Oxfordian in age, comprising eolian and beach sandstone reservoirs overlain by evaporites, which provide the seal, and in turn, overlain by organically rich, low energy carbonate mudstones, which are source rocks. This petroleum system was created during the late stages of opening of the Gulf of Mexico. The source rocks are composed of an algal mudstone overlying the evaporite sequence. Geochemistry, isotopic and biomarkers analyses allowed us to identify the Oxfordian source rock and also to obtain an excellent correlation withmore » the oils Oxfordian reservoired in the discoveries. Oxfordian sandstones in the Sonda de Campeche exhibit excellent reservoir quality, ranging from 6 to 26% porosity and 2 to 2730 md permeability. The porosity is principally secondary due to the dissolution of dolomite anhydrite and cement but intergranular porosity can also be observed. The tectonic evolution of the Gulf of Mexico, in the Sonda de Campeche produced three types of traps (1) faulted blocks of {open_quotes}domino{close_quotes} style, developed during the extensional stage; (2) faulted anticlines formed during the Middle Miocene compressive event; and (3) traps related to diapirism of salt of the Middle Miocene-Pleistocene. The seal rocks are mainly composed by Oxfordian evaporates. Oil generation was initiated in the Middle Miocene following the compressional stage. The potential source rocks reached maturity beneath a thick Tertiary overburden in downthrown fault blocks and expelled hydrocarbons which migrated in a predominantly vertical direction. The oils do not show any diagnostic evidence of bacterial alteration.« less

Comparison of the petroleum systems of East Venezuela in their tectonostratigraphic context

DOE Office of Scientific and Technical Information (OSTI.GOV)

Stronach, N.J.; Kerr, H.M.; Scotchmer, J.

1996-08-01

The Maturin and Guarico subbasins of East Venezuela record the transition from Cretaceous passive margin to Tertiary foreland basin with local post-orogenic transtensional basins. Petroleum is reservoired in several units ranging from Albian (El Cantil Formation) to Pliocene (Las Piedras Formation) age. Source rocks are principally in the Upper Cretaceous (Querecual Formation), and Miocene (Carapita Formation) in the Maturin subbasin and in the Upper Cretaceous (Tigre Formation) and Oligocene (Roblecito and La Pascua Formations) in the Guarico subbasin. An extensive well database has been used to address the distribution and provenance of hydrocarbons in the context of a tectonostratigraphic modelmore » for the evolution of the East Venezuela basin. Nine major plays have been described, comprising thirteen petroleum systems. The principal factors influencing the components of individual petroleum systems are as follows: (1) structural controls on Upper Cretaceous source rock distribution, relating to block faulting on the proto-Caribbean passive margin; (2) paleoenvironmental controls on source rock development within the Oligocene-Miocene foreland basin; and (3) timing of subsidence and maturation within the Oligocene-Upper Miocene foreland basin and the configuration of the associated fold and thrust belt, influencing long range and local migration routes (4) local development of Pliocene post-orogenic transtensional basins, influencing hydrocarbon generation, migration and remigration north of the Pirital High.« less

Restoration of Circum-Arctic Upper Jurassic source rock paleolatitude based on crude oil geochemistry

USGS Publications Warehouse

Peters, K.E.; Ramos, L.S.; Zumberge, J.E.; Valin, Z.C.; Scotese, C.R.

2008-01-01

Tectonic geochemical paleolatitude (TGP) models were developed to predict the paleolatitude of petroleum source rock from the geochemical composition of crude oil. The results validate studies designed to reconstruct ancient source rock depositional environments using oil chemistry and tectonic reconstruction of paleogeography from coordinates of the present day collection site. TGP models can also be used to corroborate tectonic paleolatitude in cases where the predicted paleogeography conflicts with the depositional setting predicted by the oil chemistry, or to predict paleolatitude when the present day collection locality is far removed from the source rock, as might occur due to long distance subsurface migration or transport of tarballs by ocean currents. Biomarker and stable carbon isotope ratios were measured for 496 crude oil samples inferred to originate from Upper Jurassic source rock in West Siberia, the North Sea and offshore Labrador. First, a unique, multi-tiered chemometric (multivariate statistics) decision tree was used to classify these samples into seven oil families and infer the type of organic matter, lithology and depositional environment of each organofacies of source rock [Peters, K.E., Ramos, L.S., Zumberge, J.E., Valin, Z.C., Scotese, C.R., Gautier, D.L., 2007. Circum-Arctic petroleum systems identified using decision-tree chemometrics. American Association of Petroleum Geologists Bulletin 91, 877-913]. Second, present day geographic locations for each sample were used to restore the tectonic paleolatitude of the source rock during Late Jurassic time (???150 Ma). Third, partial least squares regression (PLSR) was used to construct linear TGP models that relate tectonic and geochemical paleolatitude, where the latter is based on 19 source-related biomarker and isotope ratios for each oil family. The TGP models were calibrated using 70% of the samples in each family and the remaining 30% of samples were used for model validation. Positive relationships exist between tectonic and geochemical paleolatitude for each family. Standard error of prediction for geochemical paleolatitude ranges from 0.9?? to 2.6?? of tectonic paleolatitude, which translates to a relative standard error of prediction in the range 1.5-4.8%. The results suggest that the observed effect of source rock paleolatitude on crude oil composition is caused by (i) stable carbon isotope fractionation during photosynthetic fixation of carbon and (ii) species diversity at different latitudes during Late Jurassic time. ?? 2008 Elsevier Ltd. All rights reserved.

The Red Sea Basin Province: Sudr-Nubia(!) and Maqna(!) Petroleum Systems

USGS Publications Warehouse

Lindquist, Sandra J.

1999-01-01

The Sudr-Nubia(!) oil-prone total petroleum system dominates the densely explored Gulf of Suez part of the rifted Red Sea Basin Province. Upper Cretaceous to Eocene source rocks, primarily the Senonian Sudr Formation, are organic-rich, areally uniform marine carbonates that have generated known ultimate recoverable reserves exceeding 11 BBOE. The name Nubia is used for sandstone reservoirs with a wide range of poorly constrained, pre-rift geologic ages ranging from Early Paleozoic to Early Cretaceous. Syn- and post-rift Tertiary reservoirs, especially the Kareem Formation, also contain significant reserves. Partly overlapping Sudr-Nubia(!) is the areally larger and geochemically distinct, oil-and-gas-prone Maqna(!) total petroleum system within the southern Gulf of Suez basin and the sparsely explored remaining Red Sea basin. Known ultimate recoverable reserves are 50-100 MMBOE and more than 900 MMBOE, respectively, in those areas. Both the source and reservoir rocks in this petroleum system are Tertiary, dominantly Miocene, in age. Maqna(!) has the greater potential for future resource development.

Tectono-thermal Evolution of the Lower Paleozoic Petroleum Source Rocks in the Southern Lublin Trough: Implications for Shale Gas Exploration from Maturity Modelling

NASA Astrophysics Data System (ADS)

Botor, Dariusz

2018-03-01

The Lower Paleozoic basins of eastern Poland have recently been the focus of intensive exploration for shale gas. In the Lublin Basin potential unconventional play is related to Lower Silurian source rocks. In order to assess petroleum charge history of these shale gas reservoirs, 1-D maturity modeling has been performed. In the Łopiennik IG-1 well, which is the only well that penetrated Lower Paleozoic strata in the study area, the uniform vitrinite reflectance values within the Paleozoic section are interpreted as being mainly the result of higher heat flow in the Late Carboniferous to Early Permian times and 3500 m thick overburden eroded due to the Variscan inversion. Moreover, our model has been supported by zircon helium and apatite fission track dating. The Lower Paleozoic strata in the study area reached maximum temperature in the Late Carboniferous time. Accomplished tectono-thermal model allowed establishing that petroleum generation in the Lower Silurian source rocks developed mainly in the Devonian - Carboniferous period. Whereas, during Mesozoic burial, hydrocarbon generation processes did not develop again. This has negative influence on potential durability of shale gas reservoirs.

The Chuar Petroleum System, Arizona and Utah

USGS Publications Warehouse

Lillis, Paul G.

2016-01-01

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

The New Albany Shale Petroleum System, Illinois Basin - Data and Map Image Archive from the Material-Balance Assessment

USGS Publications Warehouse

Higley, Debra K.; Henry, M.E.; Lewan, M.D.; Pitman, Janet K.

2003-01-01

The data files and explanations presented in this report were used to generate published material-balance approach estimates of amounts of petroleum 1) expelled from a source rock, and the sum of 2) petroleum discovered in-place plus that lost due to 3) secondary migration within, or leakage or erosion from a petroleum system. This study includes assessment of cumulative production, known petroleum volume, and original oil in place for hydrocarbons that were generated from the New Albany Shale source rocks.More than 4.00 billion barrels of oil (BBO) have been produced from Pennsylvanian-, Mississippian-, Devonian-, and Silurian-age reservoirs in the New Albany Shale petroleum system. Known petroleum volume is 4.16 BBO; the average recovery factor is 103.9% of the current cumulative production. Known petroleum volume of oil is 36.22% of the total original oil in place of 11.45 BBO. More than 140.4 BBO have been generated from the Upper Devonian and Lower Mississippian New Albany Shale in the Illinois Basin. Approximately 86.29 billion barrels of oil that was trapped south of the Cottage Grove fault system were lost by erosion of reservoir intervals. The remaining 54.15 BBO are 21% of the hydrocarbons that were generated in the basin and are accounted for using production data. Included in this publication are 2D maps that show the distribution of production for different formations versus the Rock-Eval pyrolysis hydrogen-indices (HI) contours, and 3D images that show the close association between burial depth and HI values.The primary vertical migration pathway of oil and gas was through faults and fractures into overlying reservoir strata. About 66% of the produced oil is located within the generative basin, which is outlined by an HI contour of 400. The remaining production is concentrated within 30 miles (50 km) outside the 400 HI contour. The generative basin is subdivided by contours of progressively lower hydrogen indices that represent increased levels of thermal maturity and generative capacity of New Albany Shale source rocks. The generative basin was also divided into seven oil-migration catchments. The catchments were determined using a surface-flow hydrologic model with contoured HI values as input to the model.

Petroleum systems of the San Joaquin Basin Province -- geochemical characteristics of gas types: Chapter 10 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Lillis, Paul G.; Warden, Augusta; Claypool, George E.; Magoon, Leslie B.

2008-01-01

The San Joaquin Basin Province is a petroliferous basin filled with predominantly Late Cretaceous to Pliocene-aged sediments, with organic-rich marine rocks of Late Cretaceous, Eocene, and Miocene age providing the source of most of the oil and gas. Previous geochemical studies have focused on the origin of the oil in the province, but the origin of the natural gas has received little attention. To identify and characterize natural gas types in the San Joaquin Basin, 66 gas samples were analyzed and combined with analyses of 15 gas samples from previous studies. For the purpose of this resource assessment, each gas type was assigned to the most likely petroleum system. Three general gas types are identified on the basis of bulk and stable carbon isotopic composition—thermogenic dry (TD), thermogenic wet (TW) and biogenic (B). The thermogenic gas types are further subdivided on the basis of the δ13C values of methane and ethane and nitrogen content into TD-1, TD-2, TD-Mixed, TW-1, TW-2, and TW-Mixed. Gas types TD-1 and TD-Mixed, a mixture of biogenic and TD-1 gases, are produced from gas fields in the northern San Joaquin Basin. Type TD-1 gas most likely originated from the Late Cretaceous to Paleocene Moreno Formation, a gas-prone source rock. The biogenic component of the TD-Mixed gas existed in the trap prior to the influx of thermogenic gas. For the assessment, these gas types were assigned to the Winters- Domengine Total Petroleum System, but subsequent to the assessment were reclassified as part of the Moreno-Nortonville gas system. Dry thermogenic gas produced from oil fields in the southern San Joaquin Basin (TD-2 gas) most likely originated from the oil-prone source rock of Miocene age. These samples have low wetness values due to migration fractionation or biodegradation. The thermogenic wet gas types (TW-1, TW-2, TW-Mixed) are predominantly associated gas produced from oil fields in the southern and central San Joaquin Basin. Type TW-1 gas most likely originates from source rocks within the Eocene Kreyenhagen Formation or the Eocene Tumey formation of Atwill (1935). Type TW-2 gas most likely originates from the Miocene Monterey Formation and equivalents. TW-Mixed gas is likely a mixture of biogenic and wet thermogenic gas (TW-1 or TW-2) derived from source rocks mentioned above. The thermogenic wet gas types are included in the corresponding Eocene or Miocene total petroleum systems. Type B gas is a dry, nonassociated gas produced from the Pliocene San Joaquin Formation in the central and southern San Joaquin Basin. This gas type most likely originated from Pliocene marine source rocks as a product of methanogenesis, and defines the Neogene Nonassociated Gas Total Petroleum System.

Late Cretaceous-Cenozoic Basin framework and petroleum potential of Panama and Costa Rica

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mann, P.; Kolarsky, R.

Despite its location between major petroleum provinces in northwestern South America and northern Central America, there is a widespread negative perception of the petroleum potential of Panama and Costa Rica in southern Central America. Several factors may contribute to this perception: (1) the on and offshore geology of many areas has only be studied in a reconnaissance fashion; (2) sandstone reservoirs and source rocks are likely to be of poor quality because Upper Cretaceous-Cenozoic sandstones are eroded from island arc or oceanic basement rocks and because oil-prone source rocks are likely to be scarce in near-arc basins; and (3) structuralmore » traps are likely to be small and fragmented because of complex late Cenozoic thrust and strike-slip tectonics. On the other hand, onshore oil and gas seeps, shows and small production in wildcat wells, and source rocks with TOC values up to 26% suggest the possibility of future discoveries. In this talk, we present the results of a regional study using 3100 km of offshore seismic lines kindly provided by industry. Age and stratigraphic control of offshore lines is constrained by limited well data and detailed field studies of basin outcrops in coastal areas. We describe the major structures, stratigraphy, and tectonic history of the following areas: Gulf of Panama and Gulf of Chiriqui of Panama and the Pacific and Caribbean margins of Costa Rica.« less

Thermal Maturity Data Used by the U.S. Geological Survey for the U.S. Gulf Coast Region Oil and Gas Assessment

USGS Publications Warehouse

Dennen, Kristin O.; Warwick, Peter D.; McDade, Elizabeth Chinn

2010-01-01

The U.S. Geological Survey is currently assessing the oil and natural gas resources of the U.S. Gulf of Mexico region using a total petroleum system approach. An essential part of this geologically based method is evaluating the effectiveness of potential source rocks in the petroleum system. The purpose of this report is to make available to the public RockEval and vitrinite reflectance data from more than 1,900 samples of Mesozoic and Tertiary rock core and coal samples in the Gulf of Mexico area in a format that facilitates inclusion into a geographic information system. These data provide parameters by which the thermal maturity, type, and richness of potential sources of oil and gas in this region can be evaluated.

Chapter 1: An overview of the petroleum geology of the Arctic

USGS Publications Warehouse

Spencer, A.M.; Embry, A.F.; Gautier, D.L.; Stoupakova, A.V.; Sorensen, K.

2011-01-01

Nine main petroleum provinces containing recoverable resources totalling 61 Bbbl liquids + 269 Bbbloe of gas are known in the Arctic. The three best known major provinces are: West Siberia-South Kara, Arctic Alaska and Timan-Pechora. They have been sourced principally from, respectively, Upper Jurassic, Triassic and Devonian marine source rocks and their hydrocarbons are reservoired principally in Cretaceous sandstones, Triassic sandstones and Palaeozoic carbonates. The remaining six provinces except for the Upper Cretaceous-Palaeogene petroleum system in the Mackenzie Delta have predominantly Mesozoic sources and Jurassic reservoirs. There are discoveries in 15% of the total area of sedimentary basins (c. 8 ?? 106 km2), dry wells in 10% of the area, seismic but no wells in 50% and no seismic in 25%. The United States Geological Survey estimate yet-to-find resources to total 90 Bbbl liquids + 279 Bbbloe gas, with four regions - South Kara Sea, Alaska, East Barents Sea, East Greenland - dominating. Russian estimates of South Kara Sea and East Barents Sea are equally positive. The large potential reflects primarily the large undrilled areas, thick basins and widespread source rocks. ?? 2011 The Geological Society of London.

Burial History, Thermal Maturity, and Oil and Gas Generation History of Source Rocks in the Bighorn Basin, Wyoming and Montana

USGS Publications Warehouse

Roberts, Laura N.R.; Finn, Thomas M.; Lewan, Michael D.; Kirschbaum, Mark A.

2008-01-01

Burial history, thermal maturity, and timing of oil and gas generation were modeled for seven key source-rock units at eight well locations throughout the Bighorn Basin in Wyoming and Montana. Also modeled was the timing of cracking to gas of Phosphoria Formation-sourced oil in the Permian Park City Formation reservoirs at two well locations. Within the basin boundary, the Phosphoria is thin and only locally rich in organic carbon; it is thought that the Phosphoria oil produced from Park City and other reservoirs migrated from the Idaho-Wyoming thrust belt. Other petroleum source rocks include the Cretaceous Thermopolis Shale, Mowry Shale, Frontier Formation, Cody Shale, Mesaverde and Meeteetse Formations, and the Tertiary (Paleocene) Fort Union Formation. Locations (wells) selected for burial history reconstructions include three in the deepest parts of the Bighorn Basin (Emblem Bench, Red Point/Husky, and Sellers Draw), three at intermediate depths (Amoco BN 1, Santa Fe Tatman, and McCulloch Peak), and two at relatively shallow locations (Dobie Creek and Doctor Ditch). The thermal maturity of source rocks is greatest in the deep central part of the basin and decreases to the south, east, and north toward the basin margins. The Thermopolis and Mowry Shales are predominantly gas-prone source rocks, containing a mix of Type-III and Type-II kerogens. The Frontier, Cody, Mesaverde, Meeteetse, and Fort Union Formations are gas-prone source rocks containing Type-III kerogen. Modeling results indicate that in the deepest areas, (1) the onset of petroleum generation from Cretaceous rocks occurred from early Paleocene through early Eocene time, (2) peak petroleum generation from Cretaceous rocks occurred during Eocene time, and (3) onset of gas generation from the Fort Union Formation occurred during early Eocene time and peak generation occurred from late Eocene to early Miocene time. Only in the deepest part of the basin did the oil generated from the Thermopolis and Mowry Shales start generating gas from secondary cracking, which occurred in the late Eocene to Miocene. Also, based on modeling results, gas generation from the cracking of Phosphoria oil reservoired in the Park City Formation began in the late Eocene in the deep part of the basin but did not anywhere reach peak generation.

Petroleum source potential of the Lower Cretaceous mudstone succession of the NPRA and Colville Delta area, North Slope Alaska, based on sonic and resistivity logs

USGS Publications Warehouse

Keller, Margaret A.; Bird, Kenneth J.

2003-01-01

Resource assessment of the North Slope of Alaska by the U. S. Geological Survey includes evaluation of the petroleum source potential of Mesozoic and Cenozoic rocks using the delta log R technique (Passey and others, 1990). Porosity and resistivity logs are used in combination with thermal maturity data to produce a continuous profile of total organic carbon content in weight % (TOC). From the pattern and amount of TOC in the profile produced, the depositional setting and thus the petroleum source-rock potential (kerogen type) of the organic matter can be inferred and compared to interpretations from other data such as Rock-Eval pyrolysis. TOC profiles determined by this technique for the contiguous interval of pebble shale unit, Hue Shale (including the Gamma Ray Zone or GRZ), and lower part of the Torok Formation indicate important potential for petroleum generation in the Tunalik 1, Inigok 1, N. Inigok 1, Kuyanak 1, Texaco Colville Delta 1, Nechelik 1, and Bergschrund 1 wells of the western North Slope region. TOC profiles suggest that this interval contains both type II and III kerogens – consistent with proposed depositional models -- and is predominantly greater than 2 wt. % TOC (cut-off used for effective source potential). Average TOC for the total effective section of the pebble shale unit + Hue Shale ranges from 2.6 to 4.1 wt % TOC (values predominantly 2-8% TOC) over 192-352 ft. Source potential for the lower Torok Formation, which also has interbedded sandstone and lean mudstone, is good to negligible in these 7 wells.

Structural evolution and petroleum productivity of the Baltic basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ulmishek, G.F.

The Baltic basin is an oval depression located in the western part of the Russian craton; it occupies the eastern Baltic Sea and adjacent onshore areas. The basin contains more than 5,000 m of sedimentary rocks ranging from latest Proterozoic to Tertiary in age. These rocks consist of four tectonostratigraphic sequences deposited during major tectonic episodes of basin evolution. Principal unconformities separate the sequences. The basin is underlain by a rift probably filled with Upper Proterozoic rocks. Vendian and Lower Cambrian rocks (Baikalian sequence) form two northeast-trending depressions. The principal stage of the basin development was during deposition of amore » thick Middle Cambrian-Lower Devonian (Caledonian) sequence. This stage was terminated by the most intense deformations in the basin history. The Middle Devonian-Carboniferous (Hercynian) and Permian-Tertiary (Kimmerian-Alpine) tectonic and depositional cycles only slightly modified the basin geometry and left intact the main structural framework of underlying rocks. The petroleum productivity of the basin is related to the Caledonian tectonostratigraphic sequence that contains both source rocks and reservoirs. However, maturation of source rocks, migration of oil, and formation of fields took place mostly during deposition of the Hercynian sequence.« less

Map and digital database of sedimentary basins and indications of petroleum in the Central Alaska Province

USGS Publications Warehouse

Troutman, Sandra M.; Stanley, Richard G.

2003-01-01

This database and accompanying text depict historical and modern reported occurrences of petroleum both in wells and at the surface within the boundaries of the Central Alaska Province. These data were compiled from previously published and unpublished sources and were prepared for use in the 2002 U.S. Geological Survey petroleum assessment of Central Alaska, Yukon Flats region. Indications of petroleum are described as oil or gas shows in wells, oil or gas seeps, or outcrops of oil shale or oil-bearing rock and include confirmed and unconfirmed reports. The scale of the source map limits the spatial resolution (scale) of the database to 1:2,500,000 or smaller.

Preliminary source rock evaluation and hydrocarbon generation potential of the early Cretaceous subsurface shales from Shabwah sub-basin in the Sabatayn Basin, Western Yemen

NASA Astrophysics Data System (ADS)

Al-Matary, Adel M.; Hakimi, Mohammed Hail; Al Sofi, Sadam; Al-Nehmi, Yousif A.; Al-haj, Mohammed Ail; Al-Hmdani, Yousif A.; Al-Sarhi, Ahmed A.

2018-06-01

A conventional organic geochemical study has been performed on the shale samples collected from the early Cretaceous Saar Formation from the Shabwah oilfields in the Sabatayn Basin, Western Yemen. The results of this study were used to preliminary evaluate the potential source-rock of the shales in the Saar Formation. Organic matter richness, type, and petroleum generation potential of the analysed shales were assessed. Total organic carbon content and Rock- Eval pyrolysis results indicate that the shale intervals within the early Cretaceous Saar Formation have a wide variation in source rock generative potential and quality. The analysed shale samples have TOC content in the range of 0.50 and 5.12 wt% and generally can be considered as fair to good source rocks. The geochemical results of this study also indicate that the analysed shales in the Saar Formation are both oil- and gas-prone source rocks, containing Type II kerogen and mixed Types II-III gradient to Type III kerogen. This is consistent with Hydrogen Index (HI) values between 66 and 552 mg HC/g TOC. The temperature-sensitive parameters such as vitrinite reflectance (%VRo), Rock-Eval pyrolysis Tmax and PI reveal that the analysed shale samples are generally immature to early-mature for oil-window. Therefore, the organic matter has not been altered by thermal maturity thus petroleum has not yet generated. Therefore, exploration strategies should focus on the known deeper location of the Saar Formation in the Shabwah-sub-basin for predicting the kitchen area.

Petroleum geology and resources of the Nepa-Botuoba High, Angara-Lena Terrace, and Cis-Patom Foredeep, southeastern Siberian Craton, Russia

USGS Publications Warehouse

Ulmishek, Gregory F.

2001-01-01

Three structural provinces of this report, the Nepa-Botuoba High, the Angara-Lena Terrace, and the Cis-Patom Foredeep, occupy the southeastern part of the Siberian craton northwest of the Baikal-Patom folded region (fig. 1). The provinces are similar in many aspects of their history of development, stratigraphic composition, and petroleum geology characteristics. The sedimentary cover of the provinces overlies the Archean?Lower Proterozoic basement of the Siberian craton. Over most of the area of the provinces, the basement is covered by Vendian (uppermost Proterozoic, 650?570 Ma) clastic and carbonate rocks. Unlike the case in the more northwestern areas of the craton, older Riphean sedimentary rocks here are largely absent and they appear in the stratigraphic sequence only in parts of the Cis-Patom Foredeep province. Most of the overlying sedimentary section consists of Cambrian and Ordovician carbonate and clastic rocks, and it includes a thick Lower Cambrian salt-bearing formation. Younger rocks are thin and are present only in marginal areas. 1 A single total petroleum system (TPS) embraces all three provinces. The TPS is unique in two aspects: (1) its rich hydro-carbon reserves are derived from Precambrian source rocks and (2) preservation of oil and gas fields is extremely long owing to the presence of the Lower Cambrian undeformed salt seal. Discovered reserves of the TPS are about 2 billion barrels of oil and more than 30 trillion cubic feet of gas. The stratigraphic distribution of oil and gas reserves is narrow; all fields are in Vendian to lowermost Cambrian clastic and carbonate reservoirs that occur below Lower Cambrian salt. Both structural and stratigraphic traps are known. Source rocks are absent in the sedimentary cover of the provinces, with the possible exception of a narrow zone on the margin of the Cis-Patom Foredeep province. Source rocks are interpreted here to be Riphean and Vendian organic-rich shales of the Baikal-Patom folded region. These rocks presently are deformed and metamorphosed, but they generated oil and gas before the deformation occurred in Late Silurian and Devonian time. Generated hydrocarbons migrated updip onto the craton margin. The time of migration and formation of fields is constrained by the deposition of Lower Cambrian salt and by the Late Silurian or Devonian metamorphism of source rocks. This time frame indicates that the TPS is one of the oldest petroleum systems in the world. All three provinces are exploration frontiers, and available geologic data are limited; therefore, only one assessment unit has been identified. The largest undiscovered hydrocarbon resources are expected to be in Vendian clastic reservoirs in both structural and stratigraphic traps of the Nepa-Botuoba High province. The petroleum potential of Vendian?lowermost Cambrian carbonate reservoirs is smaller. Nevertheless, these reservoirs may contain significant resources. Gas is expected to dominate over oil in the resource base.

National Assessment of Oil and Gas Project: Petroleum Systems and Geologic Assessment of Undiscovered Oil and Gas, Hanna, Laramie, and Shirley Basins Province, Wyoming

USGS Publications Warehouse

U.S. Geological Survey Hanna, Laramie

2007-01-01

INTRODUCTION The purpose of the U.S. Geological Survey?s (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered oil and gas potential of the Hanna, Laramie, and Shirley Basins Province in Wyoming and northeastern Colorado. The assessment is based on the geologic elements of each total petroleum system (TPS) defined in the province, including hydrocarbon source rocks (source-rock maturation, hydrocarbon generation, and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined three TPSs and seven assessment units (AUs) within them; undiscovered resources for three of the seven AUs were quantitatively assessed.

Hydrocarbon potential evaluation of the source rocks from the Abu Gabra Formation in the Sufyan Sag, Muglad Basin, Sudan

NASA Astrophysics Data System (ADS)

Qiao, Jinqi; Liu, Luofu; An, Fuli; Xiao, Fei; Wang, Ying; Wu, Kangjun; Zhao, Yuanyuan

2016-06-01

The Sufyan Sag is one of the low-exploration areas in the Muglad Basin (Sudan), and hydrocarbon potential evaluation of source rocks is the basis for its further exploration. The Abu Gabra Formation consisting of three members (AG3, AG2 and AG1 from bottom to top) was thought to be the main source rock formation, but detailed studies on its petroleum geology and geochemical characteristics are still insufficient. Through systematic analysis on distribution, organic matter abundance, organic matter type, organic matter maturity and characteristics of hydrocarbon generation and expulsion of the source rocks from the Abu Gabra Formation, the main source rock members were determined and the petroleum resource extent was estimated in the study area. The results show that dark mudstones are the thickest in the AG2 member while the thinnest in the AG1 member, and the thickness of the AG3 dark mudstone is not small either. The AG3 member have developed good-excellent source rock mainly with Type I kerogen. In the Southern Sub-sag, the AG3 source rock began to generate hydrocarbons in the middle period of Bentiu. In the early period of Darfur, it reached the hydrocarbon generation and expulsion peak. It is in late mature stage currently. The AG2 member developed good-excellent source rock mainly with Types II1 and I kerogen, and has lower organic matter abundance than the AG3 member. In the Southern Sub-sag, the AG2 source rock began to generate hydrocarbons in the late period of Bentiu. In the late period of Darfur, it reached the peak of hydrocarbon generation and its expulsion. It is in middle mature stage currently. The AG1 member developed fair-good source rock mainly with Types II and III kerogen. Throughout the geological evolution history, the AG1 source rock has no effective hydrocarbon generation or expulsion processes. Combined with basin modeling results, we have concluded that the AG3 and AG2 members are the main source rock layers and the Southern Sub-sag is the main source kitchen in the study area. The AG3 and AG2 source rocks have supplied 58.1% and 41.9% of the total hydrocarbon generation, respectively, and 54.9% and 45.1% of the total hydrocarbon expulsion, respectively. Their hydrocarbon expulsion efficiency ratios are 71.0% and 62.3%, respectively. The Southern Sub-sag has supplied more than 90% of the total amounts of hydrocarbon generation and its expulsion.

Petroleum source-rock potentials of the cretaceous transgressive-regressive sedimentary sequences of the Cauvery Basin

NASA Astrophysics Data System (ADS)

Chandra, Kuldeep; Philip, P. C.; Sridharan, P.; Chopra, V. S.; Rao, Brahmaji; Saha, P. K.

The present work is an attempt to contribute to knowledge on the petroleum source-rock potentials of the marine claystones and shales of basins associated with passive continental margins where the source-rock developments are known to have been associated with the anoxic events in the Mesozoic era. Data on three key exploratory wells from three major depressions Ariyallur-Pondicherry, Thanjavur and Nagapattinam of the Cauvery Basin are described and discussed. The average total organic carbon contents of the transgressive Pre-Albian-Cinomanian and Coniacian/Santonian claystones/shales range from 1.44 and 1.16%, respectively. The transgressive/regressive Campanian/Maastrichtian claystones contain average total organic carbon varying from 0.62 to 1.19%. The kerogens in all the studied stratigraphic sequences are classified as type-III with Rock-Eval hydrogen indices varying from 30 to 275. The nearness of land masses to the depositional basin and the mainly clastic sedimentation resulted in accumulation and preservation of dominantly type-III kerogens. The Pre-Albian to Cinomanian sequences of peak transgressive zone deposited in deep marine environments have kerogens with a relatively greater proportion of type-II components with likely greater contribution of planktonic organic matters. The global anoxic event associated with the Albian-Cinomanian marine transgression, like in many other parts of the world, has pervaded the Cauvery Basin and favoured development of good source-rocks with type-III kerogens. The Coniacian-Campanian-Maastrichtian transgressive/regressive phase is identified to be relatively of lesser significance for development of good quality source-rocks.

An overview on source rocks and the petroleum system of the central Upper Rhine Graben

NASA Astrophysics Data System (ADS)

Böcker, Johannes; Littke, Ralf; Forster, Astrid

2017-03-01

The petroleum system of the Upper Rhine Graben (URG) comprises multiple reservoir rocks and four major oil families, which are represented by four distinct source rock intervals. Based on geochemical analyses of new oil samples and as a review of chemical parameter of former oil fields, numerous new oil-source rock correlations were obtained. The asymmetric graben resulted in complex migration pathways with several mixed oils as well as migration from source rocks into significantly older stratigraphic units. Oldest oils originated from Liassic black shales with the Posidonia Shale as main source rock (oil family C). Bituminous shales of the Arietenkalk-Fm. (Lias α) show also significant source rock potential representing the second major source rock interval of the Liassic sequence. Within the Tertiary sequence several source rock intervals occur. Early Tertiary coaly shales generated high wax oils that accumulated in several Tertiary as well as Mesozoic reservoirs (oil family B). The Rupelian Fish Shale acted as important source rock, especially in the northern URG (oil family D). Furthermore, early mature oils from the evaporitic-salinar Corbicula- and Lower Hydrobienschichten occur especially in the area of the Heidelberg-Mannheim-Graben (oil family A). An overview on potential source rocks in the URG is presented including the first detailed geochemical source rock characterization of Middle Eocene sediments (equivalents to the Bouxwiller-Fm.). At the base of this formation a partly very prominent sapropelic coal layer or coaly shale occurs. TOC values of 20-32 % (cuttings) and Hydrogen Index (HI) values up to 640-760 mg HC/g TOC indicate an extraordinary high source rock potential, but a highly variable lateral distribution in terms of thickness and source rock facies is also supposed. First bulk kinetic data of the sapropelic Middle Eocene coal and a coaly layer of the `Lymnäenmergel' are presented and indicate oil-prone organic matter characterized by low activation energies. These sediments are considered as most important source rocks of numerous high wax oils (oil family B) in addition to the coaly source rocks from the (Lower) Pechelbronn-Schichten (Late Eocene). Migration pathways are significantly influenced by the early graben evolution. A major erosion period occurred during the latest Cretaceous. The uplift center was located in the northern URG area, resulting in SSE dipping Mesozoic strata in the central URG. During Middle Eocene times a second uplift center in the Eifel area resulted in SW-NE-directed shore lines in the central URG and contemporaneous south-southeastern depocenters during marine transgression from the south. This structural setting resulted in a major NNW-NW-directed and topography-driven migration pattern for expelled Liassic oil in the fractured Mesozoic subcrop below sealing Dogger α clays and basal Tertiary marls.

Petroleum Systems of the Nigerian Sector of Chad Basin: Insights from Field and Subsurface Data

NASA Astrophysics Data System (ADS)

Suleiman, A. A.; Nwaobi, G. O.; Bomai, A.; Dauda, R.; Bako, M. D.; Ali, M. S.; Moses, S. D.

2017-12-01

A.A. Suleiman, A. Bomai, R. Dauda, O.G. NwaobiNigerian National Petroleum CorporationAbstract:Formation of the West and Central African Rift systems (WCARS) reflects intra-plate deformation linked to the Early to Late Cretaceous opening of South Atlantic Ocean. From an economic point of view, the USGS (2010) estimated Chad Basin, which is part of WCARS rift system to contain, up to 2.32 BBO and 14.62 TCF. However, there has been no exploration success in the Nigerian sector of the Chad Basin principally because of a poor understanding of the basin tectono-stratigraphic evolution and petroleum system development. In this study, we use 3D seismic, geochemical and field data to construct a tectono-stratigraphic framework of the Nigerian sector of Chad Basin; within this framework we then investigate the basins petroleum system development. Our analysis suggests two key plays exist in the basin, Lower and Upper Cretaceous plays. Pre-Bima lacustrine shale and the Gongila Formation constitute the prospective source rocks for the Lower Cretaceous play, whereas the Fika Shale may provide the source, for the Upper Cretaceous play. Source rock hydrocarbon modeling indicates possible oil and gas generation and expulsion from the lacustrine shales and Fika Shale in Cretaceous and Tertiary times respectively. Bima Sandstone and weathered basement represent prospective reservoirs for the Lower Cretaceous play and intra-Fika sandstone beds for the Upper Cretaceous play. We identify a range of trapping mechanisms such as inversion-related anticlines. Shales of the Gongila Formation provide the top sealing for the Lower Cretaceous play. Our field observations have proved presence of the key elements of the petroleum system in the Nigerian Sector of the Chad Basin. It has also demonstrated presence of igneous intrusions in the stratigraphy of the basin that we found to influence the hydrocarbon potential of the basin through source rock thermal maturity and degradation. Our study indicates that Nigerian sector of the Chad Basin is affected by igneous activity and basin inversion both of which impact its petroleum system development. Therefore, a detailed study of the tectono-stratigraphic framework of a rift basin is crucial to investigate the development of its petroleum system and hydrocarbon prospectivity.

The Bolivian source rocks: Sub Andean Zone-Madre de Dios-Chaco

DOE Office of Scientific and Technical Information (OSTI.GOV)

Moretti, I.; Montemurro, G.; Aguilera, E.

A complete study of source rocks has been carried out in the Bolivian foothills and foreland (Sub Andean Zone, Chaco and Madre de Dios) in order to quantify the petroleum potential of the area. Besides the classical mid-Devonian source rocks (Tequeje Formation in the north, Limoncito Formation in the center and Los Monos Formation in the south), others are important: the Tomachi Formation (late Devonian) in the north and the Copacabana Formation (Upper Carboniferous-lower Permian) in the northern Sub Andean Zone. Both show an excellent potential with S{sub 2} over 50 mg HC/g and average values higher than 10 mgmore » HC/g over few hundred meters. The Latest Cretaceous Flora Formation present locally a high potential but is very thin. Almost all the source rocks matured during the Neogene due to the subsidence in the Andean foreland and in the piggyback basins, and are thus involved on the current petroleum system. Silurian and Lower Paleozoic units also contain thick shale beds, but these source rocks were mature before the Jurassic in the south of the country. In the center, the Silurian is not nowadays overmature and may play an important role. The different zones are compared based on their Source Potential Index which indicates that the richest areas are the northern Sub Andean Zone and the Madre de Dios basin with SPI greater than 10 t/m{sup 2}. Since these two areas remain almost unexplored, these results allow us to be optimistic about the possibilities for future exploration.« less

Hydrocarbons in recent sediment of the Monterey Bay National Marine Sanctuary

USGS Publications Warehouse

Kvenvolden, K.A.; Hostettler, F.D.; Rosenbauer, R.W.; Lorenson, T.D.; Castle, W.T.; Sugarman, S.

2002-01-01

A complex mixture of hydrocarbons is present in the recent sediment of the Monterey Bay National Marine Sanctuary. Eighteen samples from the continental shelf between San Francisco and Monterey contain aliphatic and aromatic hydrocarbons showing biological contributions from both marine and terrigenous sources, with the terrigenous indicators more pronounced near Monterey. Of particular interest, however, is a low-level background of petroleum-related compounds, including 28,30-bisnorhopane and 18??+??(H)-oleanane, which are characteristic of many crude oils from the Monterey Formation of California. Thus, the sediments are overprinted by a regional chemical signature which may be derived from eroded Monterey Formation rocks and from onshore and offshore seeps releasing petroleum from Monterey Formation source rocks. ?? 2002 Elsevier Science B.V. All rights reserved.

Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

USGS Publications Warehouse

,

2013-01-01

In 2002, the U.S. Geological Survey (USGS) estimated undiscovered oil and gas resources that have the potential for additions to reserves in the San Juan Basin Province, New Mexico and Colorado. Paleozoic rocks were not appraised. The last oil and gas assessment for the province was in 1995. There are several important differences between the 1995 and 2002 assessments. The area assessed is smaller than that in the 1995 assessment. This assessment of undiscovered hydrocarbon resources in the San Juan Basin Province also used a slightly different approach in the assessment, and hence a number of the plays defined in the 1995 assessment are addressed differently in this report. After 1995, the USGS has applied a total petroleum system (TPS) concept to oil and gas basin assessments. The TPS approach incorporates knowledge of the source rocks, reservoir rocks, migration pathways, and time of generation and expulsion of hydrocarbons; thus the assessments are geologically based. Each TPS is subdivided into one or more assessment units, usually defined by a unique set of reservoir rocks, but which have in common the same source rock. Four TPSs and 14 assessment units were geologically evaluated, and for 13 units, the undiscovered oil and gas resources were quantitatively assessed.

Total Petroleum Systems of the Northwest Shelf, Australia: The Dingo-Mungaroo/Barrow and the Locker-Mungaroo/Barrow

USGS Publications Warehouse

Bishop, Michele G.

1999-01-01

The Northwest Shelf Province (U.S.G.S. #3948) of Australia contains two important hydrocarbon source-rock intervals and numerous high quality reservoir intervals. These are grouped into two petroleum systems, Dingo-Mungaroo/Barrow and Locker-Mungaroo/Barrow, where the Triassic Mungaroo Formation and the Early Cretaceous Barrow Group serve as the major reservoir rocks for the Jurassic Dingo Claystone and Triassic Locker Shale source rocks. The primary source rock, Dingo Claystone, was deposited in restricted marine conditions during the Jurassic subsidence of a regional sub-basin trend. The secondary source rock, Locker Shale, was deposited in terrestrially-influenced, continental seaway conditions during the Early Triassic at the beginning of the breakup of Pangea. These systems share potential reservoir rocks of deep-water, proximal and distal deltaic, marginal marine, and alluvial origins, ranging in age from Late Triassic through Cretaceous. Interformational seals and the regional seal, Muderong Shale, along with structural and stratigraphic traps account for the many types of hydrocarbon accumulations in this province. In 1995, the Northwest Shelf produced 42% of the hydrocarbon liquids in Australia, and in 1996 surpassed the Australian Bass Straits production, with 275,000 barrels per day (bpd) average. This region is the major producing province of Australia. Known reserves as of 1995 are estimated at 11.6 billion of barrels of oil equivalent (BBOE)(Klett and others, 1997) . Although exploration has been conducted since 1955, many types of prospects have not been targeted and major reserves continue to be discovered.

Comparative burial and thermal history of lower Upper Cretaceous strata, Powder River basin, Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Nuccio, V.F.

1989-03-01

Burial histories were reconstructed for three localities in the Powder River basin (PRB), Wyoming. Thermal maturity of lower Upper Cretaceous source rocks was determined by vitrinite reflectance (R/sub m/) and time-temperature index (TTI) modeling, producing independent estimates for timing of the oil window (0.55-1.35% R/sub m/). In the northwestern PRB, lower Upper Cretaceous rocks were buried to about 12,500 ft and achieved a thermal maturity of 0.50% to 0.56% at maximum burial, 10 Ma, based on measured R/sub m/. TTI modeling suggests a slightly higher thermal maturity, with an R/sub m/ equivalent of approximately 0.75%, placing the source rocks atmore » the beginning of the oil window 30 Ma. In the southwestern PRB, lower Upper Cretaceous rocks have been buried to about 15,000 ft and achieved thermal maturities between 0.66% and 0.75% about 10 Ma based on measured R/sub m/; therefore, petroleum generation may have begun slightly earlier. TTI modeling estimates an R/sub m/ equivalent of 1.10%, placing the beginning of the oil window at 45 Ma. In the northeastern PRB, lower Upper Cretaceous rocks have been buried only to approximately 5500 ft. Measured R/sub m/ and TTI modeling indicate a thermal maturity for lower Upper Cretaceous rocks between 0.45% and 0.50% R/sub m/, too low for petroleum generation. The higher R/sub m/ values determined by the TTI models may be due to overestimation of maximum burial depth and/or paleogeothermal gradients. The two independent maturity indicators do, however, constrain fairly narrowly the onset of petroleum generation.« less

Petroleum Systems and Geologic Assessment of Oil and Gas Resources in the Wind River Basin Province, Wyoming

USGS Publications Warehouse

,

2007-01-01

The purpose of the U.S. Geological Survey's (USGS) National Oil and Gas Assessment is to develop geologically based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States. The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered oil and gas potential of the Wind River Basin Province which encompasses about 4.7 million acres in central Wyoming. The assessment is based on the geologic elements of each total petroleum system (TPS) defined in the province, including hydrocarbon source rocks (source-rock maturation, hydrocarbon generation, and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined three TPSs: (1) Phosphoria TPS, (2) Cretaceous-Tertiary TPS, and (3) Waltman TPS. Within these systems, 12 Assessment Units (AU) were defined and undiscovered oil and gas resources were quantitatively estimated within 10 of the 12 AUs.

Pimienta-Tamabra(!) - A giant supercharged petroleum system in the southern Gulf of Mexico, onshore and offshore Mexico

USGS Publications Warehouse

Magoon, L.B.; Hudson, T.L.; Cook, H.E.

2001-01-01

Pimienta-Tamabra(!) is a giant supercharged petroleum system in the southern Gulf of Mexico with cumulative production and total reserves of 66.3 billion barrels of oil and 103.7 tcf of natural gas, or 83.6 billion barrels of oil equivalent (BOE). The effectiveness of this system results largely from the widespread distribution of good to excellent thermally mature, Upper Jurassic source rock underlying numerous stratigraphic and structural traps that contain excellent carbonate reservoirs. Expulsion of oil and gas as a supercritical fluid from Upper Jurassic source rock occurred when the thickness of overburden rock exceeded 5 km. This burial event started in the Eocene, culminated in the Miocene, and continues to a lesser extent today. The expelled hydrocarbons started migrating laterally and then upward as a gas-saturated 35-40??API oil with less than 1 wt.% sulfur and a gas-to-oil ratio (GOR) of 500-1000 ft3/BO. The generation-accumulation efficiency is about 6%.

Total Petroleum Systems and Geologic Assessment of Oil and Gas Resources in the Powder River Basin Province, Wyoming and Montana

USGS Publications Warehouse

Anna, L.O.

2009-01-01

The U.S. Geological Survey completed an assessment of the undiscovered oil and gas potential of the Powder River Basin in 2006. The assessment of undiscovered oil and gas used the total petroleum system concept, which includes mapping the distribution of potential source rocks and known petroleum accumulations and determining the timing of petroleum generation and migration. Geologically based, it focuses on source and reservoir rock stratigraphy, timing of tectonic events and the configuration of resulting structures, formation of traps and seals, and burial history modeling. The total petroleum system is subdivided into assessment units based on similar geologic characteristics and accumulation and petroleum type. In chapter 1 of this report, five total petroleum systems, eight conventional assessment units, and three continuous assessment units were defined and the undiscovered oil and gas resources within each assessment unit quantitatively estimated. Chapter 2 describes data used in support of the process being applied by the U.S. Geological Survey (USGS) National Oil and Gas Assessment (NOGA) project. Digital tabular data used in this report and archival data that permit the user to perform further analyses are available elsewhere on this CD-ROM. Computers and software may import the data without transcription from the Portable Document Format files (.pdf files) of the text by the reader. Because of the number and variety of platforms and software available, graphical images are provided as .pdf files and tabular data are provided in a raw form as tab-delimited text files (.tab files).

Chapter 32: Geology and petroleum potential of the Arctic Alaska petroleum province

USGS Publications Warehouse

Bird, K.J.; Houseknecht, D.W.

2011-01-01

The Arctic Alaska petroleum province encompasses all lands and adjacent continental shelf areas north of the Brooks Range-Herald Arch orogenic belt and south of the northern (outboard) margin of the Beaufort Rift shoulder. Even though only a small part is thoroughly explored, it is one of the most prolific petroleum provinces in North America with total known resources (cumulative production plus proved reserves) of c. 28 BBOE. The province constitutes a significant part of a displaced continental fragment, the Arctic Alaska microplate, that was probably rifted from the Canadian Arctic margin during formation of the Canada Basin. Petroleum prospective rocks in the province, mostly Mississippian and younger, record a sequential geological evolution through passive margin, rift and foreland basin tectonic stages. Significant petroleum source and reservoir rocks were formed during each tectonic stage but it was the foreland basin stage that provided the necessary burial heating to generate petroleum from the source rocks. The lion's share of known petroleum resources in the province occur in combination structural-stratigraphic traps formed as a consequence of rifting and located along the rift shoulder. Since the discovery of the super-giant Prudhoe Bay accumulation in one of these traps in the late 1960s, exploration activity preferentially focused on these types of traps. More recent activity, however, has emphasized the potential for stratigraphic traps and the prospect of a natural gas pipeline in this region has spurred renewed interest in structural traps. For assessment purposes, the province is divided into a Platform assessment unit (AU), comprising the Beaufort Rift shoulder and its relatively undeformed flanks, and a Fold-and-Thrust Belt AU, comprising the deformed area north of the Brooks Range and Herald Arch tectonic belt. Mean estimates of undiscovered, technically recoverable resources include nearly 28 billion barrels of oil (BBO) and 122 trillion cubic feet (TCF) of nonassociated gas in the Platform AU and 2 BBO and 59 TCF of nonassociated gas in the Fold-and-Thrust Belt AU. ?? 2011 The Geological Society of London.

Carboniferous-Rotliegend total petroleum system; description and assessment results summary

USGS Publications Warehouse

Gautier, Donald L.

2003-01-01

The Anglo-Dutch Basin and the Northwest German Basin are two of the 76 priority basins assessed by the U.S. Geological Survey World Energy Project. The basins were assessed together because most of the resources occur within a single petroleum system (the Carboniferous-Rotliegend Total Petroleum System) that transcends the combined Anglo-Dutch Basin and Northwest German Basin boundary. The juxtaposition of thermally mature coals and carbonaceous shales of the Carboniferous Coal Measures (source rock), sandstones of the Rotliegend sedimentary systems (reservoir rock), and the Zechstein evaporites (seal) define the total petroleum system (TPS). Three assessment units were defined, based upon technological and geographic (rather than geological) criteria, that subdivide the Carboniferous-Rotliegend Total Petroleum System. These assessment units are (1) the Southern Permian Basin-Offshore Europe Assessment Unit, (2) the Southern Permian Basin Onshore Europe Assessment Unit, and (3) the Southern Permian Basin Onshore United Kingdom Assessment Unit. Although the Carboniferous-Rotliegend Total Petroleum System is one of the most intensely explored volumes of rock in the world, potential remains for undiscovered resources. Undiscovered conventional resources associated with the TPS range from 22 to 184 million barrels of oil, and from 3.6 to 14.9 trillion cubic feet of natural gas. Of these amounts, approximately 62 million barrels of oil and 13 trillion cubic feet of gas are expected in offshore areas, and 26 million barrels of oil and 1.9 trillion cubic feet of gas are predicted in onshore areas.

Analysis and occurrence of C sub 26 -steranes in petroleum and source rocks

DOE Office of Scientific and Technical Information (OSTI.GOV)

Moldowan, J.M.; Lee, C.Y.; Gallegos, E.J.

1991-04-01

The C{sub 26}-steranes previously reported in oils and source rocks have been identified as 21-, 24-, and 27-norcholestanes (1A, 1B, and 1C). Various 24-norcholesterols or stanols, possible prescursors for the 24-norcholestanes, occur widely at low levels in marine invertebrates and some algae, and 24-norcholestanes occur in marine petroleums of Tertiary through Paleozoic age. There are reports of 27-norcholesterols and stanols in recent sediments, but the precursor organisms have not been identified. The natural occurrence of the 21-norcholestane structure is unprecedented. Unlike 24- and 27-norcholestane, 21-norcholestane is in low concentration or absent in immature rocks and increases substantially relative to themore » other C{sub 26}-steranes in thermally mature rocks, oils, and condensates. This suggests an origin involving thermal degradation of a higher molecuar weight steroid. The ratio of 21-norcholestane to the total C{sub 26}-steranes is shown to be an effective maturity parameter in a series of Wyoming (Phosphoria source) and California (Monterey source) oils. Molecular mechanics MM2 steric energy calculations indicate a relative stability order of 21 {much gt} 27 > 24-norcholestane for the major stereoisomers. Authentic 21-, 24-, and 27-nor-5{alpha}-cholestanes and 24- and 27-nor-5{beta}-cholestanes were synthesized and subjected to catalytic isomerization over Pd/C to yield the full suite of stereoisomers for each.« less

Tectonics of Chukchi Sea Shelf sedimentary basins and its influence on petroleum systems

NASA Astrophysics Data System (ADS)

Agasheva, Mariia; Antonina, Stoupakova; Anna, Suslova; Yury, Karpov

2016-04-01

The Chukchi Sea Shelf placed in the East Arctic offshore of Russia between East Siberian Sea Shelf and North Slope Alaska. The Chukchi margin is considered as high petroleum potential play. The major problem is absence of core material from drilling wells in Russian part of Chukchi Shelf, hence strong complex geological and geophysical analyses such as seismic stratigraphy interpretation should be provided. In addition, similarity to North Slope and Beaufort Basins (North Chukchi) and Hope Basin (South Chukchi) allow to infer the resembling sedimentary succession and petroleum systems. The Chukchi Sea Shelf include North and South Chukchi Basins, which are separated by Wrangel-Herald Arch and characterized by different opening time. The North Chukchi basin is formed as a general part of Canada Basin opened in Early Cretaceous. The South Chukchi Basin is characterized by a transtensional origin of the basin, this deformation related to motion on the Kobuk Fault [1]. Because seismic reflections follow chronostratigraphic correlations, it is possible to achieve stratigraphic interpretation. The main seismic horizons were indicated as: PU, JU, LCU, BU, mBU marking each regional unconformities. Reconstruction of main tectonic events of basin is important for building correct geological model. Since there are no drilling wells in the North and South Chukchi basins, source rocks could not be proven. Referring to the North Chukchi basin, source rocks equivalents of Lower Cretaceous Pebble Shale Formation, Lower Jurassic Kingdak shales and Upper Triassic Shublik Formation (North Slope) is possible exhibited [2]. In the South Chukchi, it is possible that Cretaceous source rocks could be mature for hydrocarbon generation. Erosions and uplifts that could effect on hydrocarbon preservation was substantially in Lower Jurassic and Early Cretaceous periods. Most of the structures may be connected with fault and stratigraphy traps. The structure formed at Wrangel-Herald Arch to North-Chukchi through similar to well-known structure in Norwegian part of Barents Sea - Loppa High. In South Chukchi basin, the seismic wave shows interesting structures akin to diaper fold. Inversion-related anticlines and stratigraphic pinch-outs traps could presence in Cretaceous-Cenozoic cross section. As a result, we gathered and analyzed source rocks and reservoir analogs and gained improved sedimentary models in Eastern Russian Shelfs (Laptev, East Siberian and Chukchi Seas). Appropriate tectonic conditions, proven by well testing source rocks in North Slope and high thickness of basins suggest a success of hydrocarbon exploration in Russian part of Chukchi Sea Shelf. [1] Verzhbitsky V. E., S. D. Sokolov, E. M. Frantzen, A. Little, M. I. Tuchkova, and L.I. Lobkovsky, 2012, The South Chukchi Sedimentary Basin (Chukchi Sea, Russian Arctic): Age, structural pattern,and hydrocarbon potential, in D. Gao, ed., Tectonics and sedimentation: Implications for petroleum systems: AAPG Memoir 100, p.267-290. [2] Peters K. E., Magoon L. B., Bird K. J., Valin Z. C., Keller M. A. North Slope, Alaska: Source rock distribution, richness, thermal maturity, and petroleum charge AAPG Bulletin, V. 90, No. 2 (February 2006), 2006, P. 261-292.

Geologic Cross Section I–I′ Through the Appalachian Basin from the Eastern Margin of the Illinois Basin, Jefferson County, Kentucky, to the Valley and Ridge Province, Scott County, Virginia

USGS Publications Warehouse

Ryder, Robert T.; Trippi, Michael H.; Swezey, Christopher S.

2015-12-08

Cross section I‒I ’ contains much information that is useful for evaluating energy resources in the Appalachian basin. Many of the key elements of the Appalachian basin petroleum systems (such as source rocks, reservoir rocks, seals, and traps) can be inferred from lithologic units, unconformities, and geologic structures shown on the cross section. Other aspects of petroleum systems (such as the timing of petroleum generation and petroleum migration pathways) may be evaluated by burial history, thermal history, and fluid flow models on the basis of what is shown on the cross section. Cross section I‒I’ also provides a stratigraphic and structural framework for the Pennsylvanian coal-bearing section. In addition, geologists and engineers could use cross section I‒I’ as a reconnaissance tool to identify plausible geologic structures and strata for the subsurface storage of liquid waste or for the sequestration of carbon dioxide.

The Kingak shale of northern Alaska-regional variations in organic geochemical properties and petroleum source rock quality

USGS Publications Warehouse

Magoon, L.B.; Claypool, G.E.

1984-01-01

The Kingak Shale, a thick widespread rock unit in northern Alaska that ranges in age from Early Jurassic through Early Cretaceous, has adequate to good oil source rock potential. This lenticular-shaped rock unit is as much as 1200 m thick near the Jurassic shelf edge, where its present-day burial depth is about 5000 m. Kingak sediment, transported in a southerly direction, was deposited on the then marine continental shelf. The rock unit is predominantly dark gray Shale with some interbeds of thick sandstone and siltstone. The thermal maturity of organic matter in the Kingak Shale ranges from immature (2.0%R0) in the Colville basin toward the south. Its organic carbon and hydrogen contents are highest in the eastern part of northern Alaska south of and around the Kuparuk and Prudhoe Bay oil fields. Carbon isotope data of oils and rock extracts indicate that the Kingak Shale is a source of some North Slope oil, but is probably not the major source. ?? 1984.

Petroleum prospects for offshore sedimentary basins in the eastern Papua New Guinea and Solomon Islands regions

DOE Office of Scientific and Technical Information (OSTI.GOV)

Bruns, T.R.; Vedder, J.G.

Intra-arc basins in the Buka-Bougainville region of Papua New Guinea and in the Solomon Islands contain thick sedimentary sequences that may be prospective for petroleum. The Queen Emma basin, between Bougainville and New Ireland, contains as much as 8 km of deformed Oligocene and younger strata. The Central Solomons Trough, which underlies New Georgia Sound, is a composite intra-arc basin that contains late Oligocene and younger strata as much as 7 km thick. Farther east, beneath Indispensable Strait, the down-faulted Indispensable basin locally contains as much as 5.4 km of Miocene( ) and younger strata, and the offshore part ofmore » Mbokokimbo basin off eastern Guadalcanal includes 6 km or more of late Miocene and younger strata. All of these basins have some of the attributes necessary to generate and trap petroleum. Structural and stratigraphic traps are common, including faulted anticlines, sedimentary wedges, and carbonate reefs and reef-derived deposits on submarine ridges and along the basin margins. The thickness of the basin deposits ensures that some strata are buried deeply enough to be within the thermal regime required for hydrocarbon generation. However, little source or reservoir rock information is available because of the lack of detailed surface and subsurface stratigraphy. Moreover, much of the basin sediment is likely to consist of volcaniclastic material, derived from uplifted volcanogenic rocks surrounding the basins, and may be poor in source and reservoir rocks. Until additional stratigraphic information is available, analysis of the petroleum potential of these basins is a matter of conjecture.« less

The Santa Cruz - Tarija Province of Central South America: Los Monos - Machareti(!) Petroleum System

USGS Publications Warehouse

Lindquist, Sandra J.

1999-01-01

The Los Monos - Machareti(!) total petroleum system is in the Santa Cruz - Tarija Province of Bolivia, Argentina and Paraguay. Province history is that of a Paleozoic, intracratonic, siliciclastic rift basin that evolved into a Miocene (Andean) foreland fold and thrust belt. Existing fields are typified by alternating reservoir and seal rocks in post-Ordovician sandstones and shales on anticlines. Thick Devonian and Silurian shale source rocks, depositionally and erosionally confined to this province, at a minimum have generated 4.1 BBOE known ultimate recoverable reserves (as of 1995, 77% gas, 15% condensate, 8% oil) into dominantly Carboniferous reservoirs with average 20% porosity and 156 md permeability. Major detachment surfaces within the source rocks contributed to the thin-skinned and laterally continuous nature of the deformation. Tertiary foreland burial adequate for significant source maturation coincided with the formation of compressional traps. Further hydrocarbon discovery in the fold and thrust belt is expected. In the foreland basin, higher thermal gradients and variable burial history - combined with the presence of unconformity and onlap wedges - create potential there for stratigraphic traps and pre-Andean, block-fault and forced-fold traps.

Predicted bulk composition of petroleum generated by Lower Cretaceous Wealden black shales, Lower Saxony Basin, Germany

NASA Astrophysics Data System (ADS)

Ziegs, Volker; Mahlstedt, Nicolaj; Bruns, Benjamin; Horsfield, Brian

2015-09-01

The Berriasian Wealden Shale provides the favourable situation of possessing immature to overmature source rock intervals due to differential subsidence within the Lower Saxony Basin. Hydrocarbon generation kinetics and petroleum physical properties have been investigated on four immature Wealden Shale samples situated in different depth intervals and following the PhaseKinetics approach of di Primio and Horsfield (AAPG Bull 90(7):1031-1058, 2006). Kinetic parameters and phase prediction were applied to a thermally calibrated 1D model of the geodynamic evolution at the location of an overmature well. The immature source rocks of all depth intervals comprise kerogen type I being derived from the lacustrine algae Botryococcus braunii. Bulk kinetics of the lower three depth intervals (sample 2-4) can be described by one single activation energy E a, typical for homogeneous, lacustrine organic matter (OM), whereas sample 1 from the uppermost interval shows a slightly broader E a distribution which hints to a more heterogeneous, less stable OM, but still of lacustrine origin. Predicted physical properties of the generated petroleum fluids are characteristic of variably waxy, black oil possessing GOR's below 100 Sm3/Sm3 and saturations pressures below 150 bar. Petroleum fluids from the more heterogeneous OM-containing sample 1 can always be described by slightly higher values. Based on the occurrence of paraffinic, free hydrocarbons in the uppermost horizon of the overmature well and gas/condensate in the lower 3 depth intervals, two scenarios have been discussed. From the first and least realistic scenario assuming no expulsion from the source rock, it can be deduced that phase separation in the course of uplift can only have occurred in the uppermost interval containing the slightly less stable OM but not in the lower intervals being composed of a more stable OM. Therefore and taking secondary cracking into account, all depth intervals should contain gas/condensate. The free hydrocarbons in the upper horizon are interpreted as impregnation from migrated hydrocarbons. The second scenario assumes nearly complete expulsion due to fracturing by the so-called generation overpressure (Mann et al. in Petroleum and basin evolution. Springer, Berlin, 1997). The expelled petroleum might migrate into lower pressurised source rock horizons and reach bubble-point pressures leading to the exsolution of gas and "precipitation" of very high molecular weight bitumen unable to migrate. Subsequent burial of the latter in the course of the basin evolution would lead to secondary cracking and remaining pyrobitumen explaining the high amounts of pyrobitumen in the overmature well Ex-B and relatively enhanced TOC contents at such high maturity levels.

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

USGS Publications Warehouse

Ahlbrandt, T.S.; Pollastro, R.M.; Schenk, C.J.

2002-01-01

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

Burial, thermal, and petroleum generation history of the Upper Cretaceous Steele Member of the Cody Shale (Shannon Sandstone Bed Horizon), Powder River Basin, Wyoming (Chapter A). Bulletin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Nuccio, V.F.

The purposes of the study are to (1) present burial histories representative of the northwestern and southwestern parts of the Powder River Basin (south of lat 45 N.), (2) show the maximum level of thermal maturity for the Steele Member and its Shannon Sandstone Bed, and (3) show the source-rock potential and timing of petroleum generation for the Steele. It is hoped that data presented in the study will also lead to a better understanding of the burial and temperature history of the Shannon Sandstone Bed, an understanding crucial for diagenetic studies, fluid-flow modeling, and reservoir-rock characterization.

1-D/3-D geologic model of the Western Canada Sedimentary Basin

USGS Publications Warehouse

Higley, D.K.; Henry, M.; Roberts, L.N.R.; Steinshouer, D.W.

2005-01-01

The 3-D geologic model of the Western Canada Sedimentary Basin comprises 18 stacked intervals from the base of the Devonian Woodbend Group and age equivalent formations to ground surface; it includes an estimated thickness of eroded sediments based on 1-D burial history reconstructions for 33 wells across the study area. Each interval for the construction of the 3-D model was chosen on the basis of whether it is primarily composed of petroleum system elements of reservoir, hydrocarbon source, seal, overburden, or underburden strata, as well as the quality and areal distribution of well and other data. Preliminary results of the modeling support the following interpretations. Long-distance migration of hydrocarbons east of the Rocky Mountains is indicated by oil and gas accumulations in areas within which source rocks are thermally immature for oil and (or) gas. Petroleum systems in the basin are segmented by the northeast-trending Sweetgrass Arch; hydrocarbons west of the arch were from source rocks lying near or beneath the Rocky Mountains, whereas oil and gas east of the arch were sourced from the Williston Basin. Hydrocarbon generation and migration are primarily due to increased burial associated with the Laramide Orogeny. Hydrocarbon sources and migration were also influenced by the Lower Cretaceous sub-Mannville unconformity. In the Peace River Arch area of northern Alberta, Jurassic and older formations exhibit high-angle truncations against the unconformity. Potential Paleozoic though Mesozoic hydrocarbon source rocks are in contact with overlying Mannville Group reservoir facies. In contrast, in Saskatchewan and southern Alberta the contacts are parallel to sub-parallel, with the result that hydrocarbon source rocks are separated from the Mannville Group by seal-forming strata within the Jurassic. Vertical and lateral movement of hydrocarbons along the faults in the Rocky Mountains deformed belt probably also resulted in mixing of oil and gas from numerous source rocks in Alberta.

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

USGS Publications Warehouse

Brownfield, Michael E.; Charpentier, Ronald R.

2003-01-01

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.

Chapter 1: Executive Summary - 2003 Assessment of Undiscovered Oil and Gas Resources in the Upper Cretaceous Navarro and Taylor Groups, Western Gulf Province, Gulf Coast Region, Texas

USGS Publications Warehouse

,

2006-01-01

The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered oil and gas potential of the Upper Cretaceous Navarro and Taylor Groups in the Western Gulf Province of the Gulf Coast region (fig. 1) as part of a national oil and gas assessment effort (USGS Navarro and Taylor Groups Assessment Team, 2004). The assessment of the petroleum potential of the Navarro and Taylor Groups was based on the general geologic elements used to define a total petroleum system (TPS), including hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined five assessment units (AU) in the Navarro and Taylor Groups as parts of a single TPS, the Smackover-Austin-Eagle Ford Composite TPS: Travis Volcanic Mounds Oil AU, Uvalde Volcanic Mounds Gas and Oil AU, Navarro-Taylor Updip Oil and Gas AU, Navarro-Taylor Downdip Gas and Oil AU, and Navarro-Taylor Slope-Basin Gas AU (table 1).

Overview of Petroleum Settings in Deep Waters of the Brazilian South Atlantic Margin

NASA Astrophysics Data System (ADS)

Anjos, Sylvia; Penteado, Henrique; Oliveira, Carlos M. M.

2015-04-01

The objective of this work is to present an overall view of the tectonic and stratigraphic evolution of the western South Atlantic with focus on the Brazilian marginal basins. It includes the structural evolution, stratigraphic sequences, depositional environments and petroleum systems model along the Brazilian marginal basins. In addition, a description of the main petroleum provinces and selected plays including the pre-salt carbonates and post-salt turbidite reservoirs is presented. Source-rock ages and types, trap styles, main reservoir characteristics, petroleum compositions, and recent exploration results are discussed. Finally, an outlook and general assessment of the impact of the large pre-salt discoveries on the present-day and future production curves are given.

3D thermal history and maturity modelling of the Levant Basin and Margin

NASA Astrophysics Data System (ADS)

Daher, Samer Bou; Ducros, Mathieu; Michel, Pauline; Nader, Fadi H.; Littke, Ralf

2015-04-01

The gas discoveries recorded in the Levant Basin in the last decade have redirected the industrial and academic communities' interest to this frontier basin and its surroundings. The reported gas in Miocene reservoirs has been assumed to be derived from biogenic sources, although little data has been published so far. The thickness of the sedimentary column and the presence of direct hydrocarbon indicators (DHI) observed in the seismic data suggest the presence of promising prospective thermogenic petroleum systems in deeper intervals in the Levant Basin and along its Margin. In this study we present a large scale 3D thermal history and maturity model of the Levant Basin and Margin, integrating all available calibration data, source rock information collected from onshore Lebanon, and published data. In the first part we will present the main input and assumptions that were made in terms of thicknesses, lithologies, and boundary conditions. In the second part we will discuss the analysed source rocks, their petroleum generation potential and their kinetics. In the third part we will present modelling results including depth maps for key isotherms in addition to transformation ratio and vitrinite reflectance maps for proven and speculative source rocks at different time steps. This will provide a comprehensive assessment of the potential thermogenic petroleum systems in the study area, and allow us to illustrate and discuss the differences between the basinal, marginal, and onshore part of the study area as well as the potential of the northern vis a vis the southern offshore Levant Basin. This model will also allow us to analyse the sensitivity of the system to the various poorly constrained parameters in frontier basins (e.g. crustal thickness, rifting phases, lithologies) and thus identify the most critical data to be collected for future exploration and de-risking strategies.

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

USGS Publications Warehouse

McLean, Hugh James

1979-01-01

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

Petroleum system of the Shelf Rift Basin, East China Sea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cunningham, A.C.; Armentrout, J.M.; Prebish, M.

1996-12-31

The Tertiary section of the Oujioang and Quiontang Depressions of the East China Sea Basin consists of at least eight rift-related depositional sequences identified seismically by regionally significant onlap and truncation surfaces. These sequences are calibrated by several wells including the Wenzhou 6-1-1 permitting extrapolation of petroleum system elements using seismic facies analysis. Gas and condensate correlated to non-marine source rocks and reservoired in sandstone at the Pinghu field to the north of the study area provides an known petroleum system analogue. In the Shelf Rift Basin, synrift high-amplitude parallel reflections within the graben axes correlate with coaly siltstone stratamore » and are interpreted as coastal plain and possibly lacustrine facies with source rock potential. Synrift clinoform seismic facies prograding from the northwest footwall correlate with non-marine to marginal marine conglomerate, sandstone and siltstone, and are interpreted as possible delta or fan-delta facies with reservoir potential although porosity and permeability is low within the Wenzhou 6-1-1 well. Post-rift thermal sag sequences are characterized by parallel and relatively continuous seismic reflections and locally developed clinoform packages. These facies correlate with porous and permeable marine sandstone and siltstone. Shales of potential sealing capacity occur within marine flooding intervals of both the synrift and post-rift sequences. Traps consist of differentially rotated synrift fill, and post-rift inversion anticlines. Major exploration risk factors include migration from the synrift coaly source rocks to the post-rift porous and permeable sandstones, and seismic imaging and drilling problems associated with extensive Tertiary igneous intrusions.« less

Petroleum system of the Shelf Rift Basin, East China Sea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cunningham, A.C.; Armentrout, J.M.; Prebish, M.

1996-01-01

The Tertiary section of the Oujioang and Quiontang Depressions of the East China Sea Basin consists of at least eight rift-related depositional sequences identified seismically by regionally significant onlap and truncation surfaces. These sequences are calibrated by several wells including the Wenzhou 6-1-1 permitting extrapolation of petroleum system elements using seismic facies analysis. Gas and condensate correlated to non-marine source rocks and reservoired in sandstone at the Pinghu field to the north of the study area provides an known petroleum system analogue. In the Shelf Rift Basin, synrift high-amplitude parallel reflections within the graben axes correlate with coaly siltstone stratamore » and are interpreted as coastal plain and possibly lacustrine facies with source rock potential. Synrift clinoform seismic facies prograding from the northwest footwall correlate with non-marine to marginal marine conglomerate, sandstone and siltstone, and are interpreted as possible delta or fan-delta facies with reservoir potential although porosity and permeability is low within the Wenzhou 6-1-1 well. Post-rift thermal sag sequences are characterized by parallel and relatively continuous seismic reflections and locally developed clinoform packages. These facies correlate with porous and permeable marine sandstone and siltstone. Shales of potential sealing capacity occur within marine flooding intervals of both the synrift and post-rift sequences. Traps consist of differentially rotated synrift fill, and post-rift inversion anticlines. Major exploration risk factors include migration from the synrift coaly source rocks to the post-rift porous and permeable sandstones, and seismic imaging and drilling problems associated with extensive Tertiary igneous intrusions.« less

Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Bakken Formation, Williston Basin, Montana and North Dakota, 2008

USGS Publications Warehouse

Pollastro, R.M.; Roberts, L.N.R.; Cook, T.A.; Lewan, M.D.

2008-01-01

The U.S. Geological Survey (USGS) has completed an assessment of the undiscovered oil and associated gas resources of the Upper Devonian to Lower Mississippian Bakken Formation in the U.S. portion of the Williston Basin of Montana and North Dakota and within the Williston Basin Province. The assessment is based on geologic elements of a total petroleum system (TPS), which include (1) source-rock distribution, thickness, organic richness, maturation, petroleum generation, and migration; (2) reservoir-rock type (conventional or continuous), distribution, and quality; and (3) character of traps and time of formation with respect to petroleum generation and migration. Framework studies in stratigraphy and structural geology and modeling of petroleum geochemistry, combined with historical exploration and production analyses, were used to estimate the undiscovered, technically recoverable oil resource of the Bakken Formation. Using this framework, the USGS defined a Bakken-Lodgepole TPS and seven assessment units (AU) within the system. For the Bakken Formation, the undiscovered oil and associated gas resources were quantitatively estimated for six of these AUs.

The Talara Basin province of northwestern Peru: cretaceous-tertiary total petroleum system

USGS Publications Warehouse

Higley, Debra K.

2004-01-01

More than 1.68 billion barrels of oil (BBO) and 340 billion cubic feet of gas (BCFG) have been produced from the Cretaceous-Tertiary Total Petroleum System in the Talara Basin province, northwestern Peru. Oil and minor gas fields are concentrated in the onshore northern third of the province. Current production is primarily oil, but there is excellent potential for offshore gas resources, which is a mostly untapped resource because of the limited local market for gas and because there are few pipelines. Estimated mean recoverable resources from undiscovered fields in the basin are 1.71 billion barrels of oil (BBO), 4.79 trillion cubic feet of gas (TCFG), and 255 million barrels of natural gas liquids (NGL). Of this total resource, 15 percent has been allocated to onshore and 85 percent to offshore; volumes are 0.26 BBO and 0.72 TCFG onshore, and 1.45 BBO and 4.08 TCFG offshore. The mean estimate of numbers of undiscovered oil and gas fields is 83 and 27, respectively. Minimum size of fields that were used in this analysis is 1 million barrels of oil equivalent and (or) 6 BCFG. The Paleocene Talara forearc basin is superimposed on a larger, Mesozoic and pre-Mesozoic basin. Producing formations, ranging in age from Pennsylvanian to Oligocene, are mainly Upper Cretaceous through Oligocene sandstones of fluvial, deltaic, and nearshore to deep-marine depositional origins. The primary reservoirs and greatest potential for future development are Eocene sandstones that include turbidites of the Talara and Salinas Groups. Additional production and undiscovered resources exist within Upper Cretaceous, Paleocene, and Oligocene formations. Pennsylvanian Amotape quartzites may be productive where fractured. Trap types in this block-faulted basin are mainly structural or a combination of structure and stratigraphy. Primary reservoir seals are interbedded and overlying marine shales. Most fields produce from multiple reservoirs, and production is reported commingled. For this reason, and also because geochemical data on oils and source rocks is very limited, Tertiary and Cretaceous production is grouped into one total petroleum system. The most likely source rocks are Tertiary marine shales, but some of the Cretaceous marine shales are also probable source rocks, and these would represent separate total petroleum systems. Geochemical data on one oil sample from Pennsylvanian rock indicates that it was probably also sourced from Tertiary shales.

Distribution of organic carbon and petroleum source rock potential of Cretaceous and lower Tertiary carbonates, South Florida Basin: preliminary results

USGS Publications Warehouse

Palacas, James George

1978-01-01

Analyses of 134 core samples from the South Florida Basin show that the carbonates of Comanchean age are relatively richer in average organic carbon (0.41 percent) than those of Coahuilan age (0.28 percent), Gulfian age (0.18 percent) and Paleocene age (0.20 percent). They are also nearly twice as rich as the average world, wide carbonate (average 0.24 percent). The majority of carbonates have organic carbons less than 0.30 percent but the presence of many relatively organic rich beds composed of highly bituminous, argillaceous, highly stylolitic, and algal-bearing limestones and dolomites accounts for the higher percentage of organic carbon in some of the stratigraphic units. Carbonate rocks that contain greater than 0.4 percent organic carbon and that might be considered as possible petroleum sources were noted in almost each subdivision of the Coahuilan and Comanchean Series but particularly the units of Fredericksburg 'B', Trinity 'A', Trinity 'F', and Upper Sunniland. Possible source rocks have been ascribed by others to the Lower Sunniland, but lack of sufficient samples precluded any firm assessment in this initial report. In the shallower section of the basin, organic-rich carbonates containing as much as 3.2 percent organic carbon were observed in the lowermost part of the Gulfian Series and carbonate rocks with oil staining or 'dead' and 'live oil' were noted by others in the uppermost Gulfian and upper Cedar Keys Formation. It is questionable whether these shallower rocks are of sufficient thermal maturity to have generated commercial oil. The South Florida basin is still sparsely drilled and produces only from the Sunniland Limestone at an average depth of 11,500 feet (3500 m). Because the Sunniland contains good reservoir rocks and apparently adequate source rocks, and because the success rate of new oil field discoveries has increased in recent years, the chances of finding additional oil reserves in the Sunniland are promising. Furthermore, the presence of possible source rocks in many of the other stratigraphic units, in particular, the Fredericksburg, should give further impetus to exploring for other productive horizons.

Application of uniaxial confining-core clamp with hydrous pyrolysis in petrophysical and geochemical studies of source rocks at various thermal maturities

USGS Publications Warehouse

Lewan, Michael D.; Birdwell, Justin E.; Baez, Luis; Beeney, Ken; Sonnenberg, Steve

2013-01-01

Understanding changes in petrophysical and geochemical parameters during source rock thermal maturation is a critical component in evaluating source-rock petroleum accumulations. Natural core data are preferred, but obtaining cores that represent the same facies of a source rock at different thermal maturities is seldom possible. An alternative approach is to induce thermal maturity changes by laboratory pyrolysis on aliquots of a source-rock sample of a given facies of interest. Hydrous pyrolysis is an effective way to induce thermal maturity on source-rock cores and provide expelled oils that are similar in composition to natural crude oils. However, net-volume increases during bitumen and oil generation result in expanded cores due to opening of bedding-plane partings. Although meaningful geochemical measurements on expanded, recovered cores are possible, the utility of the core for measuring petrophysical properties relevant to natural subsurface cores is not suitable. This problem created during hydrous pyrolysis is alleviated by using a stainless steel uniaxial confinement clamp on rock cores cut perpendicular to bedding fabric. The clamp prevents expansion just as overburden does during natural petroleum formation in the subsurface. As a result, intact cores can be recovered at various thermal maturities for the measurement of petrophysical properties as well as for geochemical analyses. This approach has been applied to 1.7-inch diameter cores taken perpendicular to the bedding fabric of a 2.3- to 2.4-inch thick slab of Mahogany oil shale from the Eocene Green River Formation. Cores were subjected to hydrous pyrolysis at 360 °C for 72 h, which represents near maximum oil generation. One core was heated unconfined and the other was heated in the uniaxial confinement clamp. The unconfined core developed open tensile fractures parallel to the bedding fabric that result in a 38 % vertical expansion of the core. These open fractures did not occur in the confined core, but short, discontinuous vertical fractures on the core periphery occurred as a result of lateral expansion.

Ghaba salt basin province and Fahud salt basin province, Oman; geological overview and total petroleum systems

USGS Publications Warehouse

Pollastro, R.M.

1999-01-01

Three Total Petroleum Systems each consisting of one assessment unit have been identified in the Ghaba and Fahud Salt Basin Provinces of north-central Oman. One Total Petroleum System and corresponding assessment unit, the North Oman Huqf/`Q'? Haushi(!) Total Petroleum System (201401) and Ghaba-Makarem Combined Structural Assessment Unit (20140101), were identified for the Ghaba Salt Basin Province (2014). In the Fahud Salt Basin Province, however, two overlapping Total Petroleum Systems (TPS) were recognized: 1) the North Oman Huqf ? Shu'aiba(!) TPS (201601); Fahud-Huqf Combined Structural Assessment Unit (20160101), and 2) the Middle Cretaceous Natih(!) TPS (201602); Natih-Fiqa Structural/Stratigraphic Assessment Unit (20160201). The boundary for each Total Petroleum System also defines the boundary of the corresponding assessment unit and includes all trap styles and hydrocarbon producing reservoirs within the petroleum system. In both the Ghaba and Fahud Salt Basin Provinces, hydrocarbons were generated from several deeply-buried source rocks within the Infracambrian Huqf Supergroup. One general `North Oman Huqf' type oil is dominant in the Fahud Salt Basin. Oils in the Ghaba Salt Basin are linked to at least two distinct Huqf source-rock units based on oil geochemistry: a general North Oman Huqf-type oil source and a more dominant `questionable unidentified-source' or `Q'-type Huqf oil source. These two Huqf-sourced oils are commonly found as admixtures in reservoirs throughout north-central Oman. Hydrocarbons generated from Huqf sources are produced from a variety of reservoir types and ages ranging from Precambrian to Cretaceous in both the Ghaba and Fahud Salt Basin Provinces. Clastic reservoirs of the Gharif and Al Khlata Formations, Haushi Group (M. Carboniferous to L. Permian), dominate oil production in the Ghaba Salt Basin Province and form the basis for the Huqf/`Q' ? Haushi(!) TPS. In contrast, the Lower Cretaceous Shu'aiba and Middle Cretaceous Natih limestones account for most of the production in the Fahud Salt Basin with about 50 percent of the basin's production from porous, fractured Shu'aiba limestones in Yibal field, thus the name North Oman Huqf ? Shu'aiba(!) TPS. Deep gas is produced mainly from Middle Cambrian to Lower Ordovician clastic reservoirs of the Haima Supergroup. Traps in nearly all hydrocarbon accumulations of these petroleum systems are mainly structural and were formed by one or more mechanisms. These trap-forming mechanisms were mainly periodic halokinesis of the thick Cambrian Ara Salt and consequent folding and faulting from basin loading, rifting, or other major tectonic events, particularly those events forming the Oman Mountains and associated foreland-basin system during the Late Cretaceous and Late Tertiary. Many of the future new-field targets will likely be low-relief, subtle structures, as many of the large structures have been drilled. Oman's recent interest and commitments to liquid natural gas export make deep gas a primary objective in the two North Oman Huqf petroleum systems. New-field exploration of deep gas and exploring deeper targets for gas in existing fields will likely identify a significant gas resource in the next thirty years. Moreover, salt-diapir flank traps in these two North Oman Huqf petroleum systems and salt basin provinces have gone essentially untested and will likely be targeted in the near-future. The Middle Cretaceous Natih(!) TPS is a small efficient system of the Fahud Salt Basin. Natih source rocks are only mature in the Late Cretaceous/Tertiary foredeep and production is primarily from Natih reservoirs; minor production from the Shu'aiba limestone is documented along fault-dip structures. Most traps are structural and are related to development of the foreland basin and formation of the Oman Mountains. Future targets of the Natih TPS will be less obvious than those of Fahud and Natih fields and likely includ

Ghaba salt basin province and Fahud salt basin province, Oman; geological overview and total petroleum systems

USGS Publications Warehouse

Pollastro, Richard M.

1999-01-01

Three Total Petroleum Systems each consisting of one assessment unit have been identified in the Ghaba and Fahud Salt Basin Provinces of north-central Oman. One Total Petroleum System and corresponding assessment unit, the North Oman Huqf/?Q??Haushi(!) Total Petroleum System (201401) and Ghaba- Makarem Combined Structural Assessment Unit (20140101), were identified for the Ghaba Salt Basin Province (2014). In the Fahud Salt Basin Province, however, two overlapping Total Petroleum Systems (TPS) were recognized: (1) the North Oman Huqf?Shu?aiba(!) TPS (201601); Fahud-Huqf Combined Structural Assessment Unit (20160101), and (2) the middle Cretaceous Natih(!) TPS (201602); Natih-Fiqa Structural/Stratigraphic Assessment Unit (20160201). The boundary for each Total Petroleum System also defines the boundary of the corresponding assessment unit and includes all trap styles and hydrocarbon-producing reservoirs within the petroleum system. In both the Ghaba and Fahud Salt Basin Provinces, hydrocarbons were generated from several deeply buried source rocks within the Infracambrian Huqf Supergroup. One general ?North Oman Huqf? type oil is dominant in the Fahud Salt Basin. Oils in the Ghaba Salt Basin are linked to at least two distinct Huqf source-rock units based on oil geochemistry: a general North Oman Huqf-type oil source and a more dominant ?questionable unidentified source? or ?Q?-type Huqf oil source. These two Huqf-sourced oils are commonly found as admixtures in reservoirs throughout northcentral Oman. Hydrocarbons generated from Huqf sources are produced from a variety of reservoir types and ages ranging from Precambrian to Cretaceous in both the Ghaba and Fahud Salt Basin Provinces. Clastic reservoirs of the Gharif and Al Khlata Formations, Haushi Group (middle Carboniferous to Lower Permian), dominate oil production in the Ghaba Salt Basin Province and form the basis for the Huqf/?Q??Haushi(!) TPS. In contrast, the Lower Cretaceous Shu?aiba and middle Cretaceous Natih limestones account for most of the production in the Fahud Salt Basin with about 50 percent of the basin?s production from porous, fractured Shu?aiba limestones in Yibal field, thus the name North Oman Huqf? Shu?aiba(!) TPS. Deep gas is produced mainly from Middle Cambrian to Lower Ordovician clastic reservoirs of the Haima Supergroup. Traps in nearly all hydrocarbon accumulations of these petroleum systems are mainly structural and were formed by one or more 3 mechanisms. These trap-forming mechanisms were mainly periodic halokinesis of the thick Cambrian Ara Salt and consequent folding and faulting from basin loading, rifting, or other major tectonic events, particularly those events forming the Oman Mountains and associated foreland-basin system during the Late Cretaceous and late Tertiary. Many of the future new-field targets will likely be low-relief, subtle structures, as many of the large structures have been drilled. Oman?s recent interest and commitments to liquid natural gas export make deep gas a primary objective in the two North Oman Huqf petroleum systems. New-field exploration of deep gas and exploring deeper targets for gas in existing fields will likely identify a significant gas resource in the next 30 years. Moreover, salt-diapir flank traps in these two North Oman Huqf petroleum systems and salt basin provinces have gone essentially untested and will likely be targeted in the near future. The middle Cretaceous Natih(!) TPS is a small efficient system of the Fahud Salt Basin. Natih source rocks are only mature in the Late Cretaceous/Tertiary foredeep and production is primarily from Natih reservoirs; minor production from the Shu?aiba limestone is documented along fault-dip structures. Most traps are structural and are related to development of the foreland basin and formation of the Oman Mountains. Future targets of the Natih TPS will be less obvious

Petroleum systems of the San Joaquin Basin Province, California -- geochemical characteristics of oil types: Chapter 9 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Lillis, Paul G.; Magoon, Leslie B.

2007-01-01

New analyses of 120 oil samples combined with 139 previously published oil analyses were used to characterize and map the distribution of oil types in the San Joaquin Basin, California. The results show that there are at least four oil types designated MM, ET, EK, and CM. Most of the oil from the basin has low to moderate sulfur content (less than 1 weight percent sulfur), although a few unaltered MM oils have as much as 1.2 weight percent sulfur. Reevaluation of source rock data from the literature indicate that the EK oil type is derived from the Eocene Kreyenhagen Formation, and the MM oil type is derived, in part, from the Miocene to Pliocene Monterey Formation and its equivalent units. The ET oil type is tentatively correlated to the Eocene Tumey formation of Atwill (1935). Previous studies suggest that the CM oil type is derived from the Late Cretaceous to Paleocene Moreno Formation. Maps of the distribution of the oil types show that the MM oil type is restricted to the southern third of the San Joaquin Basin Province. The composition of MM oils along the southern and eastern margins of the basin reflects the increased contribution of terrigenous organic matter to the marine basin near the Miocene paleoshoreline. EK oils are widely distributed along the western half of the basin, and ET oils are present in the central and west-central areas of the basin. The CM oil type has only been found in the Coalinga area in southwestern Fresno County. The oil type maps provide the basis for petroleum system maps that incorporate source rock distribution and burial history, migration pathways, and geologic relationships between hydrocarbon source and reservoir rocks. These petroleum system maps were used for the 2003 U.S. Geological Survey resource assessment of the San Joaquin Basin Province.

Assessment of undiscovered oil and gas resources of the Devonian Marcellus Shale of the Appalachian Basin Province

USGS Publications Warehouse

Coleman, James L.; Milici, Robert C.; Cook, Troy A.; Charpentier, Ronald R.; Kirshbaum, Mark; Klett, Timothy R.; Pollastro, Richard M.; Schenk, Christopher J.

2011-01-01

Using a geology-based assessment methodology, the U.S. Geological Survey (USGS) estimated a mean undiscovered natural gas resource of 84,198 billion cubic feet and a mean undiscovered natural gas liquids resource of 3,379 million barrels in the Devonian Marcellus Shale within the Appalachian Basin Province. All this resource occurs in continuous accumulations. In 2011, the USGS completed an assessment of the undiscovered oil and gas potential of the Devonian Marcellus Shale within the Appalachian Basin Province of the eastern United States. The Appalachian Basin Province includes parts of Alabama, Georgia, Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia. The assessment of the Marcellus Shale is based on the geologic elements of this formation's total petroleum system (TPS) as recognized in the characteristics of the TPS as a petroleum source rock (source rock richness, thermal maturation, petroleum generation, and migration) as well as a reservoir rock (stratigraphic position and content and petrophysical properties). Together, these components confirm the Marcellus Shale as a continuous petroleum accumulation. Using the geologic framework, the USGS defined one TPS and three assessment units (AUs) within this TPS and quantitatively estimated the undiscovered oil and gas resources within the three AUs. For the purposes of this assessment, the Marcellus Shale is considered to be that Middle Devonian interval that consists primarily of shale and lesser amounts of bentonite, limestone, and siltstone occurring between the underlying Middle Devonian Onondaga Limestone (or its stratigraphic equivalents, the Needmore Shale and Huntersville Chert) and the overlying Middle Devonian Mahantango Formation (or its stratigraphic equivalents, the upper Millboro Shale and middle Hamilton Group).

Executive summary--2002 assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado: Chapter 1 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

USGS Publications Warehouse

,

2013-01-01

In 2002, the U.S. Geological Survey (USGS) estimated undiscovered oil and gas resources that have the potential for additions to reserves in the San Juan Basin Province (5022), New Mexico and Colorado (fig. 1). Paleozoic rocks were not appraised. The last oil and gas assessment for the province was in 1995 (Gautier and others, 1996). There are several important differences between the 1995 and 2002 assessments. The area assessed is smaller than that in the 1995 assessment. This assessment of undiscovered hydrocarbon resources in the San Juan Basin Province also used a slightly different approach in the assessment, and hence a number of the plays defined in the 1995 assessment are addressed differently in this report. After 1995, the USGS has applied a total petroleum system (TPS) concept to oil and gas basin assessments. The TPS approach incorporates knowledge of the source rocks, reservoir rocks, migration pathways, and time of generation and expulsion of hydrocarbons; thus the assessments are geologically based. Each TPS is subdivided into one or more assessment units, usually defined by a unique set of reservoir rocks, but which have in common the same source rock. Four TPSs and 14 assessment units were geologically evaluated, and for 13 units, the undiscovered oil and gas resources were quantitatively assessed.

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

USGS Publications Warehouse

Ulmishek, Gregory F.

2001-01-01

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

Tectonics, basin analysis and organic geochemical attributes of Permian through Mesozoic deposits and their derivative oils of the Turpan-Hami basin, northwestern China

NASA Astrophysics Data System (ADS)

Greene, Todd Jeremy

The Turpan-Hami basin is a major physiographic and geologic feature of northwest China, yet considerable uncertainty exists as to the timing of its inception, its late Paleozoic and Mesozoic tectonic history, and the relationship of its petroleum systems to those of the nearby Junggar basin. Mesozoic sedimentary fades, regional unconformities, sediment dispersal patterns, and sediment compositions within the Turpan-Hami and southern Junggar basins suggest that these basins were initially separated between Early Triassic and Early Jurassic time. Prior to separation, Upper Permian profundal lacustrine and fan-delta fades and Triassic coarse-grained braided-fluvial/alluvial fades were deposited across a contiguous Junggar-Turpan-Hami basin. Permian through Triassic fades were derived mainly from the Tian Shan to the south as indicated by northward-directed paleocurrent directions and geochemical provenance of granitoid cobbles. Lower through Middle Jurassic strata begin to reflect ponded coal-forming, lake-plain environments within the Turpan-Hami basin. A sharp change in sedimentary-lithic-rich Lower Jurassic sandstone followed by a return to lithic volcanic-rich Middle Jurassic sandstone points to the initial uplift and unroofing of the largely andesitic Bogda Shan range, which first shed its sedimentary cover as it emerged to become the partition between the Turpan-Hami and southern Junggar basins. In Turpan-Hami, source rock age is one of three major statistically significant discriminators of effective source rocks in the basin. A newly developed biomarker parameter appears to track conifer evolution and can distinguish Permian rocks and their correlative oils from Jurassic coals and mudrocks, and their derivative oils. Source fades is a second key control on petroleum occurrence and character. By erecting rock-to-oil correlation models, the biomarker parameters separate oil families into end-member groups: Group 1 oils---Lower/Middle Jurassic peatland/swamp fades, Group 2 oils---Lower/Middle Jurassic marginal lacustrine fades, and Group 3 oils---Upper Permian lacusbine fades. Burial history exercises a third major control on petroleum in the Turpan-Hami basin. While relatively uninterrupted deep burial in the Tabei Depression exhausted Upper Permian source rocks and brought Lower/Middle Jurassic rocks well into the oil generative window, Late Jurassic uplift in the Tainan Depression eroded much of the Lower/Middle Jurassic section and preserved Upper Permian sourced oils as biodegraded, relict, heavy oils.* *This dissertation includes a CD that is multimedia (contains text and other applications that are not available in a printed format). The CD requires the following applications: Adobe Acrobat, UNIX.

Tectonics of East Siberian Sea Basin and its influence on petroleum systems

NASA Astrophysics Data System (ADS)

Karpov, Yury; Antonina, Stoupakova; Anna, Suslova; Mariia, Agasheva

2016-04-01

The East Siberian Sea basin (ESSB) is the largest part of the Siberian Arctic shelf, extending for over 1000 km from New Siberian Islands archipelago to Wrangel Island. Nowadays East Siberian Sea margin is considered as a region with probable high petroleum potential. This part of Russian Arctic shelf is the least studied. The major problems in geological investigation of East Siberian Sea shelf are absence of deep wells in area and low seismic exploration maturity. Only general conclusions on its geology and hydrocarbon systems can be drawn based on limited seismic, gravity and magnetic data, supported by projection of onshore geological data to offshore. So, that's why now only complex geological and seismic stratigraphy interpretations are provided. Today we have several concepts and can summarize the tectonic history of the basin. The basin is filled with siliclastic sediments. In the deepest depocentres sediments thickness exceed 8 km in average. Seismic data was interpreted using methods of seismic stratigraphy. Stratigraphic interpretation was possible to achieve because seismic reflections follow chronostratigraphic correlations. Finally, main seismic horizons were indicated. Each indicated horizon follows regional stratigraphic unconformity. In case of absence of deep wells in ESSB, we can only prove possible source rocks by projection of data about New Siberian Islands archipelago source rocks on offshore. The petroleum potential of these rocks was investigated by several authors [1, 2, 3]. Perspective structures, investigated in ESSB were founded out by comparing seismogeological cross-sections with explored analogs in other Russian and foreign onshore and offshore basins. The majority of structures could be connected with stratigraphic and fault traps. New data on possible petroleum plays was analyzed, large massif of data on geology and tectonic history of the region was collected, so now we can use method of basin modelling to evaluate hydrocarbon saturation in most perspective prospects. Factors of tectonic history, high thickness of sediments in basin, founded possible oil and gas source rocks promise success in future exploration, but in ESSB we also recommend further geophysical investigations (seismic, gravy and magnetic) and well testing of some most perspective prospects, despite of high cost of these activities. We suppose, that investigations of ESSB should be continued to receive positive effects for Russian national economy in the nearest future. References [1] Kirillova (eds) [2013] Geological setting and petroleum potential of sedimentary basins of East Siberian Sea continental margin, v. 1, (in Russian) 249. [2] Sobolev (eds) [2012] Investigation of main sequences of Paleozoic and Meso-Cenozoic sedimentary and magmatic complexes of New Siberian Islands Archipelago, (in Russian), 143. [3] Suprunenko (eds) [2005] Petroleum zoning of Russian East Arctic shelf, Comparative analysis of petroleum potential of this aquatories with definition of perspective prospects and choise of most perspective objects for future projects, v. 1, (in Russian), 264.

The Process and Reason of the Change of Oil-Water Contact of Shahejie Formation in BZ25-1 Oilfield

NASA Astrophysics Data System (ADS)

Cong, F.; Liu, J.

2015-12-01

Due to the influence of Neo-tectonic movement, the Shahejie reservoirs in Bohai Bay Basin has undergone late-stage transformation and adjustment, causing the oil-water contact to change. Through studying the changing history of oil-water contact, we can better restore petroleum accumulation process and analyze oil distribution pattern. Based on reservoir geochemistry theory and drilling and logging data, grains with oil inclusion was analyzed, and oil-bearing property, organic extracts and biomarkers was used to determine the present and paleo-oil water contact of Shahejie formation in BZ25-1 oilfield. It suggested that the paleo and present oil-water contact in Shahejie formation locates in different depth, and that Shahejie formation has gone through three petroleum charging stages and has also undergone reservoir adjustment. The POWC(paleo-oil-water contact) of E2S2 reservoirs in BZ25-1-5 well and E2S2 reservoirs in BZ25-1-3 well is lower than OWC(present oil-water contact) at least for 9m and at most for 400m, but the POWC of E2S3 reservoirs in BZ25-1-5 well is higher than OWC at least for 20m and at most for 27.5m. The petroleum accumulation process and the reason for oil-water contact adjustment were studied based on burial history, petroleum generation history, fault re-activation rate and petroleum charging history. It suggested that the three petroleum charging stages are Mid-Miocene(11.5Ma), Late Miocene-Pliocene(6.5-3.5Ma) and Quaternary(2.5Ma-present), among which the second~third charging episode is seen as the major petroleum accumulation stage. The re-activeted faults in several different periods not only served as preferential path for petroleum vertical migration, but also caused petroleum leakage through faults. The petroleum leakage mainly occurred in Neo-tectonic movement period(after 3.5Ma), during which petroleum vertically leaked through re-activated faults and migrated to shallow reservoirs or spilled over surface, meanwhile due to constant petroleum charging from active source rock, the present oil-water contact was formed. The re-activeted faults during Neo-tectonic movement period and active source rock are seen as main reason for oil-water contact adjustment in Shahejie formation.

Petroleum system modeling capabilities for use in oil and gas resource assessments

USGS Publications Warehouse

Higley, Debra K.; Lewan, Michael; Roberts, Laura N.R.; Henry, Mitchell E.

2006-01-01

Summary: Petroleum resource assessments are among the most highly visible and frequently cited scientific products of the U.S. Geological Survey. The assessments integrate diverse and extensive information on the geologic, geochemical, and petroleum production histories of provinces and regions of the United States and the World. Petroleum systems modeling incorporates these geoscience data in ways that strengthen the assessment process and results are presented visually and numerically. The purpose of this report is to outline the requirements, advantages, and limitations of one-dimensional (1-D), two-dimensional (2-D), and three-dimensional (3-D) petroleum systems modeling that can be applied to the assessment of oil and gas resources. Primary focus is on the application of the Integrated Exploration Systems (IES) PetroMod? software because of familiarity with that program as well as the emphasis by the USGS Energy Program on standardizing to one modeling application. The Western Canada Sedimentary Basin (WCSB) is used to demonstrate the use of the PetroMod? software. Petroleum systems modeling quantitatively extends the 'total petroleum systems' (TPS) concept (Magoon and Dow, 1994; Magoon and Schmoker, 2000) that is employed in USGS resource assessments. Modeling allows integration of state-of-the-art analysis techniques, and provides the means to test and refine understanding of oil and gas generation, migration, and accumulation. Results of modeling are presented visually, numerically, and statistically, which enhances interpretation of the processes that affect TPSs through time. Modeling also provides a framework for the input and processing of many kinds of data essential in resource assessment, including (1) petroleum system elements such as reservoir, seal, and source rock intervals; (2) timing of depositional, hiatus, and erosional events and their influences on petroleum systems; (3) incorporation of vertical and lateral distribution and lithologies of strata that compose the petroleum systems; and (4) calculations of pressure-volume-temperature (PVT) histories. As digital data on petroleum systems continue to expand, the models can integrate these data into USGS resource assessments by building and displaying, through time, areas of petroleum generation, migration pathways, accumulations, and relative contributions of source rocks to the hydrocarbon components. IES PetroMod? 1-D, 2-D, and 3-D models are integrated such that each uses the same variables for petroleum systems modeling. 1-D burial history models are point locations, mainly wells. Maps and cross-sections model geologic information in two dimensions and can incorporate direct input of 2-D seismic data and interpretations using various formats. Both 1-D and 2-D models use data essential for assessments and, following data compilation, they can be completed in hours and retested in minutes. Such models should be built early in the geologic assessment process, inasmuch as they incorporate the petroleum system elements of reservoir, source, and seal rock intervals with associated lithologies and depositional and erosional ages. The models can be used to delineate the petroleum systems. A number of 1-D and 2-D models can be constructed across a geologic province and used by the assessment geologists as a 3-D framework of processes that control petroleum generation, migration, and accumulation. The primary limitation of these models is that they only represent generation, migration, and accumulation in two dimensions. 3-D models are generally built at reservoir to basin scales. They provide a much more detailed and realistic representation of petroleum systems than 1-D or 2-D models because they portray more fully the temporal and physical relations among (1) burial history; (2) lithologies and associated changes through burial in porosity, permeability, and compaction; (3) hydrodynamic effects; and (4) other parameters that influence petroleum gen

Burial history, thermal maturity, and oil and gas generation history of petroleum systems in the Wind River Basin Province, central Wyoming: Chapter 6 in Petroleum systems and geologic assessment of oil and gas resources in the Wind River Basin Province, Wyoming

USGS Publications Warehouse

Roberts, Laura N.R.; Finn, Thomas M.; Lewan, Michael D.; Kirschbaum, Mark A.

2007-01-01

Burial history, thermal maturity, and timing of oil and gas generation were modeled for eight key source rock units at nine well locations throughout the Wind River Basin Province. Petroleum source rocks include the Permian Phosphoria Formation, the Cretaceous Mowry Shale, Cody Shale, and Mesaverde, Meeteetse, and Lance Formations, and the Tertiary (Paleocene) Fort Union Formation, including the Waltman Shale Member. Within the province boundary, the Phosphoria is thin and only locally rich in organic carbon. Phosphoria oil produced from reservoirs in the province is thought to have migrated from the Wyoming and Idaho thrust belt. Locations (wells) selected for burial history reconstructions include three in the deepest parts of the province (Adams OAB-17, Bighorn 1-5, and Coastal Owl Creek); three at intermediate depths (Hells Half Acre, Shell 33X-10, and West Poison Spider); and three at relatively shallow locations (Young Ranch, Amoco Unit 100, and Conoco-Coal Bank). The thermal maturity of source rocks is greatest in the deep northern and central parts of the province and decreases to the south and east toward the basin margins. The results of the modeling indicate that, in the deepest areas, (1) peak petroleum generation from Cretaceous rocks occurred from Late Cretaceous through middle Eocene time, and (2) onset of oil generation from the Waltman Shale Member occurred from late Eocene to early Miocene time. Based on modeling results, gas generation from the cracking of Phosphoria oil reservoired in the Park City Formation reached a peak in the late Paleocene/early Eocene (58 to 55 Ma) only in the deepest parts of the province. The Mowry Shale and Cody Shale (in the eastern half of the basin) contain a mix of Type-II and Type-III kerogens. Oil generation from predominantly Type-II source rocks of these units in the deepest parts of the province reached peak rates during the latest Cretaceous to early Eocene (65 to 55 Ma). Only in these areas of the basin did these units reach peak gas generation from the cracking of oil, which occurred in the early to middle Eocene (55 to 42 Ma). Gas-prone source rocks of the Mowry and Cody Shales (predominantly Type-III kerogen), and the Mesaverde, Meeteetse, Lance, and Fort Union Formations (Type –III kerogen) reached peak gas generation in the latest Cretaceous to late Eocene (67 to 38 Ma) in the deepest parts of the province. Gas generation from the Mesaverde source rocks started at all of the modeled locations but reached peak generation at only the deepest locations and at the Hells Half Acre location in the middle Paleocene to early Eocene (59 to 48 Ma). Also at the deepest locations, peak gas generation occurred from the late Paleocene to the early Eocene (57 to 49 Ma) for the Meeteetse Formation, and during the Eocene for the Lance Formation (55 to 48 Ma) and the Fort Union Formation (44 to 38 Ma). The Waltman Shale Member of the Fort Union Formation contains Type-II kerogen. The base of the Waltman reached a level of thermal maturity to generate oil only at the deep-basin locations (Adams OAB-17 and Bighorn 1-5 locations) in the middle Eocene to early Miocene (36 to 20 Ma).

The cretaceous source rocks in the Zagros Foothills of Iran: An example of a large size intracratonic basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Bordenave, M.L.; Huc, A.Y.

1993-02-01

The Zagros orogenic belt of Iran is one of the world most prolific petroleum producing area. However, most of the oil production is originated from a relatively small area, the 60,000 km[sup 2] wide Dezful Embayment which contains approximately 12% of the proven oil global reserves. The distribution of the oil and gas fields results from the area extent of six identified source rock layers, their thermal history and reservoir, cap rock and trap availability. In this paper, the emphasis is three of the layers of Cretaceous sources rocks. The Garau facies was deposited during the Neocomian to Albian intervalmore » over Lurestan, Northeast Khuzestan and extends over the extreme northeast part of Fars, the Kazhdumi source rock which deposited over the Dezful Embayment, and eventually the Senonian Gurpi Formation which has marginal source rock characteristics in limited areas of Khuzestan and Northern Fars. The deposition environment of these source rock layers corresponds to semipermanent depressions, included in an overall shallow water intracratonic basin communicating with the South Tethys Ocean. These depressions became anoxic when climatic oceanographical and geological conditions were adequate, i.e., humid climate, high stand water, influxes of fine grained clastics and the existence of sills separating the depression from the open sea. Distribution maps of these source rock layers resulting from extensive field work and well control are also given. The maturation history of source rocks is reconstructed from a set of isopachs. It was found that the main contributor to the oil reserves is the Kazhdumi source rock which is associated with excellent calcareous reservoirs.« less

40Ar/39Ar geochronology of hypabyssal igneous rocks in the Maranon Basin of Peru - A record of thermal history, structure, and alteration

USGS Publications Warehouse

Prueher, L.M.; Erlich, R.; Snee, L.W.

2005-01-01

Hypabyssal andesites and dacites from the Balsapuerto Dome in the Mara?on Basin of Peru record the thermal, tectonic, and alteration history of the area. The Mara?on Basin is one of 19 sub-Andean foreland basins. The hypabyssal rocks in the Balsapuerto Dome are one of four known occurrences of subvolcanic rocks along the deformation front in Peru. This dome is a potential petroleum structural trap. Petroleum seeps near the dome indicate that a source for the petroleum is present, but the extent and amount of petroleum development is unknown. The Balsapuerto hypabyssal rocks are plagioclase-, hornblende-, pyroxene-phyric andesites to dacites. Some parts of the dome are pervasively altered to a hydrothermal assemblage of quartz-sericite-pyrite. 40Ar/39Ar geochronology shows that thermal activity related to emplacement of these subvolcanic rocks took place between 12-10 Ma, subsequent to the major periods of Andean folding and faulting, previously assumed to have occurred about 9 Ma. Eleven argon mineral age-spectrum analyses were completed. Argon apparent ages on amphibole range from 12.7 to 11.6 Ma, and the age spectra are simple, which indicates that the ages are very close to emplacement ages. Potassium feldspar yields an argon age spectrum ranging in age from 12.5 to 11.4 Ma, reflecting the period during which the potassium feldspar closed to argon diffusion between the temperature range of 350?C to about 150?C; thus the potassium feldspar age spectrum reflects a cooling profile throughout this temperature range. This age range is consistent with ages of emplacement for the entire igneous complex indicating that an increased thermal state existed in the area for at least 1.0 m.y. Combined with the coexisting hornblende age, this rock cooled from ~580?C to ~150?C in ~1.2 m.y. resulting in an average cooling rate of 358?C /m.y. White mica, or sericite, formed as a later alteration phase associated with quartz- sericite- pyrite and propylitic alteration in some samples. Three age-spectrum analyses on white mica indicate that alteration occurred at 12.5 Ma and again at 11 Ma, and suggest that alteration fluids were present throughout the range of emplacement and as long as 0.5 m.y. afterward. Based on these data, emplacement of the intrusive body(ies) began at about 12.7 Ma. The hornblende age range can be interpreted to reflect multiple periods of intrusion from 12.7 to 11.6 Ma or a period of thermal activity and high-temperature cooling during this age range. The potassium feldspar cooling age range supports either interpretation. The white mica ages indicate that at least two periods of hydrothermal activity occurred at 12.5 and 11.0 Ma, throughout the period of emplacement and cooling of the intrusive body below about 150?C. The magmatic and hydrothermal systems were active after the intrusion, with temperatures not reaching 150?C until about 1 m.y. after emplacement. Therefore, the thermal effects associated with emplacement of the intrusion and the associated hydrothermal system were probably high enough to destroy petroleum in the host and source rocks. Thus, the Balsapuerto Dome is not a viable source of petroleum. There is no evidence in the rock samples or thin sections for brittle or ductile deformation suggesting that this body was emplaced in its present location after cessation of Andean thrusting. Andean thrusting had been assumed to end about 9 Ma. However, this new data suggested that the Andean thrusting had ceased by about 12-10 Ma.

Some Cenozoic hydrocarbon basins on the continental shelf of Vietnam

DOE Office of Scientific and Technical Information (OSTI.GOV)

Dien, P.T.

1994-07-01

The formation of the East Vietnam Sea basins was related to different geodynamic processes. The pre-Oligocene basement consists of igneous, metamorphic, and metasediment complexes. The Cretaceous-Eocene basement formations are formed by convergence of continents after destruction of the Tethys Ocean. Many Jurassic-Eocene fractured magmatic highs of the Cuulong basin basement constitute important reservoirs that are producing good crude oil. The Paleocene-Eocene formations are characterized by intramountain metamolasses, sometimes interbedded volcanic rocks. Interior structures of the Tertiary basins connect with rifted branches of the widened East Vietnam Sea. Bacbo (Song Hong) basin is predominated by alluvial-rhythmic clastics in high-constructive deltas, whichmore » developed on the rifting and sagging structures of the continental branch. Petroleum plays are constituted from Type III source rocks, clastic reservoirs, and local caprocks. Cuulong basin represents sagging structures and is predominated by fine clastics, with tidal-lagoonal fine sandstone and shalestone in high-destructive deltas that are rich in Type II source rocks. The association of the pre-Cenozoic fractured basement reservoirs and the Oligocene-Miocene clastic reservoir sequences with the Oligocene source rocks and the good caprocks is frequently met in petroleum plays of this basin. Nan Conson basin was formed from complicated structures that are related to spreading of the oceanic branch. This basin is characterized by Oligocene epicontinental fine clastics and Miocene marine carbonates that are rich in Types I, II, and III organic matter. There are both pre-Cenozoic fractured basement reservoirs, Miocene buildup carbonate reservoir rocks and Oligocene-Miocene clastic reservoir sequences, in this basin. Pliocene-Quaternary sediments are sand and mud carbonates in the shelf facies of the East Vietnam Sea back-arc basin. Their great thickness provides good conditions for maturation and trapping.« less

Chapter 34: Geology and petroleum potential of the rifted margins of the Canada Basin

USGS Publications Warehouse

Houseknecht, D.W.; Bird, K.J.

2011-01-01

Three sides of the Canada Basin are bordered by high-standing, conjugate rift shoulders of the Chukchi Borderland, Alaska and Canada. The Alaska and Canada margins are mantled with thick, growth-faulted sediment prisms, and the Chukchi Borderland contains only a thin veneer of sediment. The rift-margin strata of Alaska and Canada reflect the tectonics and sediment dispersal systems of adjacent continental regions whereas the Chukchi Borderland was tectonically isolated from these sediment dispersal systems. Along the eastern Alaska-southern Canada margin, termed herein the 'Canning-Mackenzie deformed margin', the rifted margin is deformed by ongoing Brooks Range tectonism. Additional contractional structures occur in a gravity fold belt that may be present along the entire Alaska and Canada margins of the Canada Basin. Source-rock data inboard of the rift shoulders and regional palaeogeographic reconstructions suggest three potential source-rock intervals: Lower Cretaceous (Hauterivian-Albian), Upper Cretaceous (mostly Turonian) and Lower Palaeogene. Burial history modelling indicates favourable timing for generation from all three intervals beneath the Alaska and Canada passive margins, and an active petroleum system has been documented in the Canning-Mackenzie deformed margin. Assessment of undiscovered petroleum resources indicates the greatest potential in the Canning-Mackenzie deformed margin and significant potential in the Canada and Alaska passive margins. ?? 2011 The Geological Society of London.

Geology and petroleum resources of the Barents-northern Kara shelf in light of new geologic data

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ulmishek, G.

1985-10-01

The Barents-northern Kara shelf, one of the largest continental shelves in the world, is still in the earliest stage of exploration for oil and gas. During the last several years, numerous seismic surveys have been conducted, a number of wells have been drilled, and several gas fields have been discovered. This report summarizes the geological data gathered during recent exploration activities and presents the changes in earlier concepts necessitated by consideration of these new data. The revised assessment of undiscovered petroleum resources is based on new information about the distribution and quality of source rocks and reservoir rocks and themore » structural framework of the shelf. Special attention is paid to evaluating the oil versus gas potential of the shelf, an evaluation that strongly depends on the expected offshore extension of oil-source facies in the Lower-Middle Triassic section. The most probable amounts of undiscovered petroleum resources of the shelf are estimated at 14.2 x 10/sup 9/ barrels of oil and 312.2 x 10/sup 12/ cubic feet of gas. The Finnmark trough, the south Barents and North Novaya Zemlya depressions, and the offshore continuation of the Timan-Pechora basin possess the great majority of these resources. 103 refs., 12 figs., 1 tab.« less

Petroleum Source Rock Maturation Data Constrain Predictions of Natural Hydrocarbon Seepage into the Atmosphere

NASA Astrophysics Data System (ADS)

Mansfield, M. L.

2013-12-01

Natural seepage of methane from the lithosphere to the atmosphere occurs in regions with large natural gas deposits. According to some authors, it accounts for roughly 5% of the global methane budget. I explore a new approach to estimate methane fluxes based on the maturation of kerogen, which is the hydrocarbon polymer present in petroleum source rocks, and whose pyrolysis leads to the formation of oil and natural gas. The temporal change in the atomic H/C ratio of kerogen lets us estimate the total carbon mass released by it in the form of oil and natural gas. Then the time interval of active kerogen pyrolysis lets us estimate the average annual formation rate of oil and natural gas in any given petroleum system. Obviously, this is an upper bound to the average annual rate at which natural gas seeps into the atmosphere. After adjusting for bio-oxidation of natural gas, I conclude that the average annual seepage rate in the Uinta Basin of eastern Utah is not greater than (3100 × 900) tonne/y. This is (0.5 × 0.15)% of the total flux of methane into the atmosphere over the Basin, as measured during aircraft flights. I speculate about the difference between the regional 0.5% and the global 5% estimates.

Relationship of oil seep in Kudat Peninsula with surrounding rocks based on geochemical analysis

NASA Astrophysics Data System (ADS)

Izzati Azman, Nurul; Nur Fathiyah Jamaludin, Siti

2017-10-01

This study aims to investigate the relation of oil seepage at Sikuati area with the structural and petroleum system of Kudat Peninsula. The abundance of highly carbonaceous rocks with presence of lamination in the Sikuati Member outcrop at Kudat Peninsula may give an idea on the presence of oil seepage in this area. A detailed geochemical analysis of source rock sample and oil seepage from Sikuati area was carried out for their characterization and correlation. Hydrocarbon propectivity of Sikuati Member source rock is poor to good with Total Organic Carbon (TOC) value of 0.11% to 1.48%. and also categorized as immature to early mature oil window with Vitrinite Reflectance (VRo) value of 0.43% to 0.50 %Ro. Based on biomarker distribution, from Gas Chromatography (GC) and Gas Chromatography-Mass Spectrometry (GC-MS) analysis, source rock sample shows Pr/Ph, CPI and WI of 2.22 to 2.68, 2.17 to 2.19 and 2.46 to 2.74 respectively indicates the source rock is immature and coming from terrestrial environment. The source rock might be rich in carbonaceous material organic matter resulting from planktonic/bacterial activity which occurs at fluvial to fluvio-deltaic environment. Overall, the source rock from outcrop level of Kudat Peninsula is moderately prolific in term of prospectivity and maturity. However, as go far deeper beneath the surface, we can expect more activity of mature source rock that generate and expulse hydrocarbon from the subsurface then migrating through deep-seated fault beneath the Sikuati area.

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

USGS Publications Warehouse

Higley, D.K.

2001-01-01

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.

Chapter 5. Assessment of undiscovered conventional oil and gas resources-Lower Cretaceous Travis Peak and Hosston formations, Jurassic Smackover interior salt basins total petroleum system, in the East Texas basin and Louisiana-Mississippi salt basins provinces.

USGS Publications Warehouse

Dyman, T.S.; Condon, S.M.

2006-01-01

The petroleum assessment of the Travis Peak and Hosston Formations was conducted by using a total petroleum system model. A total petroleum system includes all of the important elements of a hydrocarbon fluid system needed to develop oil and gas accumulations, including source and reservoir rocks, hydrocarbon generation, migration, traps and seals, and undiscovered accumulations. A total petroleum system is mappable and may include one or more assessment units. For each assessment unit, reservoir rocks contain similar geology, exploration characteristics, and risk. The Jurassic Smackover Interior Salt Basins Total Petroleum System is defined for this assessment to include (1) Upper Jurassic Smackover carbonates and calcareous shales and organic-rich shales of the Upper Jurassic Bossier Shale of the Cotton Valley Group and (2) Lower Cretaceous Travis Peak and Hosston Formations. The Jurassic Smackover Interior Salt Basins Total Petroleum System includes three conventional Travis Peak-Hosston assessment units: Travis Peak-Hosston Gas and Oil (AU 50490205), Travis Peak-Hosston Updip Oil (AU 50490206), and Travis Peak-Hosston Hypothetical Updip Oil (AU 50490207). A fourth assessment unit, the Hosston Hypothetical Slope-Basin Gas Assessment Unit, was named and numbered (AU 50490208) but not geologically defined or quantitatively assessed owing to a lack of data. Together, assessment units 50490205 to 50490207 are estimated to contain a mean undiscovered conventional resource of 29 million barrels of oil, 1,136 billion cubic feet of gas, and 22 million barrels of natural gas liquids.

Stratigraphic variations in the biomarker distribution of the Moreno Formation: Their correlation with San Joaquin basin oils

DOE Office of Scientific and Technical Information (OSTI.GOV)

Bac, M.G.; Schulein, B.J.

1990-05-01

Variability in the biomarker compositions of petroleums is typically employed in the recognition and distinction of contributions from different source rocks. We demonstrate that the fluctuations in the biomarker distributions of different intervals within a single source rock sequence appear to account for specific compositional differences in a suite of oils from the San Joaquin basin California. Rock-Eval pyrolysis studies of a 100-m-thick immature, laminated, marine shale sequence within the Upper Cretaceous lo lower Paleocene portion of the Moreno Formation reveals TOC (total organic carbon) contents consistently around 2% and moderate hydrogen indices (i.e., 175-300 mg HC/g org. C) characteristicsmore » suggestive of a uniform depositional sequence with source rock potential. Analyses of the extractable aliphatic hydrocarbons of cored samples taken at approximately 10-m intervals from the sequence reveal significant variability in biomarker distributions. Such differences are exemplified by the triterpenoids (as seen in m/z 191 chromatograms from GC-MS and GC-MS/MS analyses) where the dominant component fluctuates from a 17{alpha}(h),21{beta}(H)-30-norhopane to 28,30-l8{alpha}(H)-bisnorhopane to 20S and 20R danunar-13(17)-enes. Some components are dominant in one interval, but are not detected in others, suggesting discrete stratigraphic variations in the biomarker characteristics of the Moreno. Similar discrepancies in biomarker distributions are evident in the aliphatic hydrocarbons of the suite of oils. The three petroleums reservoired in the San Carlos sandstone member of the Lodo Formation which directly overlies the Moreno, reflect biomarker contributions from a Moreno source, including compound distributions, and the occurrence of both alkanes (e.g., 28.30-bisnorhopane) and alkenes (e.g.. danunarenes and diasterenes).« less

Geologic Cross Section D-D' Through the Appalachian Basin from the Findlay Arch, Sandusky County, Ohio, to the Valley and Ridge Province, Hardy County, West Virginia

USGS Publications Warehouse

Ryder, Robert T.; Crangle, Robert D.; Trippi, Michael H.; Swezey, Christopher S.; Lentz, Erika E.; Rowan, Elisabeth L.; Hope, Rebecca S.

2009-01-01

Geologic cross section D-D' is the second in a series of cross sections constructed by the U.S. Geological Survey to document and improve understanding of the geologic framework and petroleum systems of the Appalachian basin. Cross section D-D' provides a regional view of the structural and stratigraphic framework of the Appalachian basin from the Findlay arch in northwestern Ohio to the Valley and Ridge province in eastern West Virginia, a distance of approximately 290 miles. The information shown on the cross section is based on geological and geophysical data from 13 deep drill holes, several of which penetrate the Paleozoic sedimentary rocks of the basin and bottom in Mesoproterozoic (Grenville-age) crystalline basement rocks. This cross section is a companion to cross section E-E' (Ryder and others, 2008) that is located about 25 to 50 mi to the southwest. Although specific petroleum systems in the Appalachian basin are not identified on the cross section, many of their key elements (such as source rocks, reservoir rocks, seals, and traps) can be inferred from lithologic units, unconformities, and geologic structures shown on the cross section. Other aspects of petroleum systems (such as the timing of petroleum generation and preferred migration pathways) may be evaluated by burial history, thermal history, and fluid flow models based on information shown on the cross section. Cross section D-D' lacks the detail to illustrate key elements of coal systems (such as paleoclimate, coal quality, and coal rank), but it does provide a general geologic framework (stratigraphic units and general rock types) for the coal-bearing section. Also, cross section D-D' may be used as a reconnaissance tool to identify plausible geologic structures and strata for the subsurface storage of liquid waste or for the sequestration of carbon dioxide.

Timing of oil and gas generation of petroleum systems in the Southwestern Wyoming Province

USGS Publications Warehouse

Roberts, L.N.R.; Lewan, M.D.; Finn, T.M.

2004-01-01

Burial history, thermal maturity, and timing of petroleum generation were modeled for eight key source-rock horizons at seven locations throughout the Southwestern Wyoming Province. The horizons are the bases of the Lower Permian Phosphoria Formation, the Upper Cretaceous Mowry Shale, Niobrara Formation, Baxter Shale (and equivalents), upper part of the Mesaverde Group, Lewis Shale, Lance Formation, and the Tertiary (Paleocene) Fort Union Formation. Burial history locations include three in the deepest parts of the province (Adobe Town in the Washakie Basin, Eagles Nest in the Great Divide Basin, and Wagon Wheel in the northern Green River Basin); two at intermediate basin depths (Federal 31-1 and Currant, Creek in the central and southern parts of the Green River Basin, respectively); and two relatively shallow locations (Bear 1 on the southeastern margin of the Sand Wash Basin and Bruff 2 on the Moxa arch). An overall ranking of the burial history locations in order of decreasing thermal maturity is Adobe Town > Eagles Nest > Wagon Wheel > Currant Creek > Federal 31-1 > Bear-1 > Bruff 2. The results of the models indicate that peak petroleum generation from Cretaceous oil- and gas-prone source rocks in the deepest parts of the province occurred from Late Cretaceous through middle Eocene. At the modeled locations, peak oil generation from source rocks of the Phosphoria Formation, which contain type-IIS kerogen, occurred in the Late Cretaceous (80 to 73 million years ago (Ma)). Gas generation from the cracking of Phosphoria oil reached a peak in the late Paleocene (57 Ma) only in the deepest parts of the province. The Mowry Shale, Niobrara Formation, and Baxter Shale (and equivalents) contain type-IIS or a mix of type-II and type-III kerogens. Oil generation from these units, in the deepest parts of the province, reached peak rates during the latest Cretaceous to early Paleocene (66 to 61 Ma). Only at these deepest locations did these units reach peak gas generation from the cracking of oil, which occurred in the early to late Eocene (52 to 41 Ma). For the Mesaverde Group, which also contains a mix of type-II and type-III kerogen, peak oil generation occurred only in the deepest parts of the province during middle Eocene (50 to 41 Ma). Only at Adobe Town did cracking of oil occur and gas generation reach peak in the earliest Oligocene (33 Ma). Gas-prone source rocks (type-III kerogen) of the Mowry and Baxter (and equivalents) Shales reached peak gas generation in the latest Cretaceous (66 Ma) in the deepest parts of the province. At the shallower Bear 1 location, the Mancos Shale (Baxter equivalent) source rocks reached peak gas generation at about this same time. Gas generation from the gas-prone Mesaverde source rocks started at all of the modeled locations, but reached peak generation at only the deepest locations in the early Eocene (54 to 49 Ma). The Lewis Shale, Lance Formation, and Fort Union Formation all contain gas-prone source rocks with type-III kerogen. Peak generation of gas from the Lewis Shale occurred only at Eagles Nest and Adobe Town in the early Eocene (52 Ma). Source rocks of the Lance reached peak gas generation only at the deepest locations during the middle Eocene (48 to 45 Ma) and the Fort Union reached peak gas generation only at Adobe Town also in the middle Eocene (44 Ma).

40 CFR 52.28 - Protection of visibility from sources in nonattainment areas.

Code of Federal Regulations, 2013 CFR

2013-07-01

... categories: (A) Coal cleaning plants (with thermal dryers); (B) Kraft pulp mills; (C) Portland cement plants...) Phosphate rock processing plants; (M) Coke oven batteries; (N) Sulfur recovery plants; (O) Carbon black... thereof) totaling more than 250 million British thermal units per hour heat input; (V) Petroleum storage...

40 CFR 52.28 - Protection of visibility from sources in nonattainment areas.

Code of Federal Regulations, 2010 CFR

2010-07-01

... categories: (A) Coal cleaning plants (with thermal dryers); (B) Kraft pulp mills; (C) Portland cement plants...) Phosphate rock processing plants; (M) Coke oven batteries; (N) Sulfur recovery plants; (O) Carbon black... thereof) totaling more than 250 million British thermal units per hour heat input; (V) Petroleum storage...

40 CFR 52.28 - Protection of visibility from sources in nonattainment areas.

Code of Federal Regulations, 2012 CFR

2012-07-01

... categories: (A) Coal cleaning plants (with thermal dryers); (B) Kraft pulp mills; (C) Portland cement plants...) Phosphate rock processing plants; (M) Coke oven batteries; (N) Sulfur recovery plants; (O) Carbon black... thereof) totaling more than 250 million British thermal units per hour heat input; (V) Petroleum storage...

40 CFR 52.28 - Protection of visibility from sources in nonattainment areas.

Code of Federal Regulations, 2014 CFR

2014-07-01

... categories: (A) Coal cleaning plants (with thermal dryers); (B) Kraft pulp mills; (C) Portland cement plants...) Phosphate rock processing plants; (M) Coke oven batteries; (N) Sulfur recovery plants; (O) Carbon black... thereof) totaling more than 250 million British thermal units per hour heat input; (V) Petroleum storage...

40 CFR 52.28 - Protection of visibility from sources in nonattainment areas.

Code of Federal Regulations, 2011 CFR

2011-07-01

... categories: (A) Coal cleaning plants (with thermal dryers); (B) Kraft pulp mills; (C) Portland cement plants...) Phosphate rock processing plants; (M) Coke oven batteries; (N) Sulfur recovery plants; (O) Carbon black... thereof) totaling more than 250 million British thermal units per hour heat input; (V) Petroleum storage...

4D petroleum system model of the Mississippian System in the Anadarko Basin Province, Oklahoma, Kansas, Texas, and Colorado, U.S.A.

USGS Publications Warehouse

Higley, Debra K.

2013-01-01

The Upper Devonian and Lower Mississippian Woodford Shale is an important petroleum source rock for Mississippian reservoirs in the Anadarko Basin Province of Oklahoma, Kansas, Texas, and Colorado, based on results from a 4D petroleum system model of the basin. The Woodford Shale underlies Mississippian strata over most of the Anadarko Basin portions of Oklahoma and northeastern Texas. The Kansas and Colorado portions of the province are almost entirely thermally immature for oil generation from the Woodford Shale or potential Mississippian source rocks, based mainly on measured vitrinite reflectance and modeled thermal maturation. Thermal maturities of the Woodford Shale range from mature for oil to overmature for gas generation at present-day depths of about 5,000 to 20,000 ft. Oil generation began at burial depths of about 6,000 to 6,500 ft. Modeled onset of Woodford Shale oil generation was about 330 million years ago (Ma); peak oil generation was from 300 to 220 Ma.Mississippian production, including horizontal wells of the informal Mississippi limestone, is concentrated within and north of the Sooner Trend area in the northeast Oklahoma portion of the basin. This large pod of oil and gas production is within the area modeled as thermally mature for oil generation from the Woodford Shale. The southern boundary of the trend approximates the 99% transformation ratio of the Woodford Shale, which marks the end of oil generation. Because most of the Sooner Trend area is thermally mature for oil generation from the Woodford Shale, the trend probably includes short- and longer-distance vertical and lateral migration. The Woodford Shale is absent in the Mocane-Laverne Field area of the eastern Oklahoma panhandle; because of this, associated oil migrated from the south into the field. If the Springer Formation or deeper Mississippian strata generated oil, then the southern field area is within the oil window for associated petroleum source rocks. Mississippian fields along the western boundary of the study area were supplied by oil that flowed northward from the Panhandle Field area and westward from the deep basin.

Petroleum geology and resources of the Baykit High province, East Siberia, Russia

USGS Publications Warehouse

Ulmishek, Gregory F.

2001-01-01

The Baykit High province consists of two principal structural units?the Baykit regional high in the west, which occupies most of the province, and the Katanga structural saddle in the east. The province is on the western margin of the Siberian craton east of theYenisey Ridge foldbelt. The province is an exploration frontier and only a few prospects have been drilled. The oldest sedimentary rocks of the province, Riphean carbonate and clastic strata of Late Proterozoic age (1,650?650 million years old) that were deposited on the passive margin, cover the Archean?Lower Proterozoic basement. Basal Vendian (uppermost Proterozoic, 650?570 million years old) clastic rocks unconformably overlie various units of the Riphean and locally lie directly on the basement. Younger Vendian and lowermost Cambrian rocks are primarily dolomites. The Vendian/Cambrian boundary is con-formable, and its exact stratigraphic position has not been identified with certainty. The Lower Cambrian section is thick, and it consists of alternating beds of dolomite and evaporites (mostly salt). Middle and Upper Cambrian strata are composed of shale and dolomite. Ordovician-Silurian and upper Paleozoic rocks are thin, and they are present only in the northern areas of the province. Structural pattern of Riphean rocks differs substantially from that of Vendian-Cambrian rocks. A single total petroleum system (TPS) was identified in the Baykit High province. Discovered oil of the system is chiefly concentrated in Riphean carbonate reservoirs of the Yurubchen-Tokhom zone that is currently being explored and that has the Abstract 1 potential to become a giant field (or group of fields). The TPS also contains about 5 trillion cubic feet of discovered recover-able gas in clastic reservoir rocks at the base of the Vendian section. Petroleum source rocks are absent in the stratigraphic succession over most of the TPS area. Riphean organic-rich shales and carbonates that crop out in the Yenisey Ridge foldbelt west of the Baykit high are probable source rocks. Their areal distribution extends from the foldbelt into the foredeep along the province?s western margin. Potential source rocks also are present in platform depressions in eastern areas of the province. Hydrocarbon generation and migration west of the province started as early as Riphean time, before the beginning of the deformation in the Yenisey Ridge foldbelt that occurred about 820?850 million years ago. However, the presently known oil and gas accumulations were formed after deposition of the Lower Cambrian salt seal. Available data allow identification of only one assessment unit, and it covers the entire TPS area. Undiscovered oil and gas resources are moderate, primarily due to the poor quality of reservoir rocks. However, the reserve growth in the Yurubchen-Tokhom zone may be large and may exceed the volume of undiscovered resources in the rest of the province. Most oil and gas resourcesareexpectedtobeinstructuralandstratigraphictrapsin Riphean carbonate reservoirs. Vendian clastic reservoirs are probably gas-prone.

Geologic appraisal of the petroleum potential of offshore southern California; the borderland compared to onshore coastal basins

USGS Publications Warehouse

Taylor, James Carlton

1976-01-01

Offshore southern California is part of a much larger Pacific continental margin, and the two areas have a similar geologic history at least as far back as middle Tertiary time. Assessment of the petroleum potential of the offshore Southern California borderland is accomplished by examining the adjacent highly explored productive coastal basins in the tectonically unstable area west of the San Andreas fault. Known oil and gas accumulations in this region can be characterized as follows: 88 percent comes from the Los Angeles and Ventura basins; 87 percent has been found in late Miocene and younger strata and only 0.2 percent has been found in Eocene strata; 80 percent has been found in thick deposits of deep-water turbidite reservoirs; and 5 percent has been found in fractured Miocene siliceous shale reservoirs. The percentage of siliceous shale reservoirs will increase as a result of recent discoveries in this rock type in the Santa Barbara Channel. Of the 212 known fields only 5 are giants (greater than 500 million barrels), and these fields account for 52 percent of all past production from the region. Most fields are faulted anticlines, and the largest fields have the highest oil recoveries per acre. Geologic knowledge of the offshore is limited by the availability of data. Data have been obtained from geophysical surveys, analyses of bedrock samples from the sea floor, and extrapolations of data from the mainland and offshore islands. Several factors have a negative effect on the assessment of the petroleum potential of the southern California borderland. They are: 1. The Neogene section is relatively thin, and the Paleogene section is thin and has a limited distribution. 2. Over large areas, Miocene sediments apparently rest directly on basement. 3. Along much of the Santa Rosa-Cortes Ridge, sediments are uplifted and truncated, exposing Paleogene rocks. 4. Organic content in Paleogene sediments is believed too low to generate large amounts of petroleum. 5. Source rocks are immature, even in sediments as old as Eocene. 6. Burial and thermal history are insufficient for the generaton of hydrocarbons over much of the borderland area. 7. Documented oil and gas seeps are unknown seaward of the Channel Islands. 8. Limited exploratory drilling nearshore, the best prospective area, has not been favorable. 9. Adequate or thick reservoirs of deep-water turbidire origin are not evident. These negative factors are partly offset by the following positive factors: 1. Miocene sediments are excellent potential source rocks. 2. Asphaltic oil in rocks of Monterey-type lithology may be generated at lower than normal temperatures. 3. Shallow-water sands of reservoir quality possibly are present in the uppermost Paleogene and lowermost Neogene section. 4. Potential structural traps may be analogous to major structural producing trends onshore. 5. Fractured shale reservoirs may be present along flanks of major banks and ridges. 6. Buried and unsampled Paleogene and Late Cretaceous sediments may be better source rocks than those sampled and measured. The southern California borderland, although a part of a locally rich petroliferous region, has no known basins with geologic histories or characteristics similar to the Los Angeles and Ventura basins. Some offshore basins are similar to less endowed basins in terms of petroleum potential such as the Santa Maria and Salinas basins. Areas with the best petroleum potential may be in deep water (greater than 500 m). Some of the past high estimates of the petroleum potential may have been overstated; the existing geologic data tend to substantiate low estimates of 0.6 to 5.8 billion barrels of oil and 0.6 to 5.8 trillion ft3 of gas for the southern California borderland at the 5 and 95 percent probability level.

Warm Eocene climate enhanced petroleum generation from Cretaceous source rocks - a potential climate feedback mechanism?

NASA Astrophysics Data System (ADS)

Kroeger, K. F.; Funnell, R. H.

2012-04-01

Surface and deep sea temperatures from late Paleocene to early Eocene until the Early Eocene climatic Optimum increased by 5 - 10° C. This change was associated with a negative δ13C trend which implies major changes in global carbon cycling and enrichment of surface systems in isotopically light carbon. The degree of change in sedimentary δ13C requires emission of >10,000 gigatonnes of isotopically light carbon into the ocean. We reveal a relationship between global warming and increased petroleum generation in sedimentary basins operating on 100 kyr to Myr time scales that may explain the observed isotope shift. We use TEX86-based surface temperature data1 to predict how change in surface temperature influences the temperature evolution and resultant petroleum generation in four southwest Pacific sedimentary basins. Models predict an up to 50% increase in oil and gas expulsion rates in response to the increase in temperatures from late Paleocene to early Eocene in the region. Such an increase in petroleum generation would have significantly increased leakage of light hydrocarbons and oil degeneration products into surface systems. We propose that our modelling results are representative of a large number of sedimentary basins world-wide and that early Eocene warming has led to a synchronization of periods of maximum petroleum generation and enhanced generation in otherwise unproductive basins through extension of the volume of source rock within the oil and gas window. Extrapolating our modelling results to hundreds of sedimentary basins worldwide suggests that globally increased leakage could have led to the release of an amount of CH4, CO2 and light petroleum components into surface systems compatible with the observed changes in δ13C. We further suggest that this is a significant feedback effect, enhancing early Eocene climate warming. 1Bijl, P. K., S. Schouten, A. Sluijs, G.-J. Reichart, J. C. Zachos, and H. Brinkhuis (2009), Early Palaeogene temperature evolution of the southwest Pacific Ocean, Nature, 461, 776-779.

Modelling of the petroleum formation in the Mahakam sediments (Indonesia): Organic geochemical controls of the results

DOE Office of Scientific and Technical Information (OSTI.GOV)

Brosse, E.; Burris, J.; Ouidin, J.L.

1990-06-01

Since the Miocene, the delta of the Mahakam River has accumulated thousands of meters of sediments in the eastern part of the Kutei Basin (Kalimantan, Indonesia). Source-rock candidates are the coals of the deltaic plain and several types of shales, mainly the delta front/prodelta area. Organic matter basically derives from higher plants, but each source facies presents important intrinsic variations of petroleum potential. These variations are overprinted by subsequent maturation trends. Geochemical and petrographical data are integrated on the general framework provided by a new synthetic interpretation of the sedimentary sequences, relying upon the concepts of seismic stratigraphy. From coremore » samples at a given level of maturation, the variations of several organic parameters are discussed in relation to the depositional paleoenvironment and to the possible precursors. 1D and 2D numerical routines are used to reconstruct the maturation history of source rocks. These tools are based upon a kinetic modeling of kerogen cracking. Model outputs are compared with observed maturation trends. The understanding of the initial organic facies distribution provides precise constraints in the selection of a homogenous samples set for this comparison purpose.« less

Petroleum systems of the Po Basin Province of northern Italy and the northern Adriatic Sea; Porto Garibaldi (biogenic), Meride/Riva di Solto (thermal), and Marnoso Arenacea (thermal)

USGS Publications Warehouse

Lindquist, Sandra J.

1999-01-01

The Porto Garibaldi total petroleum system dominates the Po Basin Province of onshore northern Italy and offshore Italy and Croatia in the northern Adriatic Sea. Porto Garibaldi contains Pliocene (primarily) and Pleistocene (secondarily) biogenic gas ? approximately 16 TCF (2.66 BBOE) ultimately recoverable ? accumulated in co-eval siliciclastic reservoirs. This area was the northwestern edge of the Gondwanan (African) continental plate in pre-Hercynian time until the assembly of Pangea, a dominantly carbonate passive continental margin during the Mesozoic breakup of Pangea, and a Cenozoic collision zone with siliciclastic foredeep and foreland regions surrounded by thrust belts. At least two other petroleum systems, with Triassic (Meride / Riva di Solto) and Miocene (Marnoso Arenacea) source rocks, contribute oil and thermal gas reserves (nearly 1 BBOE) to the province. The major time of hydrocarbon expulsion of the thermal systems was Late Neogene during the Alpine and Apennine orogenies. Local Mesozoic oil expulsion from Triassic rocks also occurred, but those oils either were not trapped or were leaked from faulty traps through time.

Stratigraphy of the Upper Cretaceous Mancos Shale (upper part) and Mesaverde Group in the southern part of the Uinta and Piceance basins, Utah and Colorado

USGS Publications Warehouse

Hettinger, R.D.; Kirschbaum, M.A.

2002-01-01

Cross section A–A' was constructed in support of the oil and gas assessments of the Mesaverde and Mancos/Mowry Total Petroleum Systems in the Uinta and Piceance Basins of Utah and Colorado (fig. 1) (U.S. Geological Survey Uinta-Piceance Province Assessment Team, in press). This citation is referred to henceforth as simply “USGS, in press.” The Mesaverde Total Petroleum System contains continuous gas derived primarily from carbonaceous shale and coal in the Mesaverde Group [chapter by Johnson and Roberts in USGS (in press)]. The Mancos/Mowry Total Petroleum System contains continuous gas derived primarily from marine source rocks in the Mancos and Mowry Shales [chapter by Kirschbaum in USGS (in press)]. Cross section A–A' illustrates the stratigraphy of these Upper Cretaceous rocks, emphasizing the fluvial, coal-bearing coastal plain, nearshore marine, and offshore marine strata. The cross section is presented as a hard copy in this report and as a chapter by Hettinger and Kirschbaum (USGS, in press).

Families of miocene monterey crude oil, seep, and tarball samples, coastal California

USGS Publications Warehouse

Peters, K.E.; Hostettler, F.D.; Lorenson, T.D.; Rosenbauer, R.J.

2008-01-01

Biomarker and stable carbon isotope ratios were used to infer the age, lithology, organic matter input, and depositional environment of the source rocks for 388 samples of produced crude oil, seep oil, and tarballs to better assess their origins and distributions in coastal California. These samples were used to construct a chemometric (multivariate statistical) decision tree to classify 288 additional samples. The results identify three tribes of 13C-rich oil samples inferred to originate from thermally mature equivalents of the clayey-siliceous, carbonaceous marl and lower calcareous-siliceous members of the Monterey Formation at Naples Beach near Santa Barbara. An attempt to correlate these families to rock extracts from these members in the nearby COST (continental offshore stratigraphic test) (OCS-Cal 78-164) well failed, at least in part because the rocks are thermally immature. Geochemical similarities among the oil tribes and their widespread distribution support the prograding margin model or the banktop-slope-basin model instead of the ridge-and-basin model for the deposition of the Monterey Formation. Tribe 1 contains four oil families having geochemical traits of clay-rich marine shale source rock deposited under suboxic conditions with substantial higher plant input. Tribe 2 contains four oil families with traits intermediate between tribes 1 and 3, except for abundant 28,30-bisnorhopane, indicating suboxic to anoxic marine marl source rock with hemipelagic input. Tribe 3 contains five oil families with traits of distal marine carbonate source rock deposited under anoxic conditions with pelagic but little or no higher plant input. Tribes 1 and 2 occur mainly south of Point Conception in paleogeographic settings where deep burial of the Monterey source rock favored petroleum generation from all three members or their equivalents. In this area, oil from the clayey-siliceous and carbonaceous marl members (tribes 1 and 2) may overwhelm that from the lower calcareous-siliceous member (tribe 3) because the latter is thinner and less oil-prone than the overlying members. Tribe 3 occurs mainly north of Point Conception where shallow burial caused preferential generation from the underlying lower calcareous-siliceous member or another unit with similar characteristics. In a test of the decision tree, 10 tarball samples collected from beaches in Monterey and San Mateo counties in early 2007 were found to originate from natural seeps representing different organofacies of Monterey Formation source rock instead from one anthropogenic pollution event. The seeps apparently became more active because of increased storm activity. Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

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

USGS Publications Warehouse

Dennen, Kristin O.; Johnson, Craig A.; Otter, Marshall L.; Silva, Steven R.; Wandless, Gregory A.

2006-01-01

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

Age, distribution, and stratigraphic relationship of rock units in the San Joaquin Basin Province, California: Chapter 5 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Hosford Scheirer, Allegra; Magoon, Leslie B.

2008-01-01

The San Joaquin Basin is a major petroleum province that forms the southern half of California’s Great Valley, a 700-km-long, asymmetrical basin that originated between a subduction zone to the west and the Sierra Nevada to the east. Sedimentary fill and tectonic structures of the San Joaquin Basin record the Mesozoic through Cenozoic geologic history of North America’s western margin. More than 25,000 feet (>7,500 meters) of sedimentary rocks overlie the basement surface and provide a nearly continuous record of sedimentation over the past ~100 m.y. Further, depositional geometries and fault structures document the tectonic evolution of the region from forearc setting to strike-slip basin to transpressional margin. Sedimentary architecture in the San Joaquin Basin is complicated because of these tectonic regimes and because of lateral changes in depositional environment and temporal changes in relative sea level. Few formations are widespread across the basin. Consequently, a careful analysis of sedimentary facies is required to unravel the basin’s depositional history on a regional scale. At least three high-quality organic source rocks formed in the San Joaquin Basin during periods of sea level transgression and anoxia. Generated on the basin’s west side, hydrocarbons migrated into nearly every facies type in the basin, from shelf and submarine fan sands to diatomite and shale to nonmarine coarse-grained rocks to schist. In 2003, the U.S. Geological Survey (USGS) completed a geologic assessment of undiscovered oil and gas resources and future additions to reserves in the San Joaquin Valley of California (USGS San Joaquin Basin Province Assessment Team, this volume, chapter 1). Several research aims supported this assessment: identifying and mapping the petroleum systems, modeling the generation, migration, and accumulation of hydrocarbons, and defining the volumes of rock to be analyzed for additional resources. To better understand the three dimensional relationships between hydrocarbon source and reservoir rocks, we compiled a database consisting of more than 13,000 well picks and of one-mile resolution seismic grids. Both the well picks and the seismic grids characterize the depths to the top of key stratigraphic units. This database formed the basis of subsequent numerical modeling efforts, including the construction of a three- dimensional geologic model (Hosford Scheirer, this volume, chapter 7) and simulation of the petroleum systems in space and time (Peters, Magoon, Lampe, and others, this volume, chapter 12). To accomplish this modeling, we synthesized the age, geographic distribution, lithology, and petroleum characteristics of hydrocarbon source and reservoir rocks in the basin. The results of that synthesis are presented in this paper in the form of new stratigraphic correlation columns for the northern, central, and southern San Joaquin Valley (fig. 5.1; note that all figures are at the back of this report, following the References Cited). The stratigraphic relationships and ages published here draw heavily on published and unpublished studies of the San Joaquin Basin. The stratigraphy presented in each of the columns necessarily idealizes the subsurface geology over a relatively large area, instead of representing the specific geology at an individual well, oil and gas field, or outcrop. In this paper we present the background rationale for defining the geographic divisions of the basin (inset map, fig. 5.1), the paleontological time scales used for assigning absolute ages to rock units (figs. 5.2 and 5.3), and the supporting maps illustrating the geographic distribution of each rock type included in the stratigraphic column (figs. 5.4 through 5.64).

Geology of continental margins

DOE Office of Scientific and Technical Information (OSTI.GOV)

Not Available

With continued high interest in offshore petroleum exploration, the 1977 AAPG Short Course presents the latest interpretations of new data bearing on the geology and geophysics of continental margins. Seven well-known earth scientists have organized an integrated program covering major topics involved in the development of ocean basins and continental margins with emphasis on the slopes and rises. The discussion of plate tectonics and evolution of continental margins is followed by presentations on the stratigraphy and structure of pull-apart and compressional margins. Prospective petroleum source rocks, their organic content, rate of burial, and distribution on slopes and rises of differentmore » margin types is covered. Prospective reservoir rock patterns are related to depositional processes and to the sedimentary and structural histories for different types of continental margins. Finally, the seismic recognition of depositional facies on slopes and rises for different margin types with varying rates of sediment supply during eustatic sea-level changes are discussed. The course with this syllabus offers an invaluable opportunity for explorationists to refresh their understanding of the geology associated with an important petroleum frontier. In addition, the course sets forth a technical frame of reference for the case-histoy papers to be presented later in the AAPG Research Symposium on the Petroleum Potential of Slopes, Rises, and Plateaus.« less

Analysis of Shublik Formation rocks from Mt. Michelson quadrangle, Alaska

USGS Publications Warehouse

Detterman, Robert L.

1970-01-01

Analysis of 88 samples from the Shublik formation on Fire Creek, Mt. Michelson Quadrangle, Alaska, are presented in tabular form. The results include the determination of elements by semiquantitative spectrographic analysis, phosphate by X-ray fluorescence, carbon dioxide by acid decomposable carbonate, total carbon by induction furnace, carbonate carbon by conversion using the conversion factor of 0.2727 for amount of carbon in carbon dioxide, and organic carbon by difference. A seven- cycle semilogarithmic chart presents the data graphically and illustrates the range, mode, and mean for some of the elements. The chart shows, also, the approximate concentration of the same elements in rocks similar to the black shale and limestone of the Shublik Formation. Each sample represents 5 feet of section and is composed of rock chips taken at 1 - foot intervals. The samples are keyed into a stratigraphic column of the formation. Rocks of the Shublik Formation contain anomalously high concentrations of some of the elements. These same elements might be expected to be high in some of the petroleum from northern Alaska if the Shublik Formation is a source for this petroleum. Several of the stratigraphic intervals may represent, also, a low-grade phosphate deposit.

Summary of regional geology, petroleum potential, resource assessment and environmental considerations for oil and gas lease sale area No. 56

USGS Publications Warehouse

Dillon, William P.; Klitgord, Kim D.; Paull, Charles K.; Grow, John A.; Ball, Mahlon M.; Dolton, Gordon L.; Powers, Richard B.; Khan, Abdul S.; Popenoe, Peter; Robb, James M.; Dillon, William P.

1980-01-01

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.

Petroleum geology of the Gulf of Lion (Mediterranean offshore-France)

DOE Office of Scientific and Technical Information (OSTI.GOV)

Vially, R.; Jean-Jacques, B.; Alain, I.E.M.

1995-08-01

The onshore sedimentary basins of Camargue and the northern edge of the Gulf of Lion have been explored since the middle of the last century. The results of this petroleum exploration were poor despite two small oil discoveries: the Oligocene onshore Gallician field and the Triassic onshore Gabian field (respectively 7000 tons and 23000 tons of oil production). Eleven wells were drilled offshore (from 1968 to 1985), all located on highs of the pre-Tertiary substratum. Few oil and gas shows were proven by only three of these wells. The seismic data base has been fully reinterpreted. The mapping of themore » pre-Tertiary substratum shows wide unexplored grabens in the Gulf of Lion. Some Oligocene prospects have been evidenced which are either stratigraphic traps or faulted blocks associated to salt seals. A new set of geochemical analysis of the Oligocene source rock has been performed as well as systematic generation and migration models (1D and 2D models) leading to the definition of an effective oil kitchen of an Oligocene lacustrine source rock (type 1).« less

Western Greece unconventional hydrocarbon potential from oil shale and shale gas reservoirs

NASA Astrophysics Data System (ADS)

Karakitsios, Vasileios; Agiadi, Konstantina

2013-04-01

It is clear that we are gradually running out of new sedimentary basins to explore for conventional oil and gas and that the reserves of conventional oil, which can be produced cheaply, are limited. This is the reason why several major oil companies invest in what are often called unconventional hydrocarbons: mainly oil shales, heavy oil, tar sand and shale gas. In western Greece exist important oil and gas shale reservoirs which must be added to its hydrocarbon potential1,2. Regarding oil shales, Western Greece presents significant underground immature, or close to the early maturation stage, source rocks with black shale composition. These source rock oils may be produced by applying an in-situ conversion process (ICP). A modern technology, yet unproven at a commercial scale, is the thermally conductive in-situ conversion technology, developed by Shell3. Since most of western Greece source rocks are black shales with high organic content, those, which are immature or close to the maturity limit have sufficient thickness and are located below 1500 meters depth, may be converted artificially by in situ pyrolysis. In western Greece, there are several extensive areas with these characteristics, which may be subject of exploitation in the future2. Shale gas reservoirs in Western Greece are quite possibly present in all areas where shales occur below the ground-water level, with significant extent and organic matter content greater than 1%, and during their geological history, were found under conditions corresponding to the gas window (generally at depths over 5,000 to 6,000m). Western Greece contains argillaceous source rocks, found within the gas window, from which shale gas may be produced and consequently these rocks represent exploitable shale gas reservoirs. Considering the inevitable increase in crude oil prices, it is expected that at some point soon Western Greece shales will most probably be targeted. Exploration for conventional petroleum reservoirs, through the interpretation of seismic profiles and the surface geological data, will simultaneously provide the subsurface geometry of the unconventional reservoirs. Their exploitation should follow that of conventional hydrocarbons, in order to benefit from the anticipated technological advances, eliminating environmental repercussions. As a realistic approach, the environmental consequences of the oil shale and shale gas exploitation to the natural environment of western Greece, which holds other very significant natural resources, should be delved into as early as possible. References 1Karakitsios V. & Rigakis N. 2007. Evolution and Petroleum Potential of Western Greece. J.Petroleum Geology, v. 30, no. 3, p. 197-218. 2Karakitsios V. 2013. Western Greece and Ionian Sea petroleum systems. AAPG Bulletin, in press. 3Bartis J.T., Latourrette T., Dixon L., Peterson D.J., Cecchine G. 2005. Oil Shale Development in the United States: Prospect and Policy Issues. Prepared for the National Energy Tech. Lab. of the U.S. Dept Energy. RAND Corporation, 65 p.

The significance of 24-norcholestanes, triaromatic steroids and dinosteroids in oils and Cambrian-Ordovician source rocks from the cratonic region of the Tarim Basin, NW China

USGS Publications Warehouse

Li, Meijun; Wang, T.-G.; Lillis, Paul G.; Wang, Chunjiang; Shi, Shengbao

2012-01-01

Two oil families in Ordovician reservoirs from the cratonic region of the Tarim Basin are distinguished by the distribution of regular steranes, triaromatic steroids, norcholestanes and dinosteroids. Oils with relatively lower contents of C28 regular steranes, C26 20S, C26 20R + C27 20S and C27 20R regular triaromatic steroids, dinosteranes, 24-norcholestanes and triaromatic dinosteroids originated from Middle–Upper Ordovician source rocks. In contrast, oils with abnormally high abundances of the above compounds are derived from Cambrian and Lower Ordovician source rocks. Only a few oils have previously been reported to be of Cambrian and Lower Ordovician origin, especially in the east region of the Tarim Basin. This study further reports the discovery of oil accumulations of Cambrian and Lower Ordovician origin in the Tabei and Tazhong Uplifts, which indicates a potential for further discoveries involving Cambrian and Lower Ordovician sourced oils in the Tarim Basin. Dinosteroids in petroleum and ancient sediments are generally thought to be biomarkers for dinoflagellates and 24-norcholestanes for dinoflagellates and diatoms. Therefore, the abnormally high abundance of these compounds in extracts from the organic-rich sediments in the Cambrian and Lower Ordovician and related oils in the cratonic region of the Tarim Basin suggests that phytoplankton algae related to dinoflagellates have appeared and might have flourished in the Tarim Basin during the Cambrian Period. Steroids with less common structural configurations are underutilized and can expand understanding of the early development history of organisms, as well as define petroleum systems.

The evolution of the Piedemonte Llanero petroleum system, Cordillera Oriental, Colombia (2) Reservoir petrography & petroleum geochemistry

DOE Office of Scientific and Technical Information (OSTI.GOV)

Piggott, N.; Vear, A.; Warren, E.A.

1996-08-01

Detailed quantification of cements and rock texture, fluid inclusion microthermometry, thermal maturity data, oil-source rock correlations and structural restorations have been integrated to reveal the porosity and hydrocarbon charge evolution of reservoirs in the Piedemonte Llanero thrustbelt of Colombia. Active exploration of deeply buried structures in different thrust sheets of the Piedemonte Llanero has encountered quartz arenites of widely varying average porosities (4-15%). Porosity has been reduced by mechanical compaction and quartz cementation during burial, and by pressure solution during structural deformation. The relative importance and timing of these processes varies between thrust sheets controlling the observed porosity variation. Thermalmore » maturity data indicate that all thrust sheets have been deeply buried and uplifted in several stages of compression. Detailed structural restorations indicate significant differences in the burial histories of individual thrust sheets. Oil-source rock correlations suggest two major hydrocarbon components in the thrustbelt: a Late Cretaceous oil-prone source and a Tertiary oil- and gas-prone source. Initial generation charged early structures leading to partial inhibition of quartz cementation. For most structures quartz cementation predated major hydrocarbon migration. Average quartz cementation temperature is uniform within a structure, but varies between thrust sheets. These variations appear to reflect differences in burial depths during quartz cementation rather than variations in timing. Integration of all data reveals a complex but predictable evolution of porosity and hydrocarbon charge in both space and time which is being applied to current exploration in the Piedemonte Llanero and is relevant to thrustbelt exploration elsewhere.« less

DOE Office of Scientific and Technical Information (OSTI.GOV)

Molina, J.

The Chipaque-Lower Carbonera({circ}) Petroleum System of the northernmost Llanos Basin of Colombia, covers 11,100 km{sup 2} and includes two major oil fields: Caho Limon in Colombia, and Guafita in Venezuela, jointly with three more relatively small fields in Colombia: Redondo, Cano Rondon, and Jiba. Ultimate recoverable reserves are in the order of 1.4 BBO. The sedimentary section penetrated in the Northern Llanos has been informally subdivided into four Cretaceous formations: K3, K2B, K2A, and Lower K1 deposited during the Albian-Senonian, and into four Tertiary formations: Lower Carbonera, Upper Carbonera, Leon, and Guayabo deposited during the Late Eocene to Pliocene time.more » The main reservoir is the Lower Carbonera Formation, which contains 81% of the total reserves. The Cretaceous K2A and Lower K1 reservoirs contain 6% and 8%, respectively of the reserves. Minor reserves are accumulated in the discontinuous sandstones of the Oligocene Upper Carbonera Formation Geochemical analyses of the Cano Limon/Guafita oils indicate that these are aromatic intermediate to paraffinic-naphthenic, non degradated, genetically related to a common marine-derived type of kerogen. These oils were generated by a mature, marine clastic source rock with a small contribution of continental organic matter. The geochemistry of the hydrocarbon suggest a genetic relationship with the shales of the Chipaque formation, basin-ward equivalent of the K2 Formation, which presents kerogen type II organic matter and has been recognized as a good source rock. The petroleum system is hypothetical because a definite oil-source rock correlation is lacking. The development of the petroleum system is directly related to the history of movement of the Santa Maria, La Yuca, Caho Limon, and Matanegra wrench faults. It has been determined that these faults of pre-Cretaceous rifting origin, created the Santa Maria Graben of which the Espino Graben is the continuation in Venezuela.« less

Undiscovered petroleum resources for the Woodford Shale and Thirteen Finger Limestone-Atoka Shale assessment units, Anadarko Basin

USGS Publications Warehouse

Higley, Debra K.

2011-01-01

In 2010 the U.S. Geological Survey assessed undiscovered oil and gas resources for the Anadarko Basin Province of Colorado, Kansas, Oklahoma, and Texas. The assessment included three continuous (unconventional) assessment units (AU). Mean undiscovered resources for the (1) Devonian Woodford Shale Gas AU are about 16 trillion cubic feet of gas (TCFG) and 192 million barrels of natural gas liquids (MMBNGL), (2) Woodford Shale Oil AU are 393 million barrels of oil (MMBO), 2 TCFG, and 59 MMBNGL, and (3) Pennsylvanian Thirteen Finger Limestone-Atoka Shale Gas AU are 6.8 TCFG and 82 MMBNGL. The continuous gas AUs are mature for gas generation within the deep basin of Oklahoma and Texas. Gas generation from the Woodford Shale source rock started about 335 Ma, and from the Thirteen Finger Limestone-Atoka Shale AU about 300 Ma. Maturation results are based on vitrinite reflectance data, and on 1D and 4D petroleum system models that calculated vitrinite reflectance (Ro), and Rock-Eval and hydrous pyrolysis transformation (HP) ratios through time for petroleum source rocks. The Woodford Shale Gas AU boundary and sweet spot were defined mainly on (1) isopach thickness from well-log analysis and published sources; (2) estimated ultimate recoverable production from existing, mainly horizontal, wells; and (3) levels of thermal maturation. Measured and modeled Ro ranges from about 1.2% to 5% in the AU, which represents marginally mature to overmature for gas generation. The sweet spot included most of the Woodford that was deposited within eroded channels in the unconformably underlying Hunton Group. The Thirteen Finger Limestone-Atoka Shale Gas AU has no known production in the deep basin. This AU boundary is based primarily on the gas generation window, and on thickness and distribution of organic-rich facies from these mainly thin shale and limestone beds. Estimates of organic richness were based on well-log signatures and published data.

Sembar Goru/Ghazij Composite Total Petroleum System, Indus and Sulaiman-Kirthar Geologic Provinces, Pakistan and India

USGS Publications Warehouse

Wandrey, C.J.; Law, B.E.; Shah, Haider Ali

2004-01-01

Geochemical analyses of rock samples and produced oil and gas in the Indus Basin have shown that the bulk of the hydrocarbons produced in the Indus Basin are derived from the Lower Cretaceous Sembar Formation and equivalent rocks. The source rocks of the Sembar are composed of shales that were deposited in shallow marine environments, are of mixed type-II and type-III kerogen, with total organic carbon (TOC) content ranging from less than 0.5 percent to more than 3.5 percent; the average TOC of the Sembar is about 1.4 percent. Vitrinite reflectance (Ro) values range from immature (1.35 percent Ro). Thermal generation of hydrocarbons in the Sembar Formation began 65 to 40 million years ago, (Mya) during Paleocene to Oligocene time. Hydrocarbon expulsion, migration, and entrapment are interpreted to have occurred mainly 50 to 15 Mya, during Eocene to Miocene time, prior to and contemporaneously with the development of structural traps in Upper Cretaceous and Tertiary reservoirs. The principal reservoirs in the Sembar-Goru/Ghazij Composite Total Petroleum System are Upper Cretaceous through Eocene sandstones and limestones.

South Sumatra Basin Province, Indonesia; the Lahat/Talang Akar-Cenozoic total petroleum system

USGS Publications Warehouse

Bishop, Michele G.

2000-01-01

Oil and gas are produced from the onshore South Sumatra Basin Province. The province consists of Tertiary half-graben basins infilled with carbonate and clastic sedimentary rocks unconformably overlying pre-Tertiary metamorphic and igneous rocks. Eocene through lower Oligocene lacustrine shales and Oligocene through lower Miocene lacustrine and deltaic coaly shales are the mature source rocks. Reserves of 4.3 billion barrels of oil equivalent have been discovered in reservoirs that range from pre-Tertiary basement through upper Miocene sandstones and carbonates deposited as synrift strata and as marine shoreline, deltaic-fluvial, and deep-water strata. Carbonate and sandstone reservoirs produce oil and gas primarily from anticlinal traps of Plio-Pleistocene age. Stratigraphic trapping and faulting are important locally. Production is compartmentalized due to numerous intraformational seals. The regional marine shale seal, deposited by a maximum sea level highstand in early middle Miocene time, was faulted during post-depositional folding allowing migration of hydrocarbons to reservoirs above the seal. The province contains the Lahat/Talang Akar-Cenozoic total petroleum system with one assessment unit, South Sumatra.

Evaluation of the rhenium-osmium geochronometer in the Phosphoria petroleum system, Bighorn Basin of Wyoming and Montana, USA

USGS Publications Warehouse

Lillis, Paul G.; Selby, David

2013-01-01

Rhenium-osmium (Re-Os) geochronometry is applied to crude oils derived from the Permian Phosphoria Formation of the Bighorn Basin in Wyoming and Montana to determine whether the radiogenic age reflects the timing of petroleum generation, timing of migration, age of the source rock, or the timing of thermochemical sulfate reduction (TSR). The oils selected for this study are interpreted to be derived from the Meade Peak Phosphatic Shale and Retort Phosphatic Shale Members of the Phosphoria Formation based on oil-oil and oil-source rock correlations utilizing bulk properties, elemental composition, δ13C and δ34S values, and biomarker distributions. The δ34S values of the oils range from -6.2‰ to +5.7‰, with oils heavier than -2‰ interpreted to be indicative of TSR. The Re and Os isotope data of the Phosphoria oils plot in two general trends: (1) the main trend (n = 15 oils) yielding a Triassic age (239 ± 43 Ma) with an initial 187Os/188Os value of 0.85 ± 0.42 and a mean square weighted deviation (MSWD) of 1596, and (2) the Torchlight trend (n = 4 oils) yielding a Miocene age (9.24 ± 0.39 Ma) with an initial 187Os/188Os value of 1.88 ± 0.01 and a MSWD of 0.05. The scatter (high MSWD) in the main-trend regression is due, in part, to TSR in reservoirs along the eastern margin of the basin. Excluding oils that have experienced TSR, the regression is significantly improved, yielding an age of 211 ± 21 Ma with a MSWD of 148. This revised age is consistent with some studies that have proposed Late Triassic as the beginning of Phosphoria oil generation and migration, and does not seem to reflect the source rock age (Permian) or the timing of re-migration (Late Cretaceous to Eocene) associated with the Laramide orogeny. The low precision of the revised regression (±21 Ma) is not unexpected for this oil family given the long duration of generation from a large geographic area of mature Phosphoria source rock, and the possible range in the initial 187Os/188Os values of the Meade Peak and Retort source units. Effects of re-migration may have contributed to the scatter, but thermal cracking and biodegradation likely have had minimal or no effect on the main-trend regression. The four Phosphoria-sourced oils from Torchlight and Lamb fields yield a precise Miocene age Re-Os isochron that may reflect the end of TSR in the reservoir due to cooling below a threshold temperature in the last 10 m.y. from uplift and erosion of overlying rocks. The mechanism for the formation of a Re-Os isotopic relationship in a family of crude oils may involve multiple steps in the petroleum generation process. Bitumen generation from the source rock kerogen may provide a reset of the isotopic chronometer, and incremental expulsion of oil over the duration of the oil window may provide some of the variation seen in 187Re/188Os values from an oil family.

Assessment of undiscovered conventional oil and gas resources of the Western Canada Sedimentary Basin, Canada, 2012

USGS Publications Warehouse

Higley, Debra K.

2013-01-01

The U.S. Geological Survey recently completed a geoscience-based assessment of undiscovered oil and gas resources of provinces within the Western Canada Sedimentary Basin. The Western Canada Sedimentary Basin primarily comprises the (1) Alberta Basin Province of Alberta, eastern British Columbia, and the southwestern Northwest Territories; (2) the Williston Basin Province of Saskatchewan, southeastern Alberta, and southern Manitoba; and (3) the Rocky Mountain Deformed Belt Province of western Alberta and eastern British Columbia. This report is part of the U.S. Geological Survey World Petroleum Resources Project assessment of priority geologic provinces of the world. The assessment was based on geoscience elements that define a total petroleum system (TPS) and associated assessment unit(s). These elements include petroleum source rocks (geochemical properties and petroleum generation, migration, and accumulation), reservoir description (reservoir presence, type, and quality), and petroleum traps (trap and seal types, and timing of trap and seal formation relative to petroleum migration). Using this framework, the Elk Point-Woodbend Composite TPS, Exshaw-Fernie-Mannville Composite TPS, and Middle through Upper Cretaceous Composite TPS were defined, and four conventional assessment units within the total petroleum systems were quantitatively assessed for undiscovered resources in the Western Canada Sedimentary Basin.

Geological evolution of the North Sea: a dynamic 3D model including petroleum system elements

NASA Astrophysics Data System (ADS)

Sabine, Heim; Rüdiger, Lutz; Dirk, Kaufmann; Lutz, Reinhardt

2013-04-01

This study investigates the sedimentary basin evolution of the German North Sea with a focus on petroleum generation, migration and accumulation. The study is conducted within the framework of the project "Geoscientific Potential of the German North Sea (GPDN)", a joint project of federal (BGR, BSH) and state authorities (LBEG) with partners from industry and scientific institutions. Based on the structural model of the "Geotektonischer Atlas 3D" (GTA3D, LBEG), this dynamic 3D model contains additionally the northwestern part ("Entenschnabel" area) of the German North Sea. Geological information, e.g. lithostratigraphy, facies and structural data, provided by industry, was taken from published research projects, or literature data such as the Southern Permian Basin Atlas (SPBA; Doornenbal et al., 2010). Numerical modeling was carried out for a sedimentary succession containing 17 stratigraphic layers and several sublayers, representing the sedimentary deposition from the Devonian until Present. Structural details have been considered in terms of simplified faults and salt structures, as well as main erosion and salt movement events. Lithology, facies and the boundary conditions e.g. heat flow, paleo water-depth and sediment water interface temperature were assigned. The system calibration is based on geochemical and petrological data, such as maturity of organic matter (VRr) and present day temperature. Due to the maturity of the sedimentary organic matter Carboniferous layers are the major source rocks for gas generation. Main reservoir rocks are the Rotliegend sandstones, furthermore, sandstones of the Lower Triassic and Jurassic can serve as reservoir rocks in areas where the Zechstein salts are absent. The model provides information on the temperature and maturity distribution within the main source rock layers as well as information of potential hydrocarbon generation based on kinetic data for gas liberation. Finally, this dynamic 3D model offers a first interpretation of the current data base and an estimation of the structural- and burial evolution of the German North Sea area, including information on the petroleum system elements. It includes information about possible migration pathways, oil and gas accumulations, as well as the type of generated hydrocarbons and non-hydrocarbons. References: Doornenbal, J.C. and Stevenson, A.G. (editors), 2010. Petroleum Geological Atlas of the Southern Permian Basin Area. EAGE Publications b.v. (Houten).

Thermogenic Wet Gas in Immature Caprock Sections: Leakage or Generation.

NASA Astrophysics Data System (ADS)

Abrakasa, Selegha; Beka, Francis; Ndukauba, Egesi

2017-04-01

Gas geochemistry, an aspect of Petroleum Geoscience is a growing science, various concepts has been used to evaluation potential source rock for shale gas while in conventional petroleum exploration similar concepts have been used to determine potential productive formation for liquid hydrocarbons. Prior to the present times, headspace gas data had been used to recognize by pass pays, serve as indicators of petroleum accumulations, evaluate maturity and productive capacity of corresponding formations, evaluate the maturity and source of gas accumulations. Integrating studies in bid to achieve high degree of accuracy, data on direct hydrocarbon indicators (DHIs) such as oil stains, oil shows and seeps have been employed. Currently popular among professionals is the use of gas clouds on seismic cross sections. In contemporary times, advancement in gas geochemistry has witnessed the application of concepts on headspace gas to expound the efficiency of petroleum caprocks whose major role is to foster accumulation and preservation. This enables extricating potential leakage mechanism via caprock reservoir interface and unravel its corresponding migrational pathways. In this study thermogenic wet gas has been used as a dependable tool for delineating caprock leakage by discriminating migrant from indigenous hydrocarbons in caprock rock sections overlying the reservoirs. The thermogenic gas profile in corroboration with the thermogenic signature and maturity data were used. Summary statistics indicates that 60% of the 50 wells studied has wet gas up to 500m above the reservoir-caprock interface and 10% of the leaking wells are fracture prone leakage.The amount of wet gas ranges of up to 200,000 ppm in the caprock sections, this indicates pervasive leakage. Log view plots were modelled using Schlumbergers' Techlog, while descriptive lithologies were modeled using Zetawares' genesis.

Geologic cross section C-C' through the Appalachian basin from Erie County, north-central Ohio, to the Valley and Ridge province, Bedford County, south-central Pennsylvania

USGS Publications Warehouse

Ryder, Robert T.; Trippi, Michael H.; Swezey, Christopher S.; Crangle, Robert D.; Hope, Rebecca S.; Rowan, Elisabeth L.; Lentz, Erika E.

2012-01-01

Geologic cross section C-C' is the third in a series of cross sections constructed by the U.S. Geological Survey (USGS) to document and improve understanding of the geologic framework and petroleum systems of the Appalachian basin. Cross section C-C' provides a regional view of the structural and stratigraphic framework of the Appalachian basin from north-central Ohio to the Valley and Ridge province in south-central Pennsylvania, a distance of approximately 260 miles (mi). This cross section is a companion to cross sections E-E' and D-D' that are located about 50 to 125 mi and 25 to 50 mi, respectively, to the southwest. Cross section C-C' contains much information that is useful for evaluating energy resources in the Appalachian basin. Although specific petroleum systems are not identified on the cross section, many of their key elements (such as source rocks, reservoir rocks, seals, and traps) can be inferred from lithologic units, unconformities, and geologic structures shown on the cross section. Other aspects of petroleum systems (such as the timing of petroleum generation and preferred migration pathways) may be evaluated by burial history, thermal history, and fluid flow models based on what is shown on the cross section. Cross section C-C' also provides a general framework (stratigraphic units and general rock types) for the coal-bearing section, although the cross section lacks the detail to illustrate key elements of coal systems (such as paleoclimate, coal quality, and coal rank). In addition, cross section C-C' may be used as a reconnaissance tool to identify plausible geologic structures and strata for the subsurface storage of liquid waste or for the sequestration of carbon dioxide.

Geology, sequence stratigraphy, and oil and gas assessment of the Lewis Shale Total Petroleum System, San Juan Basin, New Mexico and Colorado: Chapter 5 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

USGS Publications Warehouse

Dubiel, R.F.

2013-01-01

The Lewis Shale Total Petroleum System (TPS) in the San Juan Basin Province contains a continuous gas accumulation in three distinct stratigraphic units deposited in genetically related depositional environments: offshore-marine shales, mudstones, siltstones, and sandstones of the Lewis Shale, and marginal-marine shoreface sandstones and siltstones of both the La Ventana Tongue and the Chacra Tongue of the Cliff House Sandstone. The Lewis Shale was not a completion target in the San Juan Basin (SJB) in early drilling from about the 1950s through 1990. During that time, only 16 wells were completed in the Lewis from natural fracture systems encountered while drilling for deeper reservoir objectives. In 1991, existing wells that penetrated the Lewis Shale were re-entered by petroleum industry operators in order to fracture-stimulate the Lewis and to add Lewis gas production onto preexisting, and presumably often declining, Mesaverde Group production stratigraphically lower in the section. By 1997, approximately 101 Lewis completions had been made, both as re-entries into existing wells and as add-ons to Mesaverde production in new wells. Based on recent industry drilling and completion practices leading to successful gas production from the Lewis and because new geologic models indicate that the Lewis Shale contains both source rocks and reservoir rocks, the Lewis Shale TPS was defined and evaluated as part of this U.S. Geological Survey oil and gas assessment of the San Juan Basin. Gas in the Lewis Shale Total Petroleum System is produced from shoreface sandstones and siltstones in the La Ventana and Chacra Tongues and from distal facies of these prograding clastic units that extend into marine rocks of the Lewis Shale in the central part of the San Juan Basin. Reservoirs are in shoreface sandstone parasequences of the La Ventana and Chacra and their correlative distal parasequences in the Lewis Shale where both natural and artificially enhanced fractures produce gas. The Lewis Continuous Gas Assessment Unit (AU 50220261) is thought to be self-sourced from and self-sealed by marine shales and mudstones deposited within the Lewis Shale that enclose clastic parasequences in the La Ventana and Chacra Tongues. The gas resource is thought to be a continuous accumulation sourced from the Lewis Shale throughout the depositional basin. In the Lewis Continuous Gas Assessment Unit (AU 50220261), for continuous gas resources, there is an F95 of 8,315.22 billion cubic feet of gas (BCFG) and an F5 of 12,282.31 BCFG, with a mean value of 10,177.24 BCFG. There is an F95 of 18.08 million barrels of natural gas liquids (MMBNGL) and an F5 of 47.32 MMBNGL, with a mean of 30.53 MMBNGL.

Petroleum system of Northwest Java basin based on gravity data analysis

NASA Astrophysics Data System (ADS)

Widianto, E.

2018-01-01

Energy management in the upstream oil and gas sector becomes very important for the country’s energy security. The renewal of energy resources and reserves becomes necessary and is a must. In the oil and gas industry, gravity data is usually used only for regional surveys, but with the development of instrumentation technology and gravity software development, this method can be used for assessing oil and gas survey stages from exploration to production. This study was conducted to evaluate aspects of petroleum system and exploration play concept in the part of Northwest Java Basin, covering source rock deposition regions (source kitchen area, migration direction), development of reservoirs, structural and stratigraphic trap, based on gravity data. This study uses data from Bouguer gravity anomaly map by filtering process to produce a residual map depicting sedimentation basin configuration. The mapping generated 20 sedimentary basins in Java Island with the total hydrocarbon resources of 113 BBOE (Billion Barrel of Oil Equivalent). The petroleum system analysis was conducted in the Northwest Basin section. The final map produced illustrates the condition of petroleum system and play concept that can be used as exploration direction, expectedly reducing the risk of drilling failure.

Appalachian basin oil and natural gas: stratigraphic framework, total petroleum systems, and estimated ultimate recovery: Chapter C.1 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Ryder, Robert T.; Milici, Robert C.; Swezey, Christopher S.; Trippi, Michael H.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

The most recent U.S. Geological Survey (USGS) assessment of undiscovered oil and gas resources of the Appalachian basin was completed in 2002 (Milici and others, 2003). This assessment was based on the total petroleum system (TPS), a concept introduced by Magoon and Dow (1994) and developed during subsequent studies such as those by the U.S. Geological Survey World Energy Assessment Team (2000) and by Biteau and others (2003a,b). Each TPS is based on specific geologic elements that include source rocks, traps and seals, reservoir rocks, and the generation and migration of hydrocarbons. This chapter identifies the TPSs defined in the 2002 Appalachian basin oil and gas assessment and places them in the context of the stratigraphic framework associated with regional geologic cross sections D–D′ (Ryder and others, 2009, which was re-released in this volume, chap. E.4.1) and E–E′ (Ryder and others, 2008, which was re-released in this volume, chap. E.4.2). Furthermore, the chapter presents a recent estimate of the ultimate recoverable oil and natural gas in the basin.

Assessment of undiscovered oil and gas resources of the Williston Basin Province of North Dakota, Montana, and South Dakota, 2010

USGS Publications Warehouse

,

2011-01-01

Using a geology-based assessment method, the U.S. Geological Survey estimated mean undiscovered volumes of 3.8 billion barrels of undiscovered oil, 3.7 trillion cubic feet of associated/dissolved natural gas, and 0.2 billion barrels of undiscovered natural gas liquids in the Williston Basin Province, North Dakota, Montana, and South Dakota. The U.S. Geological Survey (USGS) recently completed a comprehensive oil and gas assessment of the Williston Basin, which encompasses more than 90 million acres in parts of North Dakota, eastern Montana, and northern South Dakota. The assessment is based on the geologic elements of each total petroleum system (TPS) defined in the province, including hydrocarbon source rocks (source-rock maturation, hydrocarbon generation, and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined 11 TPS and 19 Assessment Units (AU).

Assessment of undiscovered conventionally recoverable petroleum resources of the Northwest European region

USGS Publications Warehouse

Masters, Charles D.; Klemme, H. Douglas

1984-01-01

The estimates of undiscovered conventionally recoverable petroleum resources in the northwest European region at probability levels of 95 percent, 5 percent, statistical mean, and mode are for oil (in billions of barrels): 9, 34, 20, and 15; and for gas (in trillions of cubic feet): 92, 258, 167, and 162. The occurrence of petroleum can be accounted for in two distinct geological plays located in the various subbasins of the region. Play I is associated with the distribution of mature source rocks of Late Jurassic age relative to four distinct trapping conditions. The play has been demonstrated productive mostly in the Viking and Central Grabens of the North Sea, where the shale has been buried to optimum depths for the generation of both oil and gas. To the north of 62 ? N. latitude up to the Barents Sea, source rocks become increasingly deeply buried and are interpreted to be dominantly gas prone; a narrow band of potentially oil-prone shales tracks most of the coast of Norway, but water depths in favorable localities commonly range from 600 to 1,200 feet. To the south of the Central Graben, the Jurassic source rocks are either immature or minimally productive because of a change in facies. Undrilled traps remain within the favorable source-rock area, and exploration will continue to challenge the boundaries of conventional wisdom, especially on the Norwegian side where little has .been reported on the geology of the adjoining Bergen High or Horda Basin, though, reportedly, the Jurassic source rocks are missing on the high and are immature in the southern part of the basin. Play II is associated with the distribution of a coal facies of Carboniferous age that is mature for the generation of gas and locally underlies favorable reservoir and sealing rocks. The play is limited largely by facies development to the present area of discovery and production but is limited as well to the southeast into onshore Netherlands and Germany by the unfavorable economics of an increasing nitrogen content in the gas. This increase is apparently caused by excessive temperatures associated with increasing depth of burial of the source rock. The history of discovery in the North Sea would appear to deny the commonly held maxim that large fields are found first and early in the exploration process. However, if the discovery data are examined from the perspective of the award date of each exploration license, then it is clear that the largest fields and most of the reserves have indeed been found early in the exploration process of a particular license. Discoveries made within 1 year of granting the license are on average large giants, and they account for slightly less than two-thirds of the original reserves. Discoveries made within 2 to 5 years of the granting of the license are on average less than giant size and smaller than increment-l-year discoveries by a factor of 4; these fields account for a little less than one-third of the reserves. Those fields found 6 or more years after the granting of the license are relatively small and account for 20 percent of all discoveries but only 4 percent of total original reserves. These data suggest that a measure of an area's exploration maturity is the length of time elapsed since the award of the concession.

Modified method for estimating petroleum source-rock potential using wireline logs, with application to the Kingak Shale, Alaska North Slope

USGS Publications Warehouse

Rouse, William A.; Houseknecht, David W.

2016-02-11

In 2012, the U.S. Geological Survey completed an assessment of undiscovered, technically recoverable oil and gas resources in three source rocks of the Alaska North Slope, including the lower part of the Jurassic to Lower Cretaceous Kingak Shale. In order to identify organic shale potential in the absence of a robust geochemical dataset from the lower Kingak Shale, we introduce two quantitative parameters, $\\Delta DT_\\bar{x}$ and $\\Delta DT_z$, estimated from wireline logs from exploration wells and based in part on the commonly used delta-log resistivity ($\\Delta \\text{ }log\\text{ }R$) technique. Calculation of $\\Delta DT_\\bar{x}$ and $\\Delta DT_z$ is intended to produce objective parameters that may be proportional to the quality and volume, respectively, of potential source rocks penetrated by a well and can be used as mapping parameters to convey the spatial distribution of source-rock potential. Both the $\\Delta DT_\\bar{x}$ and $\\Delta DT_z$ mapping parameters show increased source-rock potential from north to south across the North Slope, with the largest values at the toe of clinoforms in the lower Kingak Shale. Because thermal maturity is not considered in the calculation of $\\Delta DT_\\bar{x}$ or $\\Delta DT_z$, total organic carbon values for individual wells cannot be calculated on the basis of $\\Delta DT_\\bar{x}$ or $\\Delta DT_z$ alone. Therefore, the $\\Delta DT_\\bar{x}$ and $\\Delta DT_z$ mapping parameters should be viewed as first-step reconnaissance tools for identifying source-rock potential.

Petroleum systems of the Southeast Tertiary basins and Marbella area, Southeast Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Fuentes, F.

1996-08-01

This study was done in an area where insufficient organic-rich rocks were available for a reliable oil-source rock correlation. However, oil-rock correlations, molecular characteristics of key horizons, paleofacies maps, maturation and potential migration pathways suggest the Tithonian as a major source rock. Moreover, there is good evidence of high quality source rocks in Oxfordian, Kimmeridgian, Middle-Upper Cretaceous and Paleogene (mainly in the Eocene). Plays were identified in Upper Jurassic oolitic sequences, Early-Middle Cretaceus carbonate platform rocks and breccias, Late Cretaceous basinal fracture carbonates, Paleogene carbonates and breccias, Early-Middle Miocene mounds and submarine fans and isolated carbonate platform sediments and Miocene-Recentmore » turbidites. Seal rocks are shaly carbonates and anhydrites from Tithonian, basinal carbonates and anhydrites from Middle-Upper Cretaceous, basinal carbonates and marls from Upper Cretaceous and Paleogene shales, and bathyal shales from Early Miocene-Recent. The first phase of oil migration from upper Jurassic-Early Cretaceous source rocks occurred in the Early-Middle Cretaceous. In the Upper Cretaceous the Chortis block collided with Chiapas, and as a result mild folding and some hydrocarbons were emplaced to the structural highs. The main phase of structuration and folding of the Sierra de Chiapas started in the Miocene, resulting in well-defined structural traps. Finally, in Plio-Pleistocene the Chortis block was separated, the major compressional period finished and the southern portion of Sierra de Chiapas was raised isostatically. As a result of major subsidence, salt withdrawal and increased burial depth, conditions were created for the generation of liquid hydrocarbons from the Paleogene shales.« less

Neoproterozoic rift basins and their control on the development of hydrocarbon source rocks in the Tarim Basin, NW China

NASA Astrophysics Data System (ADS)

Zhu, Guang-You; Ren, Rong; Chen, Fei-Ran; Li, Ting-Ting; Chen, Yong-Quan

2017-12-01

The Proterozoic is demonstrated to be an important period for global petroleum systems. Few exploration breakthroughs, however, have been obtained on the system in the Tarim Basin, NW China. Outcrop, drilling, and seismic data are integrated in this paper to focus on the Neoproterozoic rift basins and related hydrocarbon source rocks in the Tarim Basin. The basin consists of Cryogenian to Ediacaran rifts showing a distribution of N-S differentiation. Compared to the Cryogenian basins, those of the Ediacaran are characterized by deposits in small thickness and wide distribution. Thus, the rifts have a typical dual structure, namely the Cryogenian rifting and Ediacaran depression phases that reveal distinct structural and sedimentary characteristics. The Cryogenian rifting basins are dominated by a series of grabens or half grabens, which have a wedge-shaped rapid filling structure. The basins evolved into Ediacaran depression when the rifting and magmatic activities diminished, and extensive overlapping sedimentation occurred. The distributions of the source rocks are controlled by the Neoproterozoic rifts as follows. The present outcrops lie mostly at the margins of the Cryogenian rifting basins where the rapid deposition dominates and the argillaceous rocks have low total organic carbon (TOC) contents; however, the source rocks with high TOC contents should develop in the center of the basins. The Ediacaran source rocks formed in deep water environment of the stable depressions evolving from the previous rifting basins, and are thus more widespread in the Tarim Basin. The confirmation of the Cryogenian to Ediacaran source rocks would open up a new field for the deep hydrocarbon exploration in the Tarim Basin.

Source rock potential of middle cretaceous rocks in Southwestern Montana

USGS Publications Warehouse

Dyman, T.S.; Palacas, J.G.; Tysdal, R.G.; Perry, W.J.; Pawlewicz, M.J.

1996-01-01

The middle Cretaceous in southwestern Montana is composed of a marine and nonmarine succession of predominantly clastic rocks that were deposited along the western margin of the Western Interior Seaway. In places, middle Cretaceous rocks contain appreciable total organic carbon (TOC), such as 5.59% for the Mowry Shale and 8.11% for the Frontier Formation in the Madison Range. Most samples, however, exhibit less than 1.0% TOC. The genetic or hydrocarbon potential (S1+S2) of all the samples analyzed, except one, yield less than 1 mg HC/g rock, strongly indicating poor potential for generating commercial amounts of hydrocarbons. Out of 51 samples analyzed, only one (a Thermopolis Shale sample from the Snowcrest Range) showed a moderate petroleum potential of 3.1 mg HC/g rock. Most of the middle Cretaceous samples are thermally immature to marginally mature, with vitrinite reflectance ranging from about 0.4 to 0.6% Ro. Maturity is high in the Pioneer Mountains, where vitrinite reflectance averages 3.4% Ro, and at Big Sky Montana, where vitrinite reflectance averages 2.5% Ro. At both localities, high Ro values are due to local heat sources, such as the Pioneer batholith in the Pioneer Mountains.

Discovery and identification of a series of alkyl decalin isomers in petroleum geological samples.

PubMed

Wang, Huitong; Zhang, Shuichang; Weng, Na; Zhang, Bin; Zhu, Guangyou; Liu, Lingyan

2015-07-07

The comprehensive two-dimensional gas chromatography/time-of-flight mass spectrometry (GC × GC/TOFMS) has been used to characterize a crude oil and a source rock extract sample. During the process, a series of pairwise components between monocyclic alkanes and mono-aromatics have been discovered. After tentative assignments of decahydronaphthalene isomers, a series of alkyl decalin isomers have been synthesized and used for identification and validation of these petroleum compounds. From both the MS and chromatography information, these pairwise compounds were identified as 2-alkyl-decahydronaphthalenes and 1-alkyl-decahydronaphthalenes. The polarity of 1-alkyl-decahydronaphthalenes was stronger. Their long chain alkyl substituent groups may be due to bacterial transformation or different oil cracking events. This systematic profiling of alkyl-decahydronaphthalene isomers provides further understanding and recognition of these potential petroleum biomarkers.

U.S. Geological Survey Assessment of Undiscovered Petroleum Resources of the Hamra Basin, Libya, 2006

USGS Publications Warehouse

,

2007-01-01

The Hamra Basin Province encompasses approximately 244,100 square kilometers (94,250 square miles) and is entirely within Libya. One composite total petroleum system (TPS) was defined for this assessment; it extends from Libya westward into adjacent parts of Algeria and southern Tunisia. The Hamra Basin part of the TPS was subdivided into four assessment units for the purpose of resource assessment. The assessment units cover only 172,390 square kilometers of the Hamra Basin Province; the remaining area has little potential for undiscovered petroleum resources because of the absence of petroleum source rocks. Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean volumes of 784 million barrels of crude oil, 4,748 billion cubic feet of natural gas, and 381 million barrels of natural gas liquids in the Hamra Basin of northwestern Libya. Most of the undiscovered crude oil and natural gas are interpreted to be in deeper parts of the Hamra Basin.

Chemometric differentiation of crude oil families in the San Joaquin Basin, California

USGS Publications Warehouse

Peters, Kenneth E.; Coutrot, Delphine; Nouvelle, Xavier; Ramos, L. Scott; Rohrback, Brian G.; Magoon, Leslie B.; Zumberge, John E.

2013-01-01

Chemometric analyses of geochemical data for 165 crude oil samples from the San Joaquin Basin identify genetically distinct oil families and their inferred source rocks and provide insight into migration pathways, reservoir compartments, and filling histories. In the first part of the study, 17 source-related biomarker and stable carbon-isotope ratios were evaluated using a chemometric decision tree (CDT) to identify families. In the second part, ascendant hierarchical clustering was applied to terpane mass chromatograms for the samples to compare with the CDT results. The results from the two methods are remarkably similar despite differing data input and assumptions. Recognized source rocks for the oil families include the (1) Eocene Kreyenhagen Formation, (2) Eocene Tumey Formation, (3–4) upper and lower parts of the Miocene Monterey Formation (Buttonwillow depocenter), and (5–6) upper and lower parts of the Miocene Monterey Formation (Tejon depocenter). Ascendant hierarchical clustering identifies 22 oil families in the basin as corroborated by independent data, such as carbon-isotope ratios, sample location, reservoir unit, and thermal maturity maps from a three-dimensional basin and petroleum system model. Five families originated from the Eocene Kreyenhagen Formation source rock, and three families came from the overlying Eocene Tumey Formation. Fourteen families migrated from the upper and lower parts of the Miocene Monterey Formation source rocks within the Buttonwillow and Tejon depocenters north and south of the Bakersfield arch. The Eocene and Miocene families show little cross-stratigraphic migration because of seals within and between the source rocks. The data do not exclude the possibility that some families described as originating from the Monterey Formation actually came from source rock in the Temblor Formation.

A total petroleum system of the Browse Basin, Australia; Late Jurassic, Early Cretaceous-Mesozoic

USGS Publications Warehouse

Bishop, M.G.

1999-01-01

The Browse Basin Province 3913, offshore northern Australia, contains one important petroleum system, Late Jurassic, Early Cretaceous-Mesozoic. It is comprised of Late Jurassic through Early Cretaceous source rocks deposited in restricted marine environments and various Mesozoic reservoir rocks deposited in deep-water fan to fluvial settings. Jurassic age intraformational shales and claystones and Cretaceous regional claystones seal the reservoirs. Since 1967, when exploration began in this 105,000 km2 area, fewer than 40 wells have been drilled and only one recent oil discovery is considered potentially commercial. Prior to the most recent oil discovery, on the eastern side of the basin, a giant gas field was discovered in 1971, under a modern reef on the west side of the basin. Several additional oil and gas discoveries and shows were made elsewhere. A portion of the Vulcan sub-basin lies within Province 3913 where a small field, confirmed in 1987, produced 18.8 million barrels of oil (MMBO) up to 1995 and has since been shut in.

The Timan-Pechora Basin province of northwest Arctic Russia; Domanik, Paleozoic total petroleum system

USGS Publications Warehouse

Lindquist, Sandra J.

1999-01-01

The Domanik-Paleozoic oil-prone total petroleum system covers most of the Timan-Pechora Basin Province of northwestern Arctic Russia. It contains nearly 20 BBOE ultimate recoverable reserves (66% oil). West of the province is the early Precambrian Eastern European craton margin. The province itself was the site of periodic Paleozoic tectonic events, culminating with the Hercynian Uralian orogeny along its eastern border. The stratigraphic record is dominated by Paleozoic platform and shelf-edge carbonates succeeded by Upper Permian to Triassic molasse siliciclastics that are locally present in depressions. Upper Devonian (Frasnian), deep marine shale and limestone source rocks ? with typically 5 wt % total organic carbon ? by middle Mesozoic time had generated hydrocarbons that migrated into reservoirs ranging in age from Ordovician to Triassic but most focused in Devonian and Permian rocks. Carboniferous structural inversions of old aulacogen borders, and Hercynian (Permian) to Early Cimmerian (Late Triassic to Early Jurassic) orogenic compression not only impacted depositional patterns, but also created and subsequently modified numerous structural traps within the province.

Petroleum geology and resources of the Dnieper-Donets Basin, Ukraine and Russia

USGS Publications Warehouse

Ulmishek, Gregory F.

2001-01-01

The Dnieper-Donets basin is almost entirely in Ukraine, and it is the principal producer of hydrocarbons in that country. A small southeastern part of the basin is in Russia. The basin is bounded by the Voronezh high of the Russian craton to the northeast and by the Ukrainian shield to the southwest. The basin is principally a Late Devonian rift that is overlain by a Carboniferous to Early Permian postrift sag. The Devonian rift structure extends northwestward into the Pripyat basin of Belarus; the two basins are separated by the Bragin-Loev uplift, which is a Devonian volcanic center. Southeastward, the Dnieper-Donets basin has a gradational boundary with the Donbas foldbelt, which is a structurally inverted and deformed part of the basin. The sedimentary succession of the basin consists of four tectono-stratigraphic sequences. The prerift platform sequence includes Middle Devonian to lower Frasnian, mainly clastic, rocks that were deposited in an extensive intracratonic basin. 1 The Upper Devonian synrift sequence probably is as thick as 4?5 kilometers. It is composed of marine carbonate, clastic, and volcanic rocks and two salt formations, of Frasnian and Famennian age, that are deformed into salt domes and plugs. The postrift sag sequence consists of Carboniferous and Lower Permian clastic marine and alluvial deltaic rocks that are as thick as 11 kilometers in the southeastern part of the basin. The Lower Permian interval includes a salt formation that is an important regional seal for oil and gas fields. The basin was affected by strong compression in Artinskian (Early Permian) time, when southeastern basin areas were uplifted and deeply eroded and the Donbas foldbelt was formed. The postrift platform sequence includes Triassic through Tertiary rocks that were deposited in a shallow platform depression that extended far beyond the Dnieper-Donets basin boundaries. A single total petroleum system encompassing the entire sedimentary succession is identified in the Dnieper-Donets basin. Discovered reserves of the system are 1.6 billion barrels of oil and 59 trillion cubic feet of gas. More than one-half of the reserves are in Lower Permian rocks below the salt seal. Most of remaining reserves are in upper Visean-Serpukhovian (Lower Carboniferous) strata. The majority of discovered fields are in salt-cored anticlines or in drapes over Devonian horst blocks; little exploration has been conducted for stratigraphic traps. Synrift Upper Devonian carbonate reservoirs are almost unexplored. Two identified source-rock intervals are the black anoxic shales and carbonates in the lower Visean and Devonian sections. However, additional source rocks possibly are present in the deep central area of the basin. The role of Carboniferous coals as a source rock for gas is uncertain; no coal-related gas has been identified by the limited geochemical studies. The source rocks are in the gas-generation window over most of the basin area; consequently gas dominates over oil in the reserves. Three assessment units were identified in the Dnieper-Donets Paleozoic total petroleum system. The assessment unit that contains all discovered reserves embraces postrift Carboniferous and younger rocks. This unit also contains the largest portion of undiscovered resources, especially gas. Stratigraphic and combination structural and stratigraphic traps probably will be the prime targets for future exploration. The second assessment unit includes poorly known synrift Devonian rocks. Carbonate reef reservoirs along the basin margins probably will contain most of the undiscovered resources. The third assessment unit is an unconventional, continuous, basin-centered gas accumulation in Carboniferous low-permeability clastic rocks. The entire extent of this accumulation is unknown, but it occupies much of the basin area. Resources of this assessment unit were not estimated quantitatively.

Near-Infrared Imaging for Spatial Mapping of Organic Content in Petroleum Source Rocks

NASA Astrophysics Data System (ADS)

Mehmani, Y.; Burnham, A. K.; Vanden Berg, M. D.; Tchelepi, H.

2017-12-01

Natural gas from unconventional petroleum source rocks (shales) plays a key role in our transition towards sustainable low-carbon energy production. The potential for carbon storage (in adsorbed state) in these formations further aligns with efforts to mitigate climate change. Optimizing production and development from these resources requires knowledge of the hydro-thermo-mechanical properties of the rock, which are often strong functions of organic content. This work demonstrates the potential of near-infrared (NIR) spectral imaging in mapping the spatial distribution of organic content with O(100µm) resolution on cores that can span several hundred feet in depth (Mehmani et al., 2017). We validate our approach for the immature oil shale of the Green River Formation (GRF), USA, and show its applicability potential in other formations. The method is a generalization of a previously developed optical approach specialized to the GRF (Mehmani et al., 2016a). The implications of this work for spatial mapping of hydro-thermo-mechanical properties of excavated cores, in particular thermal conductivity, are discussed (Mehmani et al., 2016b). References:Mehmani, Y., A.K. Burnham, M.D. Vanden Berg, H. Tchelepi, "Quantification of organic content in shales via near-infrared imaging: Green River Formation." Fuel, (2017). Mehmani, Y., A.K. Burnham, M.D. Vanden Berg, F. Gelin, and H. Tchelepi. "Quantification of kerogen content in organic-rich shales from optical photographs." Fuel, (2016a). Mehmani, Y., A.K. Burnham, H. Tchelepi, "From optics to upscaled thermal conductivity: Green River oil shale." Fuel, (2016b).

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

USGS Publications Warehouse

Stanley, Richard G.; Herriott, Trystan M.; LePain, David L.; Helmold, Kenneth P.; Peterson, C. Shaun

2013-01-01

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

Reconstruction of paleoceanographic significance in the Atlantic, Pacific, and the Indian Ocean during the Neogene based on calcareous nannofossil productivity and coccolith size distribution of Reticulofenestra - with special reference to formation of petroleum source rocks

NASA Astrophysics Data System (ADS)

Pratiwi, S. D.; Sato, T.; Ovinda, O.; Syavitri, D.

2017-12-01

We studied in detail the calcareous nannofossils assemblages from the ODP Sites of the western Pacific, Bahama Bank of Caribbean Sea, northwestern Pacific, Equatorial Pacific and the Indian Ocean to reconstruct the Cenozoic paleoceanographic evolution and correlate with the global events. The absolute abundant of coccolith (number/g) is gradually increased from NN6 throughout NN19 Zone, while the relative abundance of Discoaster is decreased in the Pacific Ocean. The size of Reticulofenestra increased five times throughout the section. However, it drastically decreased in NN8-10 (8.80 Ma), NN12-13 (5.40 Ma), NN14-NN15 (3.75 Ma), NN17/NN18 (2.52 Ma) and in NN19 Zone (0.80 Ma) in the western Pacific site. The characteristic of eutrophication condition determined by the high productivity of coccolith and the drastic decrease of the maximum size of Reticulofenestra are strongly related to the appearance of nutricline in the sea surface ocean. On the basis of the relationship between the changes of maximum sizes of Reticulofenestra and nutrient condition, these eutrophication events are clearly traceable in the western Pacific, Bahama Bank of Caribbean Sea, northwestern Pacific, Equatorial Pacific and the Indian Ocean. Two paleoceanographic events found in 8.80 Ma and 3.75 Ma are interpreted as a change to high nutrient condition resulted in the intensification of Asian Monsoon and closure of Panama Isthmus (Fig.). The upwelling of nutrient-rich oceanic waters may give rise to exceptionally high organic productivity. Organic carbon- rich facies accumulate preferentially during major intensification episodes. The timing of high productivity of coccolith during the middle to late Miocene is related and applicable to the formation of petroleum source rock and traceable to the Japan, marginal eastern North Pacific and California oil sites. This study suggests that the timing of the collapse of sea surface condition or eutrophication condition (8.00 Ma to 10.00 Ma) is correlated to the timing of formation petroleum source rocks in Circum Pacific based on calcareous nannofossils study.

Engaging a Diverse Group of Students with a Broad Spectrum of Geological Experience: The CSUN Catalyst Approach and a MARGINS Application

NASA Astrophysics Data System (ADS)

Marsaglia, K. M.; Vazquez, J.; Yule, J. D.; Simila, G.

2007-12-01

Imagine the challenge of teaching a one-unit Geoscience course composed of a diverse mix of first-year graduate majors, senior to freshman majors, and high school students with little earth science background. With the help of Geodiversity grants from NSF (CSUN Catalyst program), we have developed a successful environment for learning and mentorship via a series of short (2-3 week) inquiry-based exercises that emphasize teamwork. Each exercise is organized around research projects headed by Catalyst Faculty members: Northridge Earthquake, San Andreas Fault System, Yellowstone and Long Valley supervolcanoes, and New Zealand MARGIN geology. After participating in the course, students conduct independent research within one of four research groups as part of their MS or BS theses including summer research experiences. One exercise, constructed as a version of "The Oil Game," is meant to familiarize students with MARGINS Source-to-Sink focus (Waipaoa Sedimentary System, North Island) and alternate focus (Bounty Fan, South Island) sites in New Zealand. Students are divided into rival petroleum companies (Tiger Oil and Flower Petroleum) and asked to evaluate offshore areas for an impending government lease sale and to provide the rationale for competitive sealed bids that they recommend in a final presentation to management (Catalyst Faculty). To accomplish this they are supplied with reference materials on onshore geology and known petroleum production, samples of New Zealand rock units and stream sediments, and a limited budget. In addition to geological parameters (source rocks, seals, reservoir rocks, trapping mechanisms) they must also take into account environmental, economic and infrastructure concerns. Other projects included documenting volcanic hazards around Long Valley caldera and evaluating seismic hazards of local high school sites. The tiered structure of the projects perhaps best serves the undergraduate participants, who benefit from being mentored by graduate students as well as serving as mentors for the high school students.

Regional Fluid Flow and Basin Modeling in Northern Alaska

USGS Publications Warehouse

Kelley, Karen D.

2007-01-01

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

The origin of high hydrocarbon groundwater in shallow Triassic aquifer in Northwest Guizhou, China.

PubMed

Liu, Shan; Qi, Shihua; Luo, Zhaohui; Liu, Fangzhi; Ding, Yang; Huang, Huanfang; Chen, Zhihua; Cheng, Shenggao

2018-02-01

Original high hydrocarbon groundwater represents a kind of groundwater in which hydrocarbon concentration exceeds 0.05 mg/L. The original high hydrocarbon will significantly reduce the environment capacity of hydrocarbon and lead environmental problems. For the past 5 years, we have carried out for a long-term monitoring of groundwater in shallow Triassic aquifer in Northwest Guizhou, China. We found the concentration of petroleum hydrocarbon was always above 0.05 mg/L. The low-level anthropogenic contamination cannot produce high hydrocarbon groundwater in the area. By using hydrocarbon potential, geochemistry and biomarker characteristic in rocks and shallow groundwater, we carried out a comprehensive study in Dalongjing (DLJ) groundwater system to determine the hydrocarbon source. We found a simplex hydrogeology setting, high-level water-rock-hydrocarbon interaction and obviously original hydrocarbon groundwater in DLJ system. The concentration of petroleum hydrocarbon in shallow aquifer was found to increase with the strong water-rock interaction. Higher hydrocarbon potential was found in the upper of Guanling formation (T 2 g 3 ) and upper of Yongningzhen formation (T 1 yn 4 ). Heavily saturated carbon was observed from shallow groundwater, which presented similar distribution to those from rocks, especially from the deeper groundwater. These results indicated that the high concentrations of original hydrocarbon in groundwater could be due to the hydrocarbon release from corrosion and extraction out of strata over time.

Experiments on the role of water in petroleum formation

NASA Astrophysics Data System (ADS)

Lewan, M. D.

1997-09-01

Pyrolysis experiments were conducted on immature petroleum source rocks under various conditions to evaluate the role of water in petroleum formation. At temperatures less than 330°C for 72 h, the thermal decomposition of kerogen to bitumen was not significantly affected by the presence or absence of liquid water in contact with heated gravel-sized source rock. However, at 330 and 350°C for 72 h, the thermal decomposition of generated bitumen was significantly affected by the presence or absence of liquid water. Carbon-carbon bond cross linking resulting in the formation of an insoluble bitumen (i.e., pyrobitumen) is the dominant reaction pathway in the absence of liquid water. Conversely, thermal cracking of carbon-carbon bonds resulting in the generation of saturate-enriched oil, which is similar to natural crude oils, is the dominant reaction pathway in the presence of liquid water. This difference in reaction pathways is explained by the availability of an exogenous source of hydrogen, which reduces the rate of thermal decomposition, promotes thermal cracking, and inhibits carbon-carbon bond cross linking. The distribution of generated n-alkanes is characteristic of a free radical mechanism, with a broad carbon-number distribution (i.e., C 5 to C 35) and only minor branched alkanes from known biological precursors (i.e., pristane and phytane). The generation of excess oxygen in the form of CO 2 in hydrous experiments and the high degree of hydrocarbon deuteration in a D 2O experiment indicate that water dissolved in the bitumen is an exogenous source of hydrogen. The lack of an effect on product composition and yield with an increase in H + activity by five orders of magnitude in a hydrous experiment indicates that an ionic mechanism for water interactions with thermally decomposing bitumen is not likely. Several mechanistically simple and thermodynamically favorable reactions that are consistent with the available experimental data are envisaged for the generation of exogenous hydrogen and excess oxygen as CO 2. One reaction series involves water oxidizing existing carbonyl groups to form hydrogen and car☐yl groups, with the latter forming CO 2 by decar☐ylation with increasing thermal stress. Another reaction series involves either hydrogen or oxygen in dissolved water molecules directly interacting with unpaired electrons to form a hydrogen-terminated free-radical site or an oxygenated functional group, respectively. The latter is expected to be susceptible to oxidation by other dissolved water molecules to generate additional hydrogen and CO 2. In addition to water acting as an exogenous source of hydrogen, it is also essential to the generation of an expelled saturate-enriched oil that is similar to natural crude oil. This role of water is demonstrated by the lack of an expelled oil in an experiment where a liquid Ga sbnd In alloy is substituted for liquid water. Experiments conducted with high salinity water and high water/rock ratios indicate that selective aqueous solubility of hydrocarbons is not responsible for the expelled oil generated in hydrous pyrolysis experiments. Similarly, a hydrous pyrolysis experiment conducted with isolated kerogen indicates that expelled oil in hydrous pyrolysis is not the result of preferential sorption of polar organic components by the mineral matrix of a source rock. It is envisaged that dissolved water in the bitumen network of a source rock causes an immiscible saturate-enriched oil to become immiscible with the thermally decomposing polar-enriched bitumen. The overall geochemical implication of these results is that it is essential to consider the role of water in experimental studies designed to understand natural rates of petroleum generation, expulsion mechanisms of primary migration, thermal stability of crude oil, reaction kinetics of biomarker transformations, and thermal maturity indicators in sedimentary basins.

Experiments on the role of water in petroleum formation

USGS Publications Warehouse

Lewan, M.D.

1997-01-01

Pyrolysis experiments were conducted on immature petroleum source rocks under various conditions to evaluate the role of water in petroleum formation. At temperatures less than 330??C for 72 h, the thermal decomposition of kerogen to bitumen was not significantly affected by the presence or absence of liquid water in contact with heated gravel-sized source rock. However, at 330 and 350??C for 72 h, the thermal decomposition of generated bitumen was significantly affected by the presence or absence of liquid water. Carbon-carbon bond cross linking resulting in the formation of an insoluble bitumen (i.e., pyrobitumen) is the dominant reaction pathway in the absence of liquid water. Conversely, thermal cracking of carbon-carbon bonds resulting in the generation of saturate-enriched oil, which is similar to natural crude oils, is the dominant reaction pathway in the presence of liquid water. This difference in reaction pathways is explained by the availability of an exogenous source of hydrogen, which reduces the rate of thermal decomposition, promotes thermal cracking, and inhibits carbon-carbon bond cross linking. The distribution of generated n-alkanes is characteristic of a free radical mechanism, with a broad carbon-number distribution (i.e., C5 to C35) and only minor branched alkanes from known biological precursors (i.e., pristane and phytane). The generation of excess oxygen in the form of CO2 in hydrous experiments and the high degree of hydrocarbon deuteration in a D2O experiment indicate that water dissolved in the bitumen is an exogenous source of hydrogen. The lack of an effect on product composition and yield with an increase in H+ activity by five orders of magnitude in a hydrous experiment indicates that an ionic mechanism for water interactions with thermally decomposing bitumen is not likely. Several mechanistically simple and thermodynamically favorable reactions that are consistent with the available experimental data are envisaged for the generation of exogenous hydrogen and excess oxygen as CO2. One reaction series involves water oxidizing existing carbonyl groups to form hydrogen and carboxyl groups, with the latter forming CO2 by decarboxylation with increasing thermal stress. Another reaction series involves either hydrogen or oxygen in dissolved water molecules directly interacting with unpaired electrons to form a hydrogen-terminated free-radical site or an oxygenated functional group, respectively. The latter is expected to be susceptible to oxidation by other dissolved water molecules to generate additional hydrogen and CO2. In addition to water acting as an exogenous source of hydrogen, it is also essential to the generation of an expelled saturate-enriched oil that is similar to natural crude oil. This role of water is demonstrated by the lack of an expelled oil in an experiment where a liquid Ga-In alloy is substituted for liquid water. Experiments conducted with high salinity water and high water/rock ratios indicate that selective aqueous solubility of hydrocarbons is not responsible for the expelled oil generated in hydrous pyrolysis experiments. Similarly, a hydrous pyrolysis experiment conducted with isolated kerogen indicates that expelled oil in hydrous pyrolysis is not the result of preferential sorption of polar organic components by the mineral matrix of a source rock. It is envisaged that dissolved water in the bitumen network of a source rock causes an immiscible saturate-enriched oil to become immiscible with the thermally decomposing polar-enriched bitumen. The overall geochemical implication of these results is that it is essential to consider the role of water in experimental studies designed to understand natural rates of petroleum generation, expulsion mechanisms of primary migration, thermal stability of crude oil, reaction kinetics of biomarker transformations, and thermal maturity indicators in sedimentary basins. Copyright ?? 1997 Elsevier Science Ltd.

Geologic Assessment of Undiscovered Oil and Gas Resources of the North Cuba Basin, Cuba

USGS Publications Warehouse

Schenk, Christopher J.

2010-01-01

Petroleum generation in the North Cuba Basin is primarily the result of thrust loading of Jurassic and Cretaceous source rocks during formation of the North Cuba fold and thrust belt in the Late Cretaceous to Paleogene. The fold and thrust belt formed as Cuban arc-forearc rocks along the leading edge of the Caribbean plate translated northward during the opening of the Yucatan Basin and collided with the passive margin of southern North America in the Paleogene. Petroleum fluids generated during thrust loading migrated vertically into complex structures in the fold and thrust belt, into structures in the foreland basin, and possibly into carbonate reservoirs along the margins of the Yucatan and Bahama carbonate platforms. The U.S. Geological Survey (USGS) defined a Jurassic-Cretaceous Composite Total Petroleum System (TPS) and three assessment units (AU)-North Cuba Fold and Thrust Belt AU, North Cuba Foreland Basin AU, and the North Cuba Platform Margin Carbonate AU-within this TPS based mainly on structure and reservoir type (fig. 1). There is considerable geologic uncertainty as to the extent of petroleum migration that might have occurred within this TPS to form potential petroleum accumulations. Taking this geologic uncertainty into account, especially in the offshore area, the mean volumes of undiscovered resources in the composite TPS of the North Cuba Basin are estimated at (1) 4.6 billion barrels of oil (BBO), with means ranging from an F95 probability of 1 BBO to an F5 probability of 9 BBO; and (2) 8.6 trillion cubic feet of of gas (TCFG), of which 8.6 TCFG is associated with oil fields, and about 1.2 TCFG is in nonassociated gas fields in the North Cuba Foreland Basin AU.

Modeling the mesozoic-cenozoic structural evolution of east texas

USGS Publications Warehouse

Pearson, Ofori N.; Rowan, Elisabeth L.; Miller, John J.

2012-01-01

The U.S. Geological Survey (USGS) recently assessed the undiscovered technically recoverable oil and gas resources within Jurassic and Cretaceous strata of the onshore coastal plain and State waters of the U.S. Gulf Coast. Regional 2D seismic lines for key parts of the Gulf Coast basin were interpreted in order to examine the evolution of structural traps and the burial history of petroleum source rocks. Interpretation and structural modeling of seismic lines from eastern Texas provide insights into the structural evolution of this part of the Gulf of Mexico basin. Since completing the assessment, the USGS has acquired additional regional seismic lines in east Texas; interpretation of these new lines, which extend from the Texas-Oklahoma state line to the Gulf Coast shoreline, show how some of the region's prominent structural elements (e.g., the Talco and Mount Enterprise fault zones, the East Texas salt basin, and the Houston diapir province) vary along strike. The interpretations also indicate that unexplored structures may lie beneath the current drilling floor. Structural restorations based upon interpretation of these lines illustrate the evolution of key structures and show the genetic relation between structural growth and movement of the Jurassic Louann Salt. 1D thermal models that integrate kinetics and burial histories were also created for the region's two primary petroleum source rocks, the Oxfordian Smackover Formation and the Cenomanian-Turonian Eagle Ford Shale. Integrating results from the thermal models with the structural restorations provides insights into the distribution and timing of petroleum expulsion from the Smackover Formation and Eagle Ford Shale in eastern Texas.

Characterization of contamination, source and degradation of petroleum between upland and paddy fields based on geochemical characteristics and phospholipid fatty acids.

PubMed

Zhang, Juan; Wang, Renqing; Du, Xiaoming; Li, Fasheng; Dai, Jiulan

2012-01-01

To evaluate contamination caused by petroleum, surface soil samples were collected from both upland and paddy fields along the irrigation canals in the Hunpu wastewater irrigation region in northeast China. N-alkanes, terpanes, steranes, and phospholipid fatty acids (PLFA) in the surface soil samples were analyzed. The aliphatic hydrocarbon concentration was highest in the samples obtained from the upland field near an operational oil well; it was lowest at I-3P where wastewater irrigation promoted the downward movement of hydrocarbons. The Hunpu region was found contaminated by heavy petroleum from oxic lacustrine fresh water or marine deltaic source rocks. Geochemical parameters also indicated significantly heavier contamination and degradation in the upland fields compared with the paddy fields. Principal component analysis based on PLFA showed various microbial communities between petroleum contaminated upland and paddy fields. Gram-negative bacteria indicated by 15:0, 3OH 12:0, and 16:1(9) were significantly higher in the paddy fields, whereas Gram-positive bacteria indicated by i16:0 and 18:1(9)c were significantly higher in the upland fields (p < 0.05). These PLFAs were related to petroleum contamination. Poly-unsaturated PLFA (18:2omega6, 9; indicative of hydrocarbon-degrading bacteria and fungi) was also significantly elevated in the upland fields. This paper recommends more sensitive indicators of contamination and degradation of petroleum in soil. The results also provide guidelines on soil pollution control and remediation in the Hunpu region and other similar regions.

Methane clumped isotopes in the Songliao Basin (China): New insights into abiotic vs. biotic hydrocarbon formation

NASA Astrophysics Data System (ADS)

Shuai, Yanhua; Etiope, Giuseppe; Zhang, Shuichang; Douglas, Peter M. J.; Huang, Ling; Eiler, John M.

2018-01-01

Abiotic hydrocarbon gas, typically generated in serpentinized ultramafic rocks and crystalline shields, has important implications for the deep biosphere, petroleum systems, the carbon cycle and astrobiology. Distinguishing abiotic gas (produced by chemical reactions like Sabatier synthesis) from biotic gas (produced from degradation of organic matter or microbial activity) is sometimes challenging because their isotopic and molecular composition may overlap. Abiotic gas has been recognized in numerous locations on the Earth, although there are no confirmed instances where it is the dominant source of commercially valuable quantities in reservoir rocks. The deep hydrocarbon reservoirs of the Xujiaweizi Depression in the Songliao Basin (China) have been considered to host significant amounts of abiotic methane. Here we report methane clumped-isotope values (Δ18) and the isotopic composition of C1-C3 alkanes, CO2 and helium of five gas samples collected from those Xujiaweizi deep reservoirs. Some geochemical features of these samples resemble previously suggested identifiers of abiotic gas (13C-enriched CH4; decrease in 13C/12C ratio with increasing carbon number for the C1-C4 alkanes; abundant, apparently non-biogenic CO2; and mantle-derived helium). However, combining these constraints with new measurements of the clumped-isotope composition of methane and careful consideration of the geological context, suggests that the Xujiaweizi depression gas is dominantly, if not exclusively, thermogenic and derived from over-mature source rocks, i.e., from catagenesis of buried organic matter at high temperatures. Methane formation temperatures suggested by clumped-isotopes (167-213 °C) are lower than magmatic gas generation processes and consistent with the maturity of local source rocks. Also, there are no geological conditions (e.g., serpentinized ultramafic rocks) that may lead to high production of H2 and thus abiotic production of CH4 via CO2 reduction. We propose that the Songliao gas is representative of an atypical type of thermogenic gas that can be mistaken for abiotic gas. Such gases may be encountered more frequently in future exploration of deep or over-mature petroleum systems.

Geology and sequence stratigraphy of undiscovered oil and gas resources in conventional and continuous petroleum systems in the Upper Cretaceous Eagle Ford Group and related strata, U.S. Gulf Coast Region

USGS Publications Warehouse

Dubiel, Russell F.; Pearson, Ofori N.; Pitman, Janet K.; Pearson, Krystal M.; Kinney, Scott A.

2012-01-01

The U.S. Geological Survey (USGS) recently assessed the technically recoverable undiscovered oil and gas onshore and in State waters of the Gulf Coast region of the United States. The USGS defined three assessment units (AUs) with potential undiscovered conventional and continuous oil and gas resources in Upper Cretaceous (Cenomanian to Turonian) strata of the Eagle Ford Group and correlative rocks. The assessment is based on geologic elements of a total petroleum system, including hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and traps (formation, timing, and seals). Conventional oil and gas undiscovered resources are in updip sandstone reservoirs in the Upper Cretaceous Tuscaloosa and Woodbine Formations (or Groups) in Louisiana and Texas, respectively, whereas continuous oil and continuous gas undiscovered resources reside in the middip and downdip Upper Cretaceous Eagle Ford Shale in Texas and the Tuscaloosa marine shale in Louisiana. Conventional resources in the Tuscaloosa and Woodbine are included in the Eagle Ford Updip Sandstone Oil and Gas AU, in an area where the Eagle Ford Shale and Tuscaloosa marine shale display vitrinite reflectance (Ro) values less than 0.6%. The continuous Eagle Ford Shale Oil AU lies generally south of the conventional AU, is primarily updip of the Lower Cretaceous shelf edge, and is defined by thermal maturity values within shales of the Eagle Ford and Tuscaloosa that range from 0.6 to 1.2% Ro. Similarly, the Eagle Ford Shale Gas AU is defined downdip of the shelf edge where source rocks have Ro values greater than 1.2%. For undiscovered oil and gas resources, the USGS assessed means of: 1) 141 million barrels of oil (MMBO), 502 billion cubic feet of natural gas (BCFG), and 4 million barrels of natural gas liquids (MMBNGL) in the Eagle Ford Updip Sandstone Oil and Gas AU; 2) 853 MMBO, 1707 BCFG, and 34 MMBNGL in the Eagle Ford Shale Oil AU; and 3) 50,219 BCFG and 2009 MMBNGL in the Eagle Ford Shale Gas AU.

Towards an understanding of the role of clay minerals in crude oil formation, migration and accumulation

NASA Astrophysics Data System (ADS)

Wu, Lin Mei; Zhou, Chun Hui; Keeling, John; Tong, Dong Shen; Yu, Wei Hua

2012-12-01

This article reviews progress in the understanding of the role of clay minerals in crude oil formation, migration and accumulation. Clay minerals are involved in the formation of kerogen, catalytic cracking of kerogen into petroleum hydrocarbon, the migration of crude oil, and the continued change to hydrocarbon composition in underground petroleum reservoirs. In kerogen formation, clay minerals act as catalysts and sorbents to immobilize organic matter through ligand exchange, hydrophobic interactions and cation bridges by the mechanisms of Maillard reactions, polyphenol theory, selective preservation and sorptive protection. Clay minerals also serve as catalysts in acid-catalyzed cracking of kerogen into petroleum hydrocarbon through Lewis and Brønsted acid sites on the clay surface. The amount and type of clay mineral affect the composition of the petroleum. Brønsted acidity of clay minerals is affected by the presence and state of interlayer water, and displacement of this water is a probable driver in crude oil migration from source rocks. During crude oil migration and accumulation in reservoirs, the composition of petroleum is continually modified by interaction with clay minerals. The clays continue to function as sorbents and catalysts even while they are being transformed by diagenetic processes. The detail of chemical interactions and reaction mechanisms between clay minerals and crude oil formation remains to be fully explained but promises to provide insights with broader application, including catalytic conversion of biomass as a source of sustainable energy into the future.

Assessment of Coalbed Gas Resources in Cretaceous and Tertiary Rocks on the North Slope, Alaska, 2006

USGS Publications Warehouse

Roberts, Steve; Barker, Charles E.; Bird, Kenneth J.; Charpentier, Ronald R.; Cook, Troy; Houseknecht, David W.; Klett, Timothy R.; Pollastro, Richard M.; Schenk, Christopher J.

2006-01-01

The North Slope of Alaska is a vast area of land north of the Brooks Range, extending from the Chukchi Sea eastward to the Canadian border. This Arctic region is known to contain extensive coal deposits; hypothetical coal resource estimates indicate that nearly 4 trillion short tons of coal are in Cretaceous and Tertiary rocks. Because of the large volume of coal, other studies have indicated that this region might also have potential for significant coalbed gas resources. The present study represents the first detailed assessment of undiscovered coalbed gas resources beneath the North Slope by the USGS. The assessment is based on the total petroleum system (TPS) concept. Geologic elements within a TPS relate to hydrocarbon source rocks (maturity, hydrocarbon generation, migration), the characteristics of reservoir rocks, and trap and seal formation. In the case of coalbed gas, the coal beds serve as both source rock and reservoir. The Brookian Coalbed Gas Composite TPS includes coal-bearing rocks in Cretaceous and Tertiary strata underlying the North Slope and adjacent Alaska State waters. Assessment units (AUs) within the TPS (from oldest to youngest) include the Nanushuk Formation Coalbed Gas AU, the Prince Creek and Tuluvak Formations Coalbed Gas AU, and the Sagavanirktok Formation Coalbed Gas AU.

Mongolian Oil Shale, hosted in Mesozoic Sedimentary Basins

NASA Astrophysics Data System (ADS)

Bat-Orshikh, E.; Lee, I.; Norov, B.; Batsaikhan, M.

2016-12-01

Mongolia contains several Mesozoic sedimentary basins, which filled >2000 m thick non-marine successions. Late Triassic-Middle Jurassic foreland basins were formed under compression tectonic conditions, whereas Late Jurassic-Early Cretaceous rift valleys were formed through extension tectonics. Also, large areas of China were affected by these tectonic events. The sedimentary basins in China host prolific petroleum and oil shale resources. Similarly, Mongolian basins contain hundreds meter thick oil shale as well as oil fields. However, petroleum system and oil shale geology of Mongolia remain not well known due to lack of survey. Mongolian oil shale deposits and occurrences, hosted in Middle Jurassic and Lower Cretaceous units, are classified into thirteen oil shale-bearing basins, of which oil shale resources were estimated to be 787 Bt. Jurassic oil shale has been identified in central Mongolia, while Lower Cretaceous oil shale is distributed in eastern Mongolia. Lithologically, Jurassic and Cretaceous oil shale-bearing units (up to 700 m thick) are similar, composed mainly of alternating beds of oil shale, dolomotic marl, siltstone and sandstone, representing lacustrine facies. Both Jurassic and Cretaceous oil shales are characterized by Type I kerogen with high TOC contents, up to 35.6% and low sulfur contents ranging from 0.1% to 1.5%. Moreover, S2 values of oil shales are up to 146 kg/t. The numbers indicate that the oil shales are high quality, oil prone source rocks. The Tmax values of samples range from 410 to 447, suggesting immature to early oil window maturity levels. PI values are consistent with this interpretation, ranging from 0.01 to 0.03. According to bulk geochemistry data, Jurassic and Cretaceous oil shales are identical, high quality petroleum source rocks. However, previous studies indicate that known oil fields in Eastern Mongolia were originated from Lower Cretaceous oil shales. Thus, further detailed studies on Jurassic oil shale and its petroleum potential are required.

In search of a Silurian Total Petroleum System in the Appalachian Basin of New York, Ohio, Pennsylvania, and West Virginia

USGS Publications Warehouse

Ryder, Robert T.; Swezey, Christopher S.; Trippi, Michael H.; Lentz, Erika E.; Avary, K. Lee; Harper, John A.; Kappel, William M.; Rea, Ronald G.

2007-01-01

This report provides an evaluation of the source rock potential of Silurian strata in the U.S. portion of the northern Appalachian Basin, using new TOC and RockEval data. The study area consists of all or parts of New York, Ohio, Pennsylvania, and West Virginia. The stratigraphic intervals that were sampled for this study are as follows: 1) the Lower Silurian Cabot Head Shale, Rochester Shale, and Rose Hill Formation; 2) the Lower and Upper Silurian McKenzie Limestone, Lockport Dolomite, and Eramosa Member of the Lockport Group; and 3) the Upper Silurian Wills Creek Formation, Tonoloway Limestone, Salina Group, and Bass Islands Dolomite. These Silurian stratigraphic intervals were chosen because they are cited in previous publications as potential source rocks, they are easily identified and relatively continuous across the basin, and they contain beds of dark gray to black shale and (or) black argillaceous limestone and dolomite.

Impacts of petroleum production on ground and surface waters: Results from the Osage-Skiatook Petroleum Environmental Research A site, Osage County Oklahoma

USGS Publications Warehouse

Kharaka, Y.K.; Thordsen, J.J.; Kakouros, E.; Herkelrath, W.N.

2005-01-01

As part of a multidisciplinary group of about 20 scientists, we are investigating the transport, fate, natural attenuation, and ecosystem impacts of inorganic salts and organic compounds present in releases of produced water and associated hydrocarbons at the Osage-Skiatook Petroleum Environmental Research (OSPER) sites, located in Osage County, Oklahoma. Geochemical data collected from nearby oil wells show that the produced water source is a Na-Ca-Cl brine (???150,000 mg/L total dissolved solids [TDS]), with relatively high concentrations of Mg, Sr, and NH4, but low SO4 and H2S. Results from the depleted OSPER A site show that the salts continue to be removed from the soil and surficial rocks, but degraded oil persists on the contaminated surface. Eventually, the bulk of inorganic salts and dissolved organics in the brine will reach the adjacent Skiatook Lake, a 4250-ha (10,501-ac) potable water reservoir. Repeated sampling of 44 wells show a plume of high-salinity water (2000-30,000 mg/L TDS) at intermediate depths that intersects Skiatook Lake and extends beyond the visibly impacted areas. No liquid petroleum was observed in this plume, but organic acid anions, benzene, toluene, ethylbenzene, and xylene (BTEX), and other volatile organic carbon (VOC) are present. The chemical composition of released brine is modified by sorption, mineral precipitation and dissolution, evapotranspiration, volatilization, and bacterially mediated oxidation-reduction reactions, in addition to mixing with percolating precipitation water, lake water, and pristine groundwater. Results show that only minor amounts of salt are removed by runoff, supporting the conclusion that significant amounts of salts from produced water and petroleum releases still remain in the soils and rocks of the impacted area after more than 65 yr of natural attenuation. Copyright ?? 2005. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Petroleum geology and resources of the West Siberian Basin, Russia

USGS Publications Warehouse

Ulmishek, Gregory F.

2003-01-01

The West Siberian basin is the largest petroleum basin in the world covering an area of about 2.2 million km2. The basin occupies a swampy plain between the Ural Mountains and the Yenisey River. On the north, the basin extends offshore into the southern Kara Sea. On the west, north, and east, the basin is surrounded by the Ural, Yenisey Ridge, and Turukhan-Igarka foldbelts that experienced major deformations during the Hercynian tectonic event and the Novaya Zemlya foldbelt that was deformed in early Cimmerian (Triassic) time. On the south, the folded Caledonian structures of the Central Kazakhstan and Altay-Sayan regions dip northward beneath the basin?s sedimentary cover. The basin is a relatively undeformed Mesozoic sag that overlies the Hercynian accreted terrane and the Early Triassic rift system. The basement is composed of foldbelts that were deformed in Late Carboniferous?Permian time during collision of the Siberian and Kazakhstan continents with the Russian craton. The basement also includes several microcontinental blocks with a relatively undeformed Paleozoic sedimentary sequence. The sedimentary succession of the basin is composed of Middle Triassic through Tertiary clastic rocks. The lower part of this succession is present only in the northern part of the basin; southward, progressively younger strata onlap the basement, so that in the southern areas the basement is overlain by Toarcian and younger rocks. The important stage in tectono-stratigraphic development of the basin was formation of a deep-water sea in Volgian?early Berriasian time. The sea covered more than one million km2 in the central basin area. Highly organic-rich siliceous shales of the Bazhenov Formation were deposited during this time in anoxic conditions on the sea bottom. Rocks of this formation have generated more than 80 percent of West Siberian oil reserves and probably a substantial part of its gas reserves. The deep-water basin was filled by prograding clastic clinoforms during Neocomian time. The clastic material was transported by a system of rivers dominantly from the eastern provenance. Sandstones within the Neocomian clinoforms contain the principal oil reservoirs. The thick continental Aptian?Cenomanian Pokur Formation above the Neocomian sequence contains giant gas reserves in the northern part of the basin. Three total petroleum systems are identified in the West Siberian basin. Volumes of discovered hydrocarbons in these systems are 144 billion barrels of oil and more than 1,300 trillion cubic feet of gas. The assessed mean undiscovered resources are 55.2 billion barrels of oil, 642.9 trillion cubic feet of gas, and 20.5 billion barrels of natural gas liquids. The largest known oil reserves are in the Bazhenov-Neocomian total petroleum system that includes Upper Jurassic and younger rocks of the central and southern parts of the basin. Oil reservoirs are mainly in Neocomian and Upper Jurassic clastic strata. Source rocks are organic-rich siliceous shales of the Bazhenov Formation. Most discovered reserves are in structural traps, but stratigraphic traps in the Neocomian clinoform sequence are pro-ductive and are expected to contain much of the undiscovered resources. Two assessment units are identified in this total petroleum system. The first assessment unit includes all conventional reservoirs in the stratigraphic interval from the Upper Jurassic to the Cenomanian. The second unit includes unconventional (or continuous), self-sourced, fractured reservoirs in the Bazhenov Formation. This unit was not assessed quantitatively. The Togur-Tyumen total petroleum system covers the same geographic area as the Bazhenov-Neocomian system, but it includes older, Lower?Middle Jurassic strata and weathered rocks at the top of the pre-Jurassic sequence. A Callovian regional shale seal of the Abalak and lower Vasyugan Formations separates the two systems. The Togur-Tyumen system is oil-prone; gas reserves are insignificant. The principal o

A Systems Approach to Identifying Exploration and Development Opportunities in the Illinois Basin: Digital Portifolio of Plays in Underexplored Lower Paleozoic Rocks [Part 1 of 2

DOE Office of Scientific and Technical Information (OSTI.GOV)

Seyler, Beverly; Harris, David; Keith, Brian

2008-06-30

This study examined petroleum occurrence in Ordovician, Silurian and Devonian reservoirs in the Illinois Basin. Results from this project show that there is excellent potential for additional discovery of petroleum reservoirs in these formations. Numerous exploration targets and exploration strategies were identified that can be used to increase production from these underexplored strata. Some of the challenges to exploration of deeper strata include the lack of subsurface data, lack of understanding of regional facies changes, lack of understanding the role of diagenetic alteration in developing reservoir porosity and permeability, the shifting of structural closures with depth, overlooking potential producing horizons,more » and under utilization of 3D seismic techniques. This study has shown many areas are prospective for additional discoveries in lower Paleozoic strata in the Illinois Basin. This project implemented a systematic basin analysis approach that is expected to encourage exploration for petroleum in lower Paleozoic rocks of the Illinois Basin. The study has compiled and presented a broad base of information and knowledge needed by independent oil companies to pursue the development of exploration prospects in overlooked, deeper play horizons in the Illinois Basin. Available geologic data relevant for the exploration and development of petroleum reservoirs in the Illinois Basin was analyzed and assimilated into a coherent, easily accessible digital play portfolio. The primary focus of this project was on case studies of existing reservoirs in Devonian, Silurian, and Ordovician strata and the application of knowledge gained to future exploration and development in these underexplored strata of the Illinois Basin. In addition, a review of published reports and exploration in the New Albany Shale Group, a Devonian black shale source rock, in Illinois was completed due to the recent increased interest in Devonian black shales across the United States. The New Albany Shale is regarded as the source rock for petroleum in Silurian and younger strata in the Illinois Basin and has potential as a petroleum reservoir. Field studies of reservoirs in Devonian strata such as the Geneva Dolomite, Dutch Creek Sandstone and Grassy knob Chert suggest that there is much additional potential for expanding these plays beyond their current limits. These studies also suggest the potential for the discovery of additional plays using stratigraphic concepts to develop a subcrop play on the subkaskaskia unconformity boundary that separates lower Devonian strata from middle Devonian strata in portions of the basin. The lateral transition from Geneva Dolomite to Dutch Creek Sandstone also offers an avenue for developing exploration strategies in middle Devonian strata. Study of lower Devonian strata in the Sesser Oil Field and the region surrounding the field shows opportunities for development of a subcrop play where lower Devonian strata unconformably overlie Silurian strata. Field studies of Silurian reservoirs along the Sangamon Arch show that opportunities exist for overlooked pays in areas where wells do not penetrate deep enough to test all reservoir intervals in Niagaran rocks. Mapping of Silurian reservoirs in the Mt. Auburn trend along the Sangamon Arch shows that porous reservoir rock grades laterally to non-reservoir facies and several reservoir intervals may be encountered in the Silurian with numerous exploration wells testing only the uppermost reservoir intervals. Mapping of the Ordovician Trenton and shallower strata at Centralia Field show that the crest of the anticline shifted through geologic time. This study illustrates that the axes of anticlines may shift with depth and shallow structure maps may not accurately predict structurally favorable reservoir locations at depth.« less

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

USGS Publications Warehouse

Condon, S.M.; Dyman, T.S.

2006-01-01

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

A Transversely Isotropic Thermo-mechanical Framework for Oil Shale

NASA Astrophysics Data System (ADS)

Semnani, S. J.; White, J. A.; Borja, R. I.

2014-12-01

The present study provides a thermo-mechanical framework for modeling the temperature dependent behavior of oil shale. As a result of heating, oil shale undergoes phase transformations, during which organic matter is converted to petroleum products, e.g. light oil, heavy oil, bitumen, and coke. The change in the constituents and microstructure of shale at high temperatures dramatically alters its mechanical behavior e.g. plastic deformations and strength, as demonstrated by triaxial tests conducted at multiple temperatures [1,2]. Accordingly, the present model formulates the effects of changes in the chemical constituents due to thermal loading. It is well known that due to the layered structure of shale its mechanical properties in the direction parallel to the bedding planes is significantly different from its properties in the perpendicular direction. Although isotropic models simplify the modeling process, they fail to accurately describe the mechanical behavior of these rocks. Therefore, many researchers have studied the anisotropic behavior of rocks, including shale [3]. The current study presents a framework to incorporate the effects of transverse isotropy within a thermo-mechanical formulation. The proposed constitutive model can be readily applied to existing finite element codes to predict the behavior of oil shale in applications such as in-situ retorting process and stability assessment in petroleum reservoirs. [1] Masri, M. et al."Experimental Study of the Thermomechanical Behavior of the Petroleum Reservoir." SPE Eastern Regional/AAPG Eastern Section Joint Meeting. Society of Petroleum Engineers, 2008. [2] Xu, B. et al. "Thermal impact on shale deformation/failure behaviors---laboratory studies." 45th US Rock Mechanics/Geomechanics Symposium. American Rock Mechanics Association, 2011. [3] Crook, AJL et al. "Development of an orthotropic 3D elastoplastic material model for shale." SPE/ISRM Rock Mechanics Conference. Society of Petroleum Engineers, 2002.

A chemical and thermodynamic model of oil generation in hydrocarbon source rocks

NASA Astrophysics Data System (ADS)

Helgeson, Harold C.; Richard, Laurent; McKenzie, William F.; Norton, Denis L.; Schmitt, Alexandra

2009-02-01

Thermodynamic calculations and Gibbs free energy minimization computer experiments strongly support the hypothesis that kerogen maturation and oil generation are inevitable consequences of oxidation/reduction disproportionation reactions caused by prograde metamorphism of hydrocarbon source rocks with increasing depth of burial.These experiments indicate that oxygen and hydrogen are conserved in the process.Accordingly, if water is stable and present in the source rock at temperatures ≳25 but ≲100 °C along a typical US Gulf Coast geotherm, immature (reduced) kerogen with a given atomic hydrogen to carbon ratio (H/C) melts incongruently with increasing temperature and depth of burial to produce a metastable equilibrium phase assemblage consisting of naphthenic/biomarker-rich crude oil, a type-II/III kerogen with an atomic hydrogen/carbon ratio (H/C) of ˜1, and water. Hence, this incongruent melting process promotes diagenetic reaction of detritus in the source rock to form authigenic mineral assemblages.However, in the water-absent region of the system CHO (which is extensive), any water initially present or subsequently entering the source rock is consumed by reaction with the most mature kerogen with the lowest H/C it encounters to form CO 2 gas and a new kerogen with higher H/C and O/C, both of which are in metastable equilibrium with one another.This hydrolytic disproportionation process progressively increases both the concentration of the solute in the aqueous phase, and the oil generation potential of the source rock; i.e., the new kerogen can then produce more crude oil.Petroleum is generated with increasing temperature and depth of burial of hydrocarbon source rocks in which water is not stable in the system CHO by a series of irreversible disproportionation reactions in which kerogens with higher (H/C)s melt incongruently to produce metastable equilibrium assemblages consisting of crude oil, CO 2 gas, and a more mature (oxidized) kerogen with a lower H/C which in turn melts incongruently with further burial to produce more crude oil, CO 2 gas, and a kerogen with a lower H/C and so forth.The petroleum generated in the process progresses from heavy naphthenic crude oils at low temperatures to mature petroleum at ˜150 °C. For example, the results of Computer Experiment 27 (see below) indicate that the overall incongruent melting reaction in the water-absent region of the system C-H-O at 150 °C and a depth of ˜4.3 km of an immature type-II/III kerogen with a bulk composition represented by C 292H 288O 12(c) to produce a mature (oxidized) kerogen represented by C 128H 68O 7(c), together with a typical crude oil with an average metastable equilibrium composition corresponding to C 8.8H 16.9 (C 8.8H 16.9(l)) and CO 2 gas (CO 2(g)) can be described by writing CHO (kerogen,H/C=0.99O/C=0.041) →1.527CHO(kerogen,H/C=0.53O/C=0.055) +10.896CH(crude oil,H/C=1.92)+0.656CO which corresponds to a disproportionation reaction in the source rock representing the sum of a series of oxidation/reduction conservation reactions. Consideration of the stoichiometries of incongruent melting reactions analogous to Reaction (A) for reactant kerogens with different (H/C)s and/or atomic oxygen to carbon ratios (O/C)s, together with crude oil compositions corresponding to Gibbs free energy minima at specified temperatures and pressures permits calculation of the volume of oil (mole of reactant organic carbon (ROC)) -1 that can be generated in, as well as the volume of oil (mol ROC) -1 which exceeds the volume of kerogen pore space produced that must be expelled from hydrocarbon source rocks as a function of temperature, pressure, and the H/C and O/C of the reactant kerogen. These volumes and the reaction coefficients (mol ROC) -1 of the product kerogen, crude oil, and CO 2 gas in the incongruent melting reaction are linear functions of the H/C and O/C of the reactant kerogen at a given temperature and pressure. The slopes of the isopleths can be computed from power functions of temperature along a typical US Gulf Coast geotherm. All of these reactions and relations are consistent with the well-known observations that (1) the relative abundance of mature kerogen increases, and that of immature kerogen decreases with increasing burial of hydrocarbon source rocks and (2) that the volume of oil generated in a given source rock increases with increasing weight percent total organic carbon (TOC) and the H/C and (to a lesser extent) the O/C of the immature kerogen. They are also compatible with preservation of biomarkers and other polymerized hydrocarbons during the incongruent melting process. It can be deduced from Reaction (A) that nearly 11 mol of crude oil are produced from one mole of the reactant kerogen (rk), which increases to ˜39.5 mol (mol rk) -1 as the carbon content and H/C of the reactant kerogen increase to that in the hydrogen-rich type-I kerogen represented by C 415H 698O 22(c). The secondary porosities created in source rocks by Reaction (A) and others like it are of the order of 75-80 vol % of the oil generated, which requires expulsion of the remainder, together with the CO 2 gas produced by the reaction. The expulsion of the CO 2 gas and excess crude oil from the hydrocarbon source rock is facilitated by their buoyancy and the fact that the pressure in the source rocks is ⩾ the fluid pressure in the adjoining formations during progressive generation of the volume of crude oil that exceeds the kerogen pore volume produced by the incongruent melting process. The expelled CO 2 gas lowers the pH of the surrounding formation waters, which promotes the development of secondary porosity and diagenetic reaction of detrital silicates to form authigenic mineral assemblages. Hence, the expulsion process facilitates initial upward migration of the oil, which is further enhanced by expansion of the oil and its reaction with H 2O at the oil-water interface to generate methane gas. Mass transfer calculations indicate that the minimal volume of crude oil expelled into these formations is comparable to, or exceeds the volume of oil produced and in proven reserves in major oil fields such as the North Sea, the Paris and Los Angeles Basins, and those in Kuwait, Saudi Arabia, and elsewhere in the Middle East. For example, taking account of the average weight percent ( W%) organic carbon in the immature kerogen (3.4 wt%) with an average H/C of ˜1.04 in the hydrocarbon source rocks in Saudi Arabia, which have an average thickness of ˜43 m, it can be shown (see below) that all of the oil (and oil equivalent of natural gas) produced and in proven reserves in Saudi Arabia (374 billion barrels of oil or ˜1.9 million barrels of oil km -2) can be accounted for by minimal expulsion from the source rocks of oil generated at ˜125 °C solely by the incongruent melting process. Computer experiments indicate that this process can also account for all the petroleum that can be, and has been generated in the world's hydrocarbon source rocks. Of the latter, as much as 75-80% may still remain in these rocks.

Assessment of the petroleum, coal, and geothermal resources of the Economic Community of West African States (ECOWAS) region

USGS Publications Warehouse

Mattick, R. E.

1982-01-01

Approximately 85 percent of the land area of the ECOWAS (Economic Community of West African States) region is covered by basement rocks (igneous and highly metamorphosed rocks) or relatively thin layers of Paleozoic, Upper Precambrian, and 'Continental Intercalaire? sedimentary rocks. These areas have little or no petroleum potential. Areas of the ECOWAS region that have potential for petroleum production or potential for increased petroleum production include the narrow belt of sedimentary rocks that stretches along the continental margin from Mauritania to Nigeria and the Niger Delta and the Benue depression. The Senegal Basin, located on the continental margin of Mauritania, Senegal, Gambia, Guinea Bissau, and Guinea, has been intensely explored by the oil industry and most of the larger structures onshore and on the shelf probably have been tested by drilling with little or no resulting commercial production. Unless basic ideas pertaining to the petroleum geology of the Senegal Basin are revised, future discoveries are expected to be limited to small fields overlooked by industry at a time when petroleum prices were low. On the continental shelf of Sierra Leone and the continental shelf of northeast and central Liberia, the sedimentary rocks are relatively thin, and industry has shown little interest in the area. On the continental rise of these countries, however, the sedimentary section, deposited in a complex fault-block system, increases in thickness. A renewal of industry interest in this deep-water area will probably follow further development of deep-water production technology. A recent oil discovery on the continental slope off the Ivory Coast is expected to spur further exploration offshore of southeastern Liberia, Ivory Coast, Ghana, Togo, and Benin. This relatively unexplored area in the Gulf of Guinea has good possibilities .for the discovery of giant oil fields. Nigeria's oil development from the Niger Delta may have peaked, as 13 of 14 giant oil fields were discovered prior to 1969 and the greatest number of fields were discovered in the period 1965 through 1967. Like delta regions in other parts of the world, individual oil fields of the Niger Delta are small to medium by world standards and future discoveries, therefore, are likely to reflect this reality. The natural gas resources of the Niger Delta, unlike its oil resources, are comparatively underdeveloped. Parts of the Benue depression in Nigeria and Niger could contain significant deposits of petroleum. The lower Benue depression, immediately north of the Niger Delta, has been extensively explored by drilling. Except for noncommercial discoveries of oil and gas and traces of oil and gas on the ground surface, the results of exploration in the lower Benue depression were negative. However, in the Lake Chad area of Chad and in southern Chad near the Central African Republic boundary, oil and gas discoveries were made just prior to the cessation of all drilling and exploration activity in early 1979. It is rumored that these discoveries may be large although little information is available. The relation between the two areas in Chad and their overall relation to the Benue depression is poorly understood; however, the possibility of thick sedimentary sections containing Cretaceous marine source rock and Tertiary reservoir beds-all contained within grabens in a highly faulted failed-arm system subjected to high heat flow--is attractive. Of the ECOWAS countries, only Nigeria and Niger produce coal commercially. Nigeria produces subbituminous coal from Paleocene-Maestrichtian and Maestrichtian (Late Cretaceous) age rocks of the Niger Delta region; reserves are estimated, on the basis of extensive drilling, to be 350 million tons (standard coal equivalent). In addition, lignite deposits of the Niger Delta appear to be large but have not been developed. Niger produces small amounts of coal used locally by uranium mine and mill operations from C

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

USGS Publications Warehouse

Pollastro, Richard M.

2003-01-01

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).

Geology and oil and gas assessment of the Todilto Total Petroleum System, San Juan Basin Province, New Mexico and Colorado: Chapter 3 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

USGS Publications Warehouse

Ridgley, J.L.; Hatch, J.R.

2013-01-01

Organic-rich, shaly limestone beds, which contain hydrocarbon source beds in the lower part of the Jurassic Todilto Limestone Member of the Wanakah Formation, and sandstone reservoirs in the overlying Jurassic Entrada Sandstone, compose the Todilto Total Petroleum System (TPS). Source rock facies of the Todilto Limestone were deposited in a combined marine-lacustrine depositional setting. Sandstone reservoirs in the Entrada Sandstone were deposited in eolian depositional environments. Oil in Todilto source beds was generated beginning in the middle Paleocene, about 63 million years ago, and maximum generation of oil occurred in the middle Eocene. In the northern part of the San Juan Basin, possible gas and condensate were generated in Todilto Limestone Member source beds until the middle Miocene. The migration distance of oil from the Todilto source beds into the underlying Entrada Sandstone reservoirs was short, probably within the dimensions of a single dune crest. Traps in the Entrada are mainly stratigraphic and diagenetic. Regional tilt of the strata to the northeast has influenced structural trapping of oil, but also allowed for later introduction of water. Subsequent hydrodynamic forces have influenced the repositioning of the oil in some reservoirs and flushing in others. Seals are mostly the anhydrite and limestone facies of the Todilto, which thin to as little as 10 ft over the crests of the dunes. The TPS contains only one assessment unit, the Entrada Sandstone Conventional Oil Assessment Unit (AU) (50220401). Only four of the eight oil fields producing from the Entrada met the 0.5 million barrels of oil minimum size used for this assessment. The AU was estimated at the mean to have potential additions to reserves of 2.32 million barrels of oil (MMBO), 5.56 billion cubic feet of natural gas (BCFG), and 0.22 million barrels of natural gas liquids (MMBNGL).

Pore-throat sizes in sandstones, siltstones, and shales: Reply

USGS Publications Warehouse

Nelson, Philip H.

2011-01-01

In his discussion of my article (Nelson, 2009), W. K. Camp takes issue with the concept that buoyancy is not the dominant force in forming and maintaining the distribution of gas in tight-gas accumulations (Camp, 2011). I will restrict my response to the issues he raised regarding buoyant versus nonbuoyant drive and to a few comments regarding water saturation and production. I claim that the pressure generated in petroleum source rocks (Pg), instead of the buoyancy pressure (Pb), provides the energy to charge most tight sandstones with gas. The arguments are fourfold: (1) buoyant columns of sufficient height seldom exist in low-permeability sand-shale sequences, (2) tight-gas systems display a pressure profile that declines instead of increases upward, (3) gas is pervasive in overpressured systems, and (4) source rocks can generate pore pressures sufficiently high to charge tight sandstones.

What is shale gas and why is it important?

EIA Publications

2012-01-01

Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States.

Detailed description of oil shale organic and mineralogical heterogeneity via fourier transform infrared mircoscopy

USGS Publications Warehouse

Washburn, Kathryn E.; Birdwell, Justin E.; Foster, Michael; Gutierrez, Fernando

2015-01-01

Mineralogical and geochemical information on reservoir and source rocks is necessary to assess and produce from petroleum systems. The standard methods in the petroleum industry for obtaining these properties are bulk measurements on homogenized, generally crushed, and pulverized rock samples and can take from hours to days to perform. New methods using Fourier transform infrared (FTIR) spectroscopy have been developed to more rapidly obtain information on mineralogy and geochemistry. However, these methods are also typically performed on bulk, homogenized samples. We present a new approach to rock sample characterization incorporating multivariate analysis and FTIR microscopy to provide non-destructive, spatially resolved mineralogy and geochemistry on whole rock samples. We are able to predict bulk mineralogy and organic carbon content within the same margin of error as standard characterization techniques, including X-ray diffraction (XRD) and total organic carbon (TOC) analysis. Validation of the method was performed using two oil shale samples from the Green River Formation in the Piceance Basin with differing sedimentary structures. One sample represents laminated Green River oil shales, and the other is representative of oil shale breccia. The FTIR microscopy results on the oil shales agree with XRD and LECO TOC data from the homogenized samples but also give additional detail regarding sample heterogeneity by providing information on the distribution of mineral phases and organic content. While measurements for this study were performed on oil shales, the method could also be applied to other geological samples, such as other mudrocks, complex carbonates, and soils.

Near-Surface and High Resolution Seismic Imaging of the Bennett Thrust Fault in the Indio Mountains of West Texas

NASA Astrophysics Data System (ADS)

Vennemann, Alan

My research investigates the structure of the Indio Mountains in southwest Texas, 34 kilometers southwest of Van Horn, at the UTEP (University of Texas at El Paso) Field Station using newly acquired active-source seismic data. The area is underlain by deformed Cretaceous sedimentary rocks that represent a transgressive sequence nearly 2 km in total stratigraphic thickness. The rocks were deposited in mid Cretaceous extensional basins and later contracted into fold-thrust structures during Laramide orogenesis. The stratigraphic sequence is an analog for similar areas that are ideal for pre-salt petroleum reservoirs, such as reservoirs off the coasts of Brazil and Angola (Li, 2014; Fox, 2016; Kattah, 2017). The 1-km-long 2-D shallow seismic reflection survey that I planned and led during May 2016 was the first at the UTEP Field Station, providing critical subsurface information that was previously lacking. The data were processed with Landmark ProMAX seismic processing software to create a seismic reflection image of the Bennett Thrust Fault and additional imbricate faulting not expressed at the surface. Along the 1-km line, reflection data were recorded with 200 4.5 Hz geophones, using 100 150-gram explosive charges and 490 sledge-hammer blows for sources. A seismic reflection profile was produced using the lower frequency explosive dataset, which was used in the identification of the Bennett Thrust Fault and additional faulting and folding in the subsurface. This dataset provides three possible interpretations for the subsurface geometries of the faulting and folding present. However, producing a seismic reflection image with the higher frequency sledge-hammer sourced dataset for interpretation proved more challenging. While there are no petroleum plays in the Indio Mountains region, imaging and understanding subsurface structural and lithological geometries and how that geometry directs potential fluid flow has implications for other regions with petroleum plays.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Burwood, R.; Mycke, B.

The Lower Congo Coastal and Kwanza provinces cumulatively account for reserves of ca 6 GBOR. These are dominantly reservoired in Pinda carbonate traps of the former basin. However, with production from a range of accretionary wedge, carbonate platform and Pre-Salt reservoirs, a diversity in oil character presupposes complex hydrocarbon habitats charged by multiple sourcing. Each of these two major Atlantic margin salt basins constitutes a different, source rock driven, hydrocarbon habitat. As classic passive margin pull-apart basins, Early Cretaceous initiated rift events (Pre-rift, Synrift I, II, etc.) evolved into the Drift phase opening of the southern Atlantic. A striking featuremore » of this progression was widespread evaporate deposition of the Aptian Loeme Salt. This separates two distinct sedimentary and tectonic domains of the Pre- and Post-Salt. The core Lower Congo habitat is dominated by the Pre-Salt Bucomazi (!) petroleum system. These lacustrine, often super-rich, sediments reveal considerable organofacies variations between their basin fill (Synrift I) and sheet drape (Synrift II) development, accounting for the compositional diversity in their progenic petroleums. Of crucial impact is a cognate diversity in their kerogen kinetic behaviour. This controls the conditions and timing of generation and realization of charge potential. With the Lower Congo habitat extending southwards to the Ambriz Spur, the Bucomazi facies proper appears restricted to the northern and deeper proto-lake trend. Over the more weakly subsident margins such troughs host inferior sheet drape potential. Elsewhere, the Upper Cretaceous-Paleogene marine clastic labe (!) petroleum system is hydrocarbon productive, yielding petroleums of unique, and/or mixed Pre-Salt, source provenance.« less

Karelian shungite—an indication of 2.0-Ga-old metamorphosed oil-shale and generation of petroleum: geology, lithology and geochemistry

NASA Astrophysics Data System (ADS)

Melezhik, V. A.; Fallick, A. E.; Filippov, M. M.; Larsen, O.

1999-07-01

The ca. 2.0-Ga-old, 600-m-thick upper Zaonezhskaya Formation near Lake Onega, NW Russia, contains unusually high concentrations of C org (up to 98%), averaging around 25%. The formation contains an estimated 25×10 10 tonnes of organic carbon accumulated within an area of 9000 km 2. Organic material is represented by shungite, which forms a black, dense, amorphous or nanocrystalline mass consisting of C with traces of N, O, S, and H. Autochthonous shungite occurs as disseminated organic material (0.1-50% C org) which, when mixed with migrated bitumen (now pyrobitumen), appears as coal-like seams and lenses of semilustrous and semimat layer-shungite rocks (oil shales, 50-75% C org). The migrated bitumen (originally petroleum), represented by the lustrous vein- and layer-shungite, conformably fills interbedding spaces or cross-cutting joints and usually contains 80-98% C org. The shungite-bearing rocks of the upper Zaonezhskaya Formation represent one of the most richest accumulations of organic material reported from the Palaeoproterozoic, and one of the geologically earliest stages of petroleum generation. The sediments of the Zaonezhskaya Formation were initially deposited in brackish water in a non-euxinic, lagoonal environment. The high C/S ratio (8-1000) with a zero intercept on the C-S cross-plot indicates that deposition occurred in sulphur-poor water. Intensive synchronous volcanism may have contributed to both the enhanced delivery of nutrients and elevated sedimentation rate, and eventually to the high degree of preservation of organic material. The integrated data suggest that the organic material has a biogenic origin, most likely algal or bacterial. The organic material suffered complex catagenetic and metamorphic alteration which is reflected in: (1) the four-modal distribution of C org content (with maxima at 5, 30, 65 and 95%); (2) highly variable δ 13C org (-45‰ to -17‰); (3) bimodal distribution of δ 13C org (with maxima at -28 and -39‰); and (4) low H/C ratios (0.005-0.2). Abundant diagenetic carbonates associated with shungite rocks ( δ 13C carb=-5 to -26‰) and the presence of pyrite ( δ 34S -22 to +31‰), reflects substantial loss of organic matter via bacterial reduction of sulphate during diagenesis. The shungite rocks are characterised by a further substantial loss (>50%) of biologically produced organic material in the course of thermal maturation and by a depletion in 12C (>10‰). The isotopic composition of carbonate concretions does not indicate the involvement of fermentative diagenesis. Conservative estimates give δ13C org of -34‰ as the best value of the initial biomass. Lustrous vein- and layer-shungite containing more than 80% C org are considered to be allochthonous, migrated bitumen (originally petroleum). The semilustrous and semimat layer shungite rocks containing 55-75% C org represent oil shales with both migrated bitumen (originally petroleum) and autochthonous kerogen residues. The oil source rocks were apparently hosted in the Zaonezhskaya Formation. The generated oil has migrated both vertically and laterally with the highest concentration in cupola structures. The locality at Shunga represents the most significant volume of trapped petroleum from the study area.

Integrated exploration workflow in the south Middle Magdalena Valley (Colombia)

NASA Astrophysics Data System (ADS)

Moretti, Isabelle; Charry, German Rodriguez; Morales, Marcela Mayorga; Mondragon, Juan Carlos

2010-03-01

The HC exploration is presently active in the southern part of the Middle Magdalena Valley but only moderate size discoveries have been made up to date. The majority of these discoveries are at shallow depth in the Tertiary section. The structures located in the Valley are faulted anticlines charged by lateral migration from the Cretaceous source rocks that are assumed to be present and mature eastward below the main thrusts and the Guaduas Syncline. Upper Cretaceous reservoirs have also been positively tested. To reduce the risks linked to the exploration of deeper structures below the western thrusts of the Eastern Cordillera, an integrated study was carried out. It includes the acquisition of new seismic data, the integration of all surface and subsurface data within a 3D-geomodel, a quality control of the structural model by restoration and a modeling of the petroleum system (presence and maturity of the Cretaceous source rocks, potential migration pathways). The various steps of this workflow will be presented as well as the main conclusions in term of source rock, deformation phases and timing of the thrust emplacement versus oil maturation and migration. Our data suggest (or confirm) The good potential of the Umir Fm as a source rock. The early (Paleogene) deformation of the Bituima Trigo fault area. The maturity gap within the Cretaceous source rock between the hangingwall and footwall of the Bituima fault that proves an initial offset of Cretaceous burial in the range of 4.5 km between the Upper Cretaceous series westward and the Lower Cretaceous ones eastward of this fault zone. The post Miocene weak reactivation as dextral strike slip of Cretaceous faults such as the San Juan de Rio Seco fault that corresponds to change in the Cretaceous thickness and therefore in the depth of the thrust decollement.

Petroleum geology and resources of the Amu-Darya basin, Turkmenistan, Uzbekistan, Afghanistan, and Iran

USGS Publications Warehouse

Ulmishek, Gregory F.

2004-01-01

The Amu-Darya basin is a highly productive petroleum province in Turkmenistan and Uzbekistan (former Soviet Union), extending southwestward into Iran and southeastward into Afghanistan. The basin underlies deserts and semideserts north of the high ridges of the Kopet-Dag and Bande-Turkestan Mountains. On the northwest, the basin boundary crosses the crest of the Karakum regional structural high, and on the north the basin is bounded by the shallow basement of the Kyzylkum high. On the east, the Amu-Darya basin is separated by the buried southeast spur of the Gissar Range from the Afghan-Tajik basin, which is deformed into a series of north-south-trending synclinoria and anticlinoria. The separation of the two basins occurred during the Neogene Alpine orogeny; earlier, they were parts of a single sedimentary province. The basement of the Amu-Darya basin is a Hercynian accreted terrane composed of deformed and commonly metamorphosed Paleozoic rocks. These rocks are overlain by rift grabens filled with Upper Permian-Triassic rocks that are strongly compacted and diagenetically altered. This taphrogenic sequence, also considered to be a part of the economic basement, is overlain by thick Lower to Middle Jurassic, largely continental, coal-bearing rocks. The overlying Callovian-Oxfordian rocks are primarily carbonates. A deep-water basin surrounded by shallow shelves with reefs along their margins was formed during this time and reached its maximum topographic expression in the late Oxfordian. In Kimmeridgian-Tithonian time, the basin was filled with thick evaporites of the Gaurdak Formation. The Cretaceous-Paleogene sequence is composed chiefly of marine clastic rocks with carbonate intervals prominent in the Valanginian, Barremian, Maastrichtian, and Paleocene stratigraphic units. In Neogene time, the Alpine orogeny on the basin periphery resulted in deposition of continental clastics, initiation of new and rejuvenation of old faults, and formation of most structural traps. A single total petroleum system is identified in the Amu-Darya basin. The system is primarily gas prone. Discovered gas reserves are listed by Petroconsultants (1996) at about 230 trillion cubic feet, but recent discoveries and recent reserve estimates in older fields should increase this number by 40 to 50 trillion cubic feet. Reserves of liquid hydrocarbons (oil and condensate) are comparatively small, less than 2 billion barrels. Most of the gas reserves are concentrated in two stratigraphic intervals, Upper Jurassic carbonates and Neocomian clastics, each of which contains about one-half of the reserves. Reserves of other stratigraphic units?from Middle Jurassic to Paleogene in age?are relatively small. Source rocks for the gas are the Lower to Middle Jurassic clastics and coal and Oxfordian basinal black shales in the east-central part of the basin. The latter is probably responsible for the oil legs and much of the condensate in gas pools. Throughout most of the basin both source-rock units are presently in the gas-window zone. Traps are structural, paleogeomorphic, and stratigraphic, as well as a combination of these types. The giant Dauletabad field is in a combination trap with an essential hydrodynamic component. Four assessment units were identified in the total petroleum system. One unit in the northeastern, northern, and northwestern marginal areas of the basin and another in the southern marginal area are characterized by wide vertical distribution of hydrocarbon pools in Middle Jurassic to Paleocene rocks and the absence of the salt of the Gaurdak Formation. The other two assessment units are stratigraphically stacked; they occupy the central area of the basin and are separated by the regional undeformed salt seal of the Gaurdak Formation. The largest part of undiscovered hydrocarbon resources of the Amu-Darya basin is expected in older of these assessment units. The mean value of total assessed resources of the Amu-Darya basin is estimated

Madbi Amran/Qishn total petroleum system of the Ma'Rib-Al Jawf/Shabwah, and Masila-Jeza basins, Yemen

USGS Publications Warehouse

Ahlbrandt, Thomas S.

2002-01-01

Since the first discovery of petroleum in Yemen in 1984, several recent advances have been made in the understanding of that countrys geologic history and petroleum systems. The total petroleum resource endowment for the combined petroleum provinces within Yemen, as estimated in the recent U.S. Geological Survey world assessment, ranks 51st in the world, exclusive of the United States, at 9.8 BBOE, which includes cumulative production and remaining reserves, as well as a mean estimate of undiscovered resources. Such undiscovered petroleum resources are about 2.7 billion barrels of oil, 17 trillion cubic feet (2.8 billion barrels of oil equivalent) of natural gas and 1 billion barrels of natural gas liquids. A single total petroleum system, the Jurassic Madbi Amran/Qishn, dominates petroleum generation and production; it was formed in response to a Late Jurassic rifting event related to the separation of the Arabian Peninsula from the Gondwana supercontinent. This rifting resulted in the development of two petroleum-bearing sedimentary basins: (1) the western MaRibAl Jawf / Shabwah basin, and (2) the eastern Masila-Jeza basin. In both basins, petroleum source rocks of the Jurassic (Kimmeridgian) Madbi Formation generated hydrocarbons during Late Cretaceous time that migrated, mostly vertically, into Jurassic and Cretaceous reservoirs. In the western MaRibAl Jawf / Shabwah basin, the petroleum system is largely confined to syn-rift deposits, with reservoirs ranging from deep-water turbidites to continental clastics buried beneath a thick Upper Jurassic (Tithonian) salt. The salt initially deformed in Early Cretaceous time, and continued halokinesis resulted in salt diapirism and associated salt withdrawal during extension. The eastern Masila-Jeza basin contained similar early syn-rift deposits but received less clastic sediment during the Jurassic; however, no salt formed because the basin remained open to ocean circulation in the Late Jurassic. Thus, Madbi Formation-sourced hydrocarbons migrated vertically into Lower Cretaceous estuarine, fluvial, and tidal sandstones of the Qishn Formation and were trapped by overlying impermeable carbonates of the same formation. Both basins were formed by extensional forces during Jurassic rifting; how-ever, another rifting event that formed the Red Sea and Gulf of Aden during Oligocene and Miocene time had a strong effect on the eastern Masila-Jeza basin. Recurrent movement of basement blocks, particularly during the Tertiary, rather than halokinesis, was critical to the formation of traps.

Modeling of gas generation from the Barnett Shale, Fort Worth Basin, Texas

USGS Publications Warehouse

Hill, R.J.; Zhang, E.; Katz, B.J.; Tang, Y.

2007-01-01

The generative gas potential of the Mississippian Barnett Shale in the Fort Worth Basin, Texas, was quantitatively evaluated by sealed gold-tube pyrolysis. Kinetic parameters for gas generation and vitrinite reflectance (Ro) changes were calculated from pyrolysis data and the results used to estimate the amount of gas generated from the Barnett Shale at geologic heating rates. Using derived kinetics for Ro evolution and gas generation, quantities of hydrocarbon gas generated at Ro ??? 1.1% are about 230 L/t (7.4 scf/t) and increase to more that 5800 L/t (186 scf/t) at Ro ??? 2.0% for a sample with an initial total organic carbon content of 5.5% and Ro = 0.44%. The volume of shale gas generated will depend on the organic richness, thickness, and thermal maturity of the shale and also the amount of petroleum that is retained in the shale during migration. Gas that is reservoired in shales appears to be generated from the cracking of kerogen and petroleum that is retained in shales, and that cracking of the retained petroleum starts by Ro ??? 1.1%. This result suggests that the cracking of petroleum retained in source rocks occurs at rates that are faster than what is predicted for conventional siliciclastic and carbonate reservoirs, and that contact of retained petroleum with kerogen and shale mineralogy may be a critical factor in shale-gas generation. Shale-gas systems, together with overburden, can be considered complete petroleum systems, although the processes of petroleum migration, accumulation, and trap formation are different from what is defined for conventional petroleum systems. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

Documenting mudstone heterogeneity by use of principal component analysis of X-ray diffraction and portable X-ray fluorescence data: A case study in the Triassic Shublik Formation, Alaska North Slope

USGS Publications Warehouse

Boehlke, Adam; Whidden, Katherine J.; Benzel, William M.

2017-01-01

Determining the chemical and mineralogical variability within fine-grained mudrocks poses analytical challenges but is potentially useful for documenting subtle stratigraphic differences in physicochemical environments that may influence petroleum reservoir properties and behavior. In this study, we investigate the utility of combining principal component analysis (PCA) of X-ray diffraction (XRD) data and portable X-ray fluorescence (pXRF) data to identify simplifying relationships within a large number of samples and subsequently evaluate a subset that encompasses the full spectrum or range of mineral and chemical variability within a vertical section. Samples were collected and analyzed from a vertical core of the Shublik Formation, a heterogeneous, phosphate-rich, calcareous mudstone-to-marl unit deposited in the Arctic Alaska Basin (AAB) during the Middle and Late Triassic. The Shublik is a major petroleum source rock in the Alaskan North Slope, and is considered a prime target for continuous self-sourced resource plays.

Geologic assessment of undiscovered hydrocarbon resources of the Western Oregon and Washington Province

USGS Publications Warehouse

,; Brownfield, Michael E.; Charpentier, Ronald R.; Cook, Troy A.; Klett, Timothy R.; Pollastro, Richard M.; Schenk, Christopher J.; Le, P.A.; ,

2011-01-01

The purpose of the U.S. Geological Survey (USGS) National Oil and Gas Assessment is to develop geology-based hypotheses regarding the potential for additions to oil and gas reserves in priority areas of the United States, focusing on the distribution, quantity, and availability of oil and natural gas resources. The USGS has completed an assessment of the undiscovered, technically recoverable oil and gas resources in western Oregon and Washington (USGS Western Oregon and Washington Province 5004). The province includes all of Oregon and Washington north of the Klamath Mountains and west of the crest of the Cascade Range, and extends offshore to the 3-mi limit of State waters on the west and to the International Boundary in the Straits of Juan de Fuca and Canada on the north. It measures about 450 mi north-south and 50 to 160 mi east-west, encompassing more than 51,000 mi2. The assessment of the Western Oregon and Washington Province is geology based and used the total petroleum system (TPS) concept. The geologic elements of a TPS include hydrocarbon source rocks (source rock maturation and hydrocarbon generation and migration), reservoir rocks (quality and distribution), and traps for hydrocarbon accumulation. Using these geologic criteria, two conventional and one unconventional (continuous) total petroleum systems were defined, with one assessment unit (AU) in each TPS: (1) the Cretaceous-Tertiary Composite TPS and the Western Oregon and Washington Conventional Gas AU, (2) the Tertiary Marine TPS and the Tertiary-Marine Gas AU, and (3) the Tertiary Coalbed Gas TPS and the Eocene Coalbed Gas AU, in which a cell-based methodology was used to estimate coalbed-gas resources.

Giant fields of the late 80s associated with type [open quotes]A[close quotes] subduction in South America

DOE Office of Scientific and Technical Information (OSTI.GOV)

Duval, B.; Cramez, C.; Figuera, J.

1993-02-01

About 10 billion bbl of recoverable oil have been found in these three fields for which the petroleum generating subsystem is very similar. The potential source rocks are the organic sediments associated with the major downlap surface of the post-Pangea continental encroachment sedimentary cycle, i.e., MFS 91, 5 Ma (La Luna formation). However, the concentrating physico-chemical petroleum subsystem is quite different. The El Furrial/Musipan field is associated with a Tertiary foredeep basin overlying a generating Atlantic type passive margin. On the other hand, Cusiana and Ceuta fields are associated with a Tertiary foredeep basin developed over a generating back-arc basin.more » The different stacking of sedimentary basins controls the migration/entrapment petroleum subsystem. In El Furrial/Musipan, decollement surfaces and their associated thrusts are predominant whereas, in Ceuta and Cusiana the majority of compressional structures are created by tectonic inversions. These tectonic settings create different petroleum systems: (a) supercharged with low impedance and lateral drainage in El Furrial/Musipan, (b) normally charged with high impedance and vertically drained in Ceuta and Cusiana area. Each case requires appropriated exploration approaches.« less

Generation and migration of Bitumen and oil from the oil shale interval of the Eocene Green River formation, Uinta Basin, Utah

USGS Publications Warehouse

Johnson, Ronald C.; Birdwell, Justin E.; Mercier, Tracey J.

2016-01-01

The results from the recent U.S. Geological Survey assessment of in-place oil shale resources of the Eocene Green River Formation, based primarily on the Fischer assay method, are applied herein to define areas where the oil shale interval is depleted of some of its petroleum-generating potential along the deep structural trough of the basin and to make: (1) a general estimates of the amount of this depletion, and (2) estimate the total volume of petroleum generated. Oil yields (gallons of oil per ton of rock, GPT) and in-place oil (barrels of oil per acre, BPA) decrease toward the structural trough of the basin, which represents an offshore lacustrine area that is believed to have originally contained greater petroleum-generating potential than is currently indicated by measured Fischer assay oil yields. Although this interval is considered to be largely immature for oil generation based on vitrinite reflectance measurements, the oil shale interval is a likely source for the gilsonite deposits and much of the tar sands in the basin. Early expulsion of petroleum may have occurred due to the very high organic carbon content and oil-prone nature of the Type I kerogen present in Green River oil shale. In order to examine the possible sources and migration pathways for the tar sands and gilsonite deposits, we have created paleogeographic reconstructions of several oil shale zones in the basin as part of this study.

Sedimentary modeling and analysis of petroleum system of the upper Tertiary sequences in southern Ulleung sedimentary Basin, East Sea (Sea of Japan)

NASA Astrophysics Data System (ADS)

Cheong, D.; Kim, D.; Kim, Y.

2010-12-01

The block 6-1 located in the southwestern margin of the Ulleung basin, East Sea (Sea of Japan) is an area where recently produces commercial natural gas and condensate. A total of 17 exploratory wells have been drilled, and also many seismic explorations have been carried out since early 1970s. Among the wells and seismic sections, the Gorae 1 well and a seismic section through the Gorae 1-2 well were chosen for this simulation work. Then, a 2-D graphic simulation using SEDPAK elucidates the evolution, burial history and diagenesis of the sedimentary sequence. The study area is a suitable place for modeling a petroleum system and evaluating hydrocarbon potential of reservoir. Shale as a source rock is about 3500m deep from sea floor, and sandstones interbedded with thin mud layers are distributed as potential reservoir rocks from 3,500m to 2,000m deep. On top of that, shales cover as seal rocks and overburden rocks upto 900m deep. Input data(sea level, sediment supply, subsidence rate, etc) for the simulation was taken from several previous published papers including the well and seismic data, and the thermal maturity of the sediment was calculated from known thermal gradient data. In this study area, gas and condensate have been found and commercially produced, and the result of the simulation also shows that there is a gas window between 4000m and 6000m deep, so that three possible interpretations can be inferred from the simulation result. First, oil has already moved and gone to the southeastern area along uplifting zones. Or second, oil has never been generated because organic matter is kerogen type 3, and or finally, generated oil has been converted into gas by thermally overcooking. SEDPAK has an advantage that it provides the timing and depth information of generated oil and gas with TTI values even though it has a limit which itself can not perform geochemical modeling to analyze thermal maturity level of source rocks. Based on the result of our simulation, added exploratory wells are required to discover deeper gas located in the study area.

Geologic Cross Section E-E' through the Appalachian Basin from the Findlay Arch, Wood County, Ohio, to the Valley and Ridge Province, Pendleton County, West Virginia

USGS Publications Warehouse

Ryder, Robert T.; Swezey, Christopher S.; Crangle, Robert D.; Trippi, Michael H.

2008-01-01

Geologic cross section E-E' is the first in a series of cross sections planned by the U.S. Geological Survey (USGS) to document and improve understanding of the geologic framework and petroleum systems of the Appalachian basin. Cross section E-E' provides a regional view of the structural and stratigraphic framework of the basin from the Findlay arch in northwestern Ohio to the Valley and Ridge province in eastern West Virginia, a distance of approximately 380 miles (mi) (fig. 1, on sheet 1). Cross section E-E' updates earlier geologic cross sections through the central Appalachian basin by Renfro and Feray (1970), Bennison (1978), and Bally and Snelson (1980) and a stratigraphic cross section by Colton (1970). Although other published cross sections through parts of the basin show more structural detail (for example, Shumaker, 1985; Kulander and Dean, 1986) and stratigraphic detail (for example, Ryder, 1992; de Witt and others, 1993; Hettinger, 2001), these other cross sections are of more limited extent geographically and stratigraphically. Although specific petroleum systems in the Appalachian basin are not identified on the cross section, many of their key elements (such as source rocks, reservoir rocks, seals, and traps) can be inferred from lithologic units, unconformities, and geologic structures shown on the cross section. Other aspects of petroleum systems (such as the timing of petroleum generation and preferred migration pathways) may be evaluated by burial history, thermal history, and fluid flow models based on information shown on the cross section. Cross section E-E' lacks the detail to illustrate key elements of coal systems (such as paleoclimate, coal quality, and coal rank), but it does provide a general framework (stratigraphic units and general rock types) for the coal-bearing section. Also, cross section E-E' may be used as a reconnaissance tool to identify plausible geologic structures and strata for the subsurface storage of liquid waste (for example, Colton, 1961; Lloyd and Reid, 1990) or for the sequestration of carbon dioxide (for example, Smith and others, 2002; Lucier and others, 2006).

The origin of gas seeps and shallow gas in northern part of South China Sea

NASA Astrophysics Data System (ADS)

Li, M.; Jin, X.

2003-04-01

The northern part of South China Sea is of passive continental margin, which geologic units include shelf, slope and deep sea basin. There are rifting basins forming during Paleogene (or Cretaceous ?) to Quaternary developed on shelf and slope, which sediments are dominated by fluvial and lake clastic rock of Paleogene, and marine clastic rock and carbonate of Neogene - Quaternary. The main basins include the Pearl River Mouth Basin, Beibu Gulf basin, Qiongdongnan Basin and Yinggehai basin. They contain rich oil and gas resources, and have become important industrial oil and gas producing region in South China Sea. With the increasing of petroleum exploration actives and marine petroleum engineering, it has been paid more attention to the investigation and research of gas seeps and shallow gas, for they become a potential threaten to the marine engineering while they are regarded as the indicators of industrial oil and gas. By study the distribution and geochemical characteristics of gas seeps in northeast part of Yinggehai basin and shallow gas in sediments on slope, combined with their regional geologic background, this paper deals with the origin, migration pathway and emission mechanism of gas seeps and shallow gas in northern part of South China Sea, for providing a base knowledge for the evaluation of marine engineering geology. In northeast part of Yinggehai basin gas seeps have been found and recorded for near 100 years. During 1990s, as a part of petroleum exploration, the gas seeps in the basin have been investigated and research by oil companies (Baojia Huang et al., 1992; Jiaqiong He et al., 2000). Gas seeps were found in shallow water area along southwest coast of Hainan Island, water depth usually less than 50 m. The occurrence of gas seeps can be divided into two types: (1) gas continuously emission, continuous gas bubbles groups can be detected by sonar underwater and observed on water surface. (2) gas intermittently emission, the time intervals vary in different places. Gas chimneys can be found on seafloor, which show blank zone on seismic profiles, locally with pit holes. The geochemical analyses of gas samples from gas seeps indicate its composition is dominated by hydrocarbon gas, the other include CO_2, N_2 and O_2. The gas has high dry index, and heavier δ13C_1.This shows that the gas is of matured- over matured thermogenic gas. The geochemical characteristics of extracts from sediments in the area are similar to those of penetrated source rock of Neogene in the basin, indicating the gas is from the matured source rock in the basin, the diapric zone and fault act as the migration pathway. The gas samples on slope were obtained through degasification of sediments collected by SONNE. Geochemical analyses show that the gas composition is dominated by methane, with high dry index and heavier δ13C_1, belonging to typical thermogenic gas. On maturity chart, the gas samples on upper slope fall in the area near the boundary of condensate, indicating higher maturity, while those on lower slope has lower maturity and fall in the area near oil window. The gas samples from deep sea basin is mixed gas of thermogenic gas and biogas. Therefore, it is reasonable to consider the deep buried source rock as the origin of the gas, and the active faults are the migration pathway. As stated above, the gas seeps and shallow gas in northern part of South China Sea were mainly originated from deep buried source rock, migrated through diapric zone or active faults. Their distribution and occurrence have directly relation with the source rock type and maturity, and the tectonic active of the underlying basins. The petroleum exploration has proved that Yinggehai basin and Qiongdongnan basin on the western part are favored for gas generation, while the Pearl River Mouth Basin and Beibu Gulf basin on the eastern part are favored for oil generation. This may account for the distribution of gas seeps which concentrated in the Yinggehai basin. Therefore, an effective and practical evaluation of the potential dangers of gas for marine engineering need to consider the regional geologic background. This study is financially supported by the National Major Fundamental Research and Development Project (No. G20000467). Reference Baojia Huang et al. 1992 Investigation and Origin of Oil-Gas Seepages in the Yinggehai Sea, China Offshore Oil and Gas (Geology), 1992,6(4): 1-7. Jiaxiong He et al. 2000 The Distribution of Oil-Gas Seeps in northern slope of Yinggehai Basin and the Analyses of Petroleum exploration prospect in the Basin, Natural Gas Geoscience Vol. 11, No.2, 1-9. Xianglong Jin et al. 1989 Research Report on Geoscience of South China Sea, Donghai Marine Science Vol. 7, No.4, 1-92.

Basement geology of the National Petroleum Reserve Alaska (NPRA), Northern Alaska

USGS Publications Warehouse

Saltus, R.W.; Hudson, T.L.; Phillips, J.D.; Kulander, C.; Dumoulin, Julie A.; Potter, C.

2002-01-01

Gravity, aeromagnetic, seismic, and borehole information enable mapping of crustal basement characteristics within the National Petroleum Reserve Alaska (NPRA). In general, the pre-Mississippian basement of the southern portion of the NPRA is different from that in the north in that it is deeper and thinner, is made up of dense magnetic rocks, is cut by more normal faults, and underlies thicker accumulations of Mississippian to Triassic Ellesmerian sequence sedimentary rocks. Mafic igneous rocks within the basement and locally within the deeper Ellesmerian sequence sedimentary section could explain the observed density and magnetic variations. Because these variations spatially overlap thicker Ellesmerian sequence sediment accumulations, they may have developed, at least in part, during Mississippian to Triassic extension and basin formation. If this period of extension, and postulated mafic magmatism, was accompanied by higher heat flow, then early Ellesmerian sequence clastic sediments may have become mature for hydrocarbon generation (Magoon and Bird, 1988). This could have produced an early petroleum system in the Colville basin.

A new perspective of particle adsorption: Dispersed oil and granular materials interactions in simulated coastal environment.

PubMed

Meng, Long; Bao, Mutai; Sun, Peiyan

2017-09-15

This study, adsorption behaviors of dispersed oil in seawaters by granular materials were explored in simulation environment. We quantitatively demonstrated the dispersed oil adsorbed by granular materials were both dissolved petroleum hydrocarbons (DPHs) and oil droplets. Furthermore, DPHs were accounted for 42.5%, 63.4%, and 85.2% (35.5% was emulsion adsorption) in the adsorption of dispersed oil by coastal rocks, sediments, and bacterial strain particles respectively. Effects of controlling parameters, such as temperature, particle size and concentration on adsorption of petroleum hydrocarbons were described in detail. Most strikingly, adsorption concentration was followed a decreasing order of bacterial strain (0.5-2μm)>sediments (0.005-0.625mm)>coastal rocks (0.2-1cm). With particle concentration or temperature increased, adsorption concentration increased for coastal rocks particle but decreased for sediments particle. Besides, particle adsorption rate of petroleum hydrocarbons (n-alkanes and PAHs) was different among granular materials during 60 days. Copyright © 2017 Elsevier Ltd. All rights reserved.

Hydrocarbon generation and expulsion in shale Vs. carbonate source rocks

DOE Office of Scientific and Technical Information (OSTI.GOV)

Leythaeuser, D.; Krooss, B.; Hillebrand, T.

1993-09-01

For a number of commercially important source rocks of shale and of carbonate lithologies, which were studied by geochemical, microscopical, and petrophysical techniques, a systematic comparison was made of the processes on how hydrocarbon generation and migration proceed with maturity progress. In this way, several fundamental differences between both types of source rocks were recognized, which are related to differences of sedimentary facies and, more importantly, of diagenetic processes responsible for lithification. Whereas siliciclastic sediments lithify mainly by mechanical compaction, carbonate muds get converted into lithified rocks predominantly by chemical diagenesis. With respect to their role as hydrocarbon source rocks,more » pressure solution processes appear to be key elements. During modest burial stages and prior to the onset of hydrocarbon generation reactions by thermal decomposition of kerogen, pressure solution seams and stylolites. These offer favorable conditions for hydrocarbon generation and expulsion-a three-dimensional kerogen network and high organic-matter concentrations that lead to effective saturation of the internal pore fluid system once hydrocarbon generation has started. As a consequence, within such zones pore fluids get overpressured, leading ultimately to fracturing. Petroleum expulsion can then occur at high efficiencies and in an explosive fashion, whereby clay minerals and residual kerogen particles are squeezed in a toothpaste-like fashion into newly created fractures. In order to elucidate several of the above outlined steps of hydrocarbon generation and migration processes, open-system hydrous pyrolysis experiments were performed. This approach permits one to monitor changes in yield and composition of hydrocarbon products generated and expelled at 10[degrees]C temperature increments over temperature range, which mimics in the laboratory the conditions prevailing in nature over the entire liquid window interval.« less

Publications - GMC 13 | Alaska Division of Geological & Geophysical Surveys

Science.gov Websites

DGGS GMC 13 Publication Details Title: Total organic carbon, rock-eval pyrolysis and vitrinite information. Bibliographic Reference Phillips Petroleum Company, 1983, Total organic carbon, rock-eval K) Keywords Pyrolysis; Rock-Eval Pyrolysis; Total Organic Carbon; Vitrinite Reflectance Top of Page

Significant role of structural fractures in Ren-Qiu buried-block oil field, eastern China

DOE Office of Scientific and Technical Information (OSTI.GOV)

Fei, Q.; Xie-Pei, W.

1983-03-01

Ren-qui oil field is in a buried block of Sinian (upper Proterozoic) rocks located in the Ji-zhong depression of the western Bohai Bay basin in eastern China. The main reservoir consists of Sinian dolomite rocks. It is a fault block with a large growth fault on the west side which trends north-northeast with throws of up to 1 km (0.6 mi) or more. The source rocks for the oil are Paleogene age and overlie the Sinian dolomite rocks. The structural fractures are the main factor forming the reservoir of the buried-block oil field. Three structural lines, trending northeast, north-northeast, andmore » northwest, form the regional netted fracture system. The north-northeast growth fault controlled the structural development of the buried block. The block was raised and eroded before the Tertiary sediments were deposited. In the Eocene Epoch, the Ji-zhong depression subsided, but the deposition, faulting, and related uplift of the block happened synchronously as the block was gradually submerged. At the same time, several horizontal and vertical karst zones were formed by the karst water along the netted structural fractures. The Eocene oil source rocks lapped onto the block and so the buried block, with many developed karst fractures, was surrounded by a great thickness of source rocks. As the growth fault developed, the height of the block was increased from 400 m (1300 ft) before the Oligocene to 1300 m (4250 ft) after. As the petroleum was generated, it migrated immediately into the karst fractures of the buried block along the growth fault. The karst-fractured block reservoir has an 800-m (2600-ft) high oil-bearing closure and good connections developed between the karst fractures.« less

Regional Stratigraphy and Petroleum Systems of the Illinois Basin, U.S.A.

USGS Publications Warehouse

Swezey, Christopher S.

2009-01-01

The publication combines data on Paleozoic and Mesozoic stratigraphy and petroleum geology of the Illinois basin, U.S.A., in order to facilitate visualizing the stratigraphy on a regional scale and visualizing stratigraphic relations within the basin. Data are presented in eight schematic chronostratigraphic sections arranged approximately from north to south, with time denoted in equal increments along the sections, in addition to the areal extent of this structural basin. The stratigraphic data are modified from Hass (1956), Conant and Swanson (1961), Wilman and others (1975), American Association of Petroleum Geologists (1984, 1986), Olive and McDowell (1986), Shaver and others (1986), Thompson (1986), Mancini and others (1996), and Harrison and Litwin (1997). The time scale is taken from Gradstein and others (2004). Additional stratigraphic nomenclature is from Harland and others (1990), Babcock and others (2007), and Bergstrom and others (2008). Stratigraphic sequences as defined by Sloss (1963, 1988) and Wheeler (1963) also are included, as well as the locations of major petroleum source rocks and major petroleum plays. The stratigraphic units shown are colored according to predominant lithology, in order to emphasize general lithologic patterns and to provide a broad overview of the Illinois basin. For the purpose of comparison, three columns on the right show schematic depictions of stratigraphy and interpreted events in the Illinois basin and in the adjacent Michigan and Appalachian basins.

Neogene Gas Total Petroleum System -- Neogene Nonassociated Gas Assessment Unit of the San Joaquin Basin Province: Chapter 22 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Hosford Scheirer, Allegra; Magoon, Leslie B.

2009-01-01

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

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

USGS Publications Warehouse

Wandrey, Craig J.

2004-01-01

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

Petroleum systems used to determine the assessment units in the San Joaquin Basin Province, California: Chapter 8 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Magoon, Leslie B.; Lillis, Paul G.; Peters, Kenneth E.

2009-01-01

The figures and tables for each petroleum system and TPS are as follows: (1) the San Joaquin(?) petroleum system or the Neogene Nonassociated Gas TPS is a natural gas system in the southeast part of the province (figs. 8.3 through 8.8; table 8.5; this volume, chapter 22); (2) the Miocene TPS (this volume, chapters 13, 14, 15, 16, and 17) includes the McLure-Tulare(!) petroleum system north of the Bakersfield Arch (figs. 8.9 through 8.13; table 8.6), and the Antelope-Stevens(!) petroleum system south of the arch (figs. 8.14 through 8.18; table 8.7), and is summarized in figure 8.19; (3) the Eocene TPS (this volume, chapters 18 and 19) combines two petroleum systems, the Tumey-Temblor(.) covering much of the province (figs. 8.20 through 8.24; table 8.8) and the underlying Kreyenhagen-Temblor(!) (figs. 8.25 through 8.29: table 8.9), and is summarized in figure 8.30; (4) the Eocene-Miocene Composite TPS, formed by combining the Miocene and Eocene TPS (this volume, chapter 20); and (5) the Moreno-Nortonville(.) is both a petroleum system and a TPS consisting mainly of natural gas in the northern part of the province (figs. 8.31 through 8.36: table 8.10; this volume, chapter 21). Oil samples with geochemistry from surface seeps and wells used to map these petroleum systems are listed in table 8.11. Finally, the volume of oil and gas expelled by each pod of active source rock was calculated and compared with the discovered hydrocarbons in each petroleum system (figs. 8.37 through 8.39; tables 8.12 and 8.13).

New insights into the stratigraphic, paleogeographic and tectonic evolution and petroleum potential of Kerkennah Islands, Eastern Tunisia

NASA Astrophysics Data System (ADS)

Elfessi, Maroua

2017-01-01

This work presents general insights into the stratigraphic and paleogeographic evolution as well as the structural architecture and the petroleum potential of Kerkennah Islands, located in the Eastern Tunisia Foreland, from Cenomanian to Pliocene times. Available data from twenty wells mostly drilled in Cercina and Chergui fields are used to establish three lithostratigraphic correlations as well as isopach and isobath maps in order to point out thickness and depth variations of different geological formations present within our study area; in addition to a synthetic log and isoporosity map of the main carbonate reservoir (the nummulites enriched Reineche Member). The integrated geological study reveals relatively condensed but generally continuous sedimentation and a rugged substrate with horsts, grabens and tilted blocks due to the initiation and the individualization of Kerkennah arch throughout the studied geological times. Furthermore, a relationship was highlighted between the evolution of our study zone and those of Sirt basin, Western Mediterranean Sea and Pelagian troughs; this relationship is due to the outstanding location of Kerkennah Islands. The main Bou Dabbous source rock is thicker and more mature within the central-east of the Gulf of Gabes indicating therefore the southeast charge of Reineche reservoir which shows NW-SE trending tilted block system surrounded by normal faults representing the hydrocarbon migration pathways. Besides, the thick Oligo-Miocene formations deposited during the collapse of the Pelagian block caused the maturation of the Ypresian source rock, while the Pliocene unconformity allowed basin inversion and hydrocarbon migration.

Chapter 27: Geology and petroleum potential of the north and east margins of the Siberian Craton, north of the Arctic Circle

USGS Publications Warehouse

Klett, T.R.; Wandrey, C.J.; Pitman, Janet K.

2011-01-01

The Siberian Craton consists of crystalline rocks and superimposed Precambrian sedimentary rocks deposited in rift basins. Palaeozoic rocks, mainly carbonates, were deposited along the margins of the craton to form an outwardly younger concentric pattern that underlies an outward-thickening Mesozoic sedimentary section. The north and east margins of the Siberian Craton subsequently became foreland basins created by compressional deformation during collision with other tectonic plates. The Tunguska Basin developed as a Palaeozoic rift/sag basin over Proterozoic rifts. The geological provinces along the north and east margins of the Siberian Craton are immature with respect to exploration, so exploration-history analysis alone cannot be used for assessing undiscovered petroleum resources. Therefore, other areas from around the world having greater petroleum exploration maturity and similar geological characteristics, and which have been previously assessed, were used as analogues to aid in this assessment. The analogues included those of foreland basins and rift/sag basins that were later subjected to compression. The US Geological Survey estimated the mean undiscovered, technically recoverable conventional petroleum resources to be approximately 28 billion barrels of oil equivalent, including approximately 8 billion barrels of crude oil, 103 trillion cubic feet of natural gas and 3 billion barrels of natural gas liquids. ?? 2011 The Geological Society of London.

Lisburne Group (Mississippian and Pennsylvanian), potential major hydrocarbon objective of Arctic Slope, Alaska

USGS Publications Warehouse

Bird, Kenneth J.; Jordan, Clifton F.

1977-01-01

The Lisburne Group, a thick carbonate-rock unit of Mississippian and Pennsylvanian age, is one of the most widespread potential reservoir-rock units in northern Alaska. A comprehensive review of the Lisburne in the subsurface of the eastern Arctic Slope indicates attractive reservoir characteristics in a favorable source and migration setting where numerous trapping mechanisms appear to be available. Evaluation of this group as a potential exploration objective is particularly timely because of impending offshore sales in the Beaufort Sea and current exploration programs under way in the Prudhoe Bay area and the Naval Petroleum Reserve. Dolomite and sandstone have been identified as reservoir rocks. Oolitic grainstone is a common rock type, but observations indicate little reservoir potential owing to complete void filling by calcite cement. The most important reservoir rock as judged by thickness, areal extent, and predictability is microsucrosic (10 to 30µ) dolomite of intertidal to supratidal origin. It is present throughout the Lisburne and is most abundant near the middle of the sequence. Northward it decreases in thickness from 1,000 ft (300 m) to less than 100 ft (30 m). Porosity of the dolomite as determined in selected wells averages between 10 and 15% and attains a maximum of slightly more than 25%. Net thickness of reservoir rocks (i.e., rocks with greater than 5% porosity) ranges in these wells from 40 to 390 ft (40 to 120 m). Oil shows are common, and drill-stem tests have yielded as much as 1,600 bbl/day of oil and 22 MMcf/day of gas in the Lisburne pool of the Prudhoe Bay field and as much as 2,057 bbl/day of salt water outside the field area. The occurrence of dolomite over such a large area makes its presence in the offshore Beaufort Sea and adjacent Naval Petroleum Reserve 4 fairly certain. The presence of sandstone as thick as 140 ft (40 m) in the middle and upper part of the Lisburne in two coastal wells suggests that larger areas of sandstone may be found on the north in offshore areas. Shows of oil and gas and a saltwater flow of 1,470 bbl/day have been recorded from this sandstone facies. Shales of Permian and Cretaceous ages unconformably overlie the Lisburne, providing adequate sealing beds above potential reservoirs. Impermeable limestone (completely cemented grainstone) and thin beds of shale may serve as seals within the Lisburne, but the possibility of fractures in these units may negate their sealing capability. The most favorable source rock for Lisburne hydrocarbons appears to be Cretaceous shale that unconformably overlies the Lisburne east of Prudhoe Bay. This shale is reported to be a rich source rock and is the most likely source for the entire Prudhoe Bay field. A source within the Lisburne or within the underlying Kayak Shale is postulated for oil shows in the southernmost Lisburne wells. This postulated source may be in a more basinal facies of the Lisburne and may be similar to dark shale in the upper Lisburne in thrust slices to dark shale in the upper Lisburne in thrust slices in the Brooks Range. Coal in the underlying Endicott Group is a possible source for dry gas. At present, much of this coal probably is in a gas-generating regime downdip from the Prudhoe Bay field. Stratigraphic traps involving the Lisburne Group may have resulted from widespread Permian and Cretaceous unconformities. Structural traps related to normal faulting may be present along the trend of the Barrow arch, and faulted anticlines are numerous in the foothills of the Brooks Range. Combination traps are possible along the trend of the Barrow arch.

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

USGS Publications Warehouse

Whidden, Katherine J.; Lillis, Paul G.; Anna, Lawrence O.; Pearson, Krystal M.; Dubiel, Russell F.

2014-01-01

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.

Geochemistry characterization, biomarker and determination of correlation, maturity of petroleum from Bangko-Rohil and Duri Bengkalis, Riau

NASA Astrophysics Data System (ADS)

Tamboesai, Emrizal Mahidin

2017-11-01

Petroleum is the main source of the energy for industry, transportation. Thedemand for crude oil in Indonesia is much higher than its production which leads to current energy crisis. One of solutions for this crisis is to conduct correlation study, which determines the genetic relationship at each oil well. This study is aimed to provide the indication of the genetic relationship (source matter, source rock and the origins) of Bangko and Duri crude oil. The saturated fraction was analyzed using Gas Chromatography (GC). On the basis of the abundance of hydrocarbon aliphatic, the crude oils samples have small ratio value, which is 0,38-0,50 forPr/n-C17 and 0,16-0,18Ph/n-C18. This values indicated that the samples were originated from higher vascular plants (terrestrial). The samples derived from lacustrine environments (lake) have ratio valueof Pr/Ph (2,50-2,90). The calculation from Star diagram have showed that the oil samples in area MB-07, MB-076 dan MB-172 of Bangko with the oil sample in Duri (MD-01) are negatively correlated. The negative correlation indicated that the oil samples have different the genetic relationship source matter and different in enhance oil recovery.

Middle Tertiary stratigraphic sequences of the San Joaquin Basin, California: Chapter 6 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Johnson, Cari L.; Graham, Stephan A.

2007-01-01

An integrated database of outcrop studies, borehole logs, and seismic-reflection profiles is used to divide Eocene through Miocene strata of the central and southern San Joaquin Basin, California, into a framework of nine stratigraphic sequences. These third- and higher-order sequences (<3 m.y. duration) comprise the principal intervals for petroleum assessment for the basin, including key reservoir and source rock intervals. Important characteristics of each sequence are discussed, including distribution and stratigraphic relationships, sedimentary facies, regional correlation, and age relations. This higher-order stratigraphic packaging represents relatively short-term fluctuations in various forcing factors including climatic effects, changes in sediment supply, local and regional tectonism, and fluctuations in global eustatic sea level. These stratigraphic packages occur within the context of second-order stratigraphic megasequences, which mainly reflect long-term tectonic basin evolution. Despite more than a century of petroleum exploration in the San Joaquin Basin, many uncertainties remain regarding the age, correlation, and origin of the third- and higher-order sequences. Nevertheless, a sequence stratigraphic approach allows definition of key intervals based on genetic affinity rather than purely lithostratigraphic relationships, and thus is useful for reconstructing the multiphase history of this basin, as well as understanding its petroleum systems.

Strike-slip structural styles and petroleum system evolution, northeast Sakhalin Island

DOE Office of Scientific and Technical Information (OSTI.GOV)

Meisling, K.E.; Wagner, J.B.

1996-12-31

The primary petroleum system of northeast Sakhalin Island and adjacent shelfal areas is comprised of a system of Late Miocene to Quaternary faulted transpressional anticlines that trap oil and gas in Early Miocene to Pliocene deltaic reservoirs sourced from Late Oligocene to Early Miocene diatomaceous shales. Existing production has been limited to onshore anticlines, and offshore structural trends remain undeveloped, despite several discoveries. The regional tectonic evolution of Sakhalin Island can be divided into five major phases: (1) Late Cretaceous to Early Eocene subduction, (2) Middle-Eocene collision and uplift, (3) Late Eocene to Early Oligocene oblique rifting, (4) Late Oligocenemore » to Middle Miocene thermal subsidence, and (5) Late Miocene to Quaternary transpression and inversion. Oil-prone source rocks were deposited during rapid post-rift thermal subsidence of transtensional rift basins and adjacent highs, which provided an ideal sediment-starved setting for source rock accumulation. Reservoir facies were supplied by prograding post-rift Miocene deltaics of the paleo-Amur river, which built a shelf across the thermally subsiding basin and intrabasin highs. Traps were formed when the basin was later inverted during Late Miocene to Pleistocene transpression, which reactivated both Paleogene normal faults and structural trends of the Mesozoic accretionary prism to create a broad zone of distributed shear. Strike-slip structural styles are evidenced by linear, en echelon alignments of doubly-plunging anticlines characterized by numerous small-displacement, transverse normal faults. Strike slip on individual structures is relatively small, however, based on a lack of thorough going faults. Strike-slip structures on Sakhalin Island are considered active, in light of the earthquake of May 27, 1995 (M=7.6) and uplift of Pleistocene marine terraces.« less

Strike-slip structural styles and petroleum system evolution, northeast Sakhalin Island

DOE Office of Scientific and Technical Information (OSTI.GOV)

Meisling, K.E.; Wagner, J.B.

1996-01-01

The primary petroleum system of northeast Sakhalin Island and adjacent shelfal areas is comprised of a system of Late Miocene to Quaternary faulted transpressional anticlines that trap oil and gas in Early Miocene to Pliocene deltaic reservoirs sourced from Late Oligocene to Early Miocene diatomaceous shales. Existing production has been limited to onshore anticlines, and offshore structural trends remain undeveloped, despite several discoveries. The regional tectonic evolution of Sakhalin Island can be divided into five major phases: (1) Late Cretaceous to Early Eocene subduction, (2) Middle-Eocene collision and uplift, (3) Late Eocene to Early Oligocene oblique rifting, (4) Late Oligocenemore » to Middle Miocene thermal subsidence, and (5) Late Miocene to Quaternary transpression and inversion. Oil-prone source rocks were deposited during rapid post-rift thermal subsidence of transtensional rift basins and adjacent highs, which provided an ideal sediment-starved setting for source rock accumulation. Reservoir facies were supplied by prograding post-rift Miocene deltaics of the paleo-Amur river, which built a shelf across the thermally subsiding basin and intrabasin highs. Traps were formed when the basin was later inverted during Late Miocene to Pleistocene transpression, which reactivated both Paleogene normal faults and structural trends of the Mesozoic accretionary prism to create a broad zone of distributed shear. Strike-slip structural styles are evidenced by linear, en echelon alignments of doubly-plunging anticlines characterized by numerous small-displacement, transverse normal faults. Strike slip on individual structures is relatively small, however, based on a lack of thorough going faults. Strike-slip structures on Sakhalin Island are considered active, in light of the earthquake of May 27, 1995 (M=7.6) and uplift of Pleistocene marine terraces.« less

Geologic framework of the Mississippian Barnett Shale, Barnett-Paleozoic total petroleum system, Bend arch-Fort Worth Basin, Texas

USGS Publications Warehouse

Pollastro, R.M.; Jarvie, D.M.; Hill, R.J.; Adams, C.W.

2007-01-01

This article describes the primary geologic characteristics and criteria of the Barnett Shale and Barnett-Paleozoic total petroleum system (TPS) of the Fort Worth Basin used to define two geographic areas of the Barnett Shale for petroleum resource assessment. From these two areas, referred to as "assessment units," the U.S. Geological Survey estimated a mean volume of about 26 tcf of undiscovered, technically recoverable hydrocarbon gas in the Barnett Shale. The Mississippian Barnett Shale is the primary source rock for oil and gas produced from Paleozoic reservoir rocks in the Bend arch-Fort Worth Basin area and is also one of the most significant gas-producing formations in Texas. Subsurface mapping from well logs and commercial databases and petroleum geochemistry demonstrate that the Barnett Shale is organic rich and thermally mature for hydrocarbon generation over most of the Bend arch-Fort Worth Basin area. In the northeastern and structurally deepest part of the Fort Worth Basin adjacent to the Muenster arch, the formation is more than 1000 ft (305 m) thick and interbedded with thick limestone units; westward, it thins rapidly over the Mississippian Chappel shelf to only a few tens of feet. The Barnett-Paleozoic TPS is identified where thermally mature Barnett Shale has generated large volumes of hydrocarbons and is (1) contained within the Barnett Shale unconventional continuous accumulation and (2) expelled and distributed among numerous conventional clastic- and carbonate-rock reservoirs of Paleozoic age. Vitrinite reflectance (Ro) measurements show little correlation with present-day burial depth. Contours of equal Ro values measured from Barnett Shale and typing of produced hydrocarbons indicate significant uplift and erosion. Furthermore, the thermal history of the formation was enhanced by hydrothermal events along the Ouachita thrust front and Mineral Wells-Newark East fault system. Stratigraphy and thermal maturity define two gas-producing assessment units for the Barnett Shale: (1) a greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit, encompassing an area of optimal gas production where dense impermeable limestones enclose thick (???300 ft; ???91 m) Barnett Shale that is within the gas-generation window (Ro ??? 1.1%); and (2) an extended continuous Barnett Shale gas assessment unit covering an area where the Barnett Shale is within the gas-generation window, but is less than 300 ft (91 m) thick, and either one or both of the overlying and underlying limestone barriers are absent. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

Strontium isotopic study of subsurface brines from Illinois basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

hetherington, E.A.; Stueber, A.M.; Pushkar, P.

1986-05-01

The abundance of the radiogenic isotope /sup 87/Sr in a subsurface brine can be used as a tracer of brine origin, evolution, and diagenetic effects. The authors have determined the /sup 87/Sr//sup 86/Sr ratios of over 60 oil-field waters from the Illinois basin, where brine origin is perplexing because of the absence of any significant evaporite strata. Initially, they analyzed brines from 15 petroleum-producing sandstone and carbonate units; waters from Ordovician, Silurian, Devonian, and Mississippian strata have /sup 87/Sr//sup 86/Sr ratios in the range 0.7079-0.7108. All but those from the Ste. Genevieve Limestone (middle Mississippian) are more radiogenic in /supmore » 87/Sr//sup 86/Sr than seawater values for this interval of geologic time. The detrital source of the more radiogenic /sup 87/Sr may be the New Albany Shale group, considered to be a major petroleum source rock in the basin. The /sup 87/Sr//sup 86/Sr ratios of Ste. Genevieve brines apparently evolved without a contribution from fluid-shale interaction.« less

Diagenesis and fracture development in the Bakken Formation, Williston Basin; implications for reservoir quality in the middle member

USGS Publications Warehouse

Pitman, Janet K.; Price, Leigh C.; LeFever, Julie A.

2001-01-01

The middle member of the Bakken Formation is an attractive petroleum exploration target in the deeper part of the Williston Basin because it is favorably positioned with respect to source and seal units. Progressive rates of burial and minor uplift and erosion of this member led to a stable thermal regime and, consequently, minor variations in diagenesis across much of the basin. The simple diagenetic history recorded in sandstones and siltstones in the middle member can, in part, be attributed to the closed, low-permeability nature of the Bakken petroleum system during most of its burial history. Most diagenesis ceased in the middle member when oil entered the sandstones and siltstones in the Late Cretaceous. Most oil in the Bakken Formation resides in open, horizontal fractures in the middle member. Core analysis reveals that sandstones and siltstones associated with thick mature shales typically have a greater density of fractures than sandstones and siltstones associated with thin mature shales. Fractures were caused by superlithostatic pressures that formed in response to increased fluid volumes in the source rocks during hydrocarbon generation

Copper Deposits in Sedimentary and Volcanogenic Rocks

USGS Publications Warehouse

Tourtelot, Elizabeth B.; Vine, James David

1976-01-01

Copper deposits occur in sedimentary and volcanogenic rocks within a wide variety of geologic environments where there may be little or no evidence of hydrothermal alteration. Some deposits may be hypogene and have a deep-seated source for the ore fluids, but because of rapid cooling and dilution during syngenetic deposition on the ocean floor, the resulting deposits are not associated with hydrothermal alteration. Many of these deposits are formed at or near major tectonic features on the Earth's crust, including plate boundaries, rift valleys, and island arcs. The resulting ore bodies may be stratabound and either massive or disseminated. Other deposits form in rocks deposited in shallow-marine, deltaic, and nonmarine environments by the movement and reaction of interstratal brines whose metal content is derived from buried sedimentary and volcanic rocks. Some of the world's largest copper deposits were probably formed in this manner. This process we regard as diagenetic, but some would regard it as syngenetic, if the ore metals are derived from disseminated metal in the host-rock sequence, and others would regard the process as epigenetic, if there is demonstrable evidence of ore cutting across bedding. Because the oxidation associated with diagenetic red beds releases copper to ground-water solutions, red rocks and copper deposits are commonly associated. However, the ultimate size, shape, and mineral zoning of a deposit result from local conditions at the site of deposition - a logjam in fluvial channel sandstone may result in an irregular tabular body of limited size; a petroleum-water interface in an oil pool may result in a copper deposit limited by the size and shape of the petroleum reservoir; a persistent thin bed of black shale may result in a copper deposit the size and shape of that single bed. The process of supergene enrichment has been largely overlooked in descriptions of copper deposits in sedimentary rocks. However, supergene processes may be involved during erosion of any primary ore body and its ultimate displacement and redeposition as a secondary deposit. Bleached sandstone at the surface may indicate significant ore deposits near the water table.

Eocene Total Petroleum System -- North and East of the Eocene West Side Fold Belt Assessment Unit of the San Joaquin Basin Province: Chapter 19 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Gautier, Donald L.; Hosford Scheirer, Allegra

2009-01-01

The North and East of Eocene West Side Fold Belt Assessment Unit (AU) of the Eocene Total Petroleum System of the San Joaquin Basin Province comprises all hydrocarbon accumulations within the geographic and stratigraphic limits of this confirmed AU. Oil and associated gas accumulations occur in Paleocene through early middle Miocene marine to nonmarine sandstones found on the comparatively stable northeast shelf of the basin. The assessment unit is located north and east of the thickest accumulation of Neogene sediments and the west side fold belt. The area enclosed by the AU has been affected by only mild deformation since Eocene time. Traps containing known accumulations are mostly low-relief domes, anticlines, and up-dip basin margin traps with faulting and stratigraphic components. Map boundaries of the assessment unit are shown in figures 19.1 and 19.2; this assessment unit replaces the Northeast Shelf of Neogene Basin play 1006, the East Central Basin and Slope North of Bakersfield Arch play 1010, and part of the West Side Fold Belt Sourced by Pre-middle Miocene Rocks play 1005 considered by the U.S. Geological Survey (USGS) in their 1995 National Assessment (Beyer, 1996). Stratigraphically, the AU includes rocks from the uppermost crystalline basement to the topographic surface. In the region of overlap with the Central Basin Monterey Diagenetic Traps Assessment Unit, the North and East of Eocene West Side Fold Belt AU extends from basement rocks to the top of the Temblor Formation (figs. 19.3 and 19.4). In map view, the northern boundary of the assessment unit corresponds to the northernmost extent of Eocene-age Kreyenhagen Formation. The northeast boundary is the eastern limit of possible oil reservoir rocks near the eastern edge of the basin. The southeast boundary corresponds to the pinch-out of Stevens sand of Eckis (1940) to the south, which approximately coincides with the northern flank of the Bakersfield Arch (fig. 19.1). The AU is bounded on the southwest by the limit of major west side structural deformation and to the northwest by the San Andreas Fault and the limit of hydrocarbon-prospective strata in the Coast Ranges. As described by Gautier and others (this volume, chapter 2), existing oil fields in the San Joaquin Basin Province were assigned to assessment units based on the identified petroleum system and reservoir rocks in each field. Vallecitos oil field in the extreme northwest corner of the basin was assigned to the Eocene Total Petroleum System, because oil analyses conducted for this San Joaquin Basin assessment indicate that Eocene oil charged the reservoir rocks (Lillis and Magoon, this volume, chapter 9). Some literature classifies the Vallecitos oil field as part of the northernmost fold of the basin’s west side fold belt (see, for example, Rentschler, 1985; Bartow, 1991), but because of the oil field’s spatial separation and differing trend from the west side fold belt, Vallecitos field was considered here to be within the North and East of Eocene West Side Fold Belt Assessment Unit rather than in the other assessment unit in the Eocene Total Petroleum System, the Eocene West Side Fold Belt. Primary fields in the assessment unit are defined as those containing hydrocarbon resources greater than the USGS minimum threshold for assessment (0.5 million barrels of oil); secondary fields contain smaller volumes of oil but constitute a significant show of hydrocarbons.

Analysis of the Control Factors of Groundwater Petroleum Hydrocarbons Contamination in a City’s West Part

NASA Astrophysics Data System (ADS)

Sun, L. H.; Ma, Z. M.; Liu, Z. W.

2018-05-01

Based on study of the hydrogeological condition and the characteristics of petroleum hydrocarbons pollution in karst groundwater, an oil refinery located in western part of a certain city is chosen as the study site to have an analysis on the control factors of groundwater petroleum hydrocarbons contamination. The study result shows that the control factors of groundwater petroleum hydrocarbons contamination are hydrogeological condition and biodegradation. The soil layer of Quaternary is very thin, the limestone is exposed in the surface, which makes the petroleum hydrocarbons easy to permeate into the water bearing layer. Karst-fractured zone in aquifer determines the migration way of petroleum hydrocarbons to be convection, but the magmatic rock in northern part has certain blocking effect on the migration of petroleum hydrocarbons. Biodegradation makes both the contamination plume area of petroleum hydrocarbons and the content of petroleum hydrocarbons decreased.

Indigenous Precambrian petroleum revisited

DOE Office of Scientific and Technical Information (OSTI.GOV)

Murray, G.E.; Kaczor, M.J.; McArthur, R.E.

1980-10-01

Irrefutable evidence of fossil remains from Precambrian sediments and proved petroleum reserves in upper Proterozoic (Riphean-Vendian) strata of the Irkutsk basin, USSR, suggest that unmetamorphosed Precambrian sedimentary rocks should be a focus for hydrocarbon exploration. Since 1965, a dramatic increase in publications which document worldwide occurrences of Precambrian life forms discloses that, by the end of the Proterozoic, organic evolution had produced diversified assemblages of relatively highly developed macroorganisms and microorganisms. Some of these organisms have generated crude oil in the Nonesuch Shale of northern Michigan and kerogen in stromatolitic carbonate rocks in Africa Kerogen has been extracted from approx.more » 2300-m.y. old Transvaal (Africa) stromatolitic limestone containing coccoid and complex filamentous cyanophytes. Also, aromatic and aliphatic hydrocarbons have been obtained from the approx. 2800-m.y. old Bulawayan stromatolitic limestone of Rhodesia. Additional evidence indicates that commercial reserves of petroleum from Precambrian strata are possible. An oil discovery in Lower Cambrian rocks in 1962, at Markovo in the Irkutsk basin of the Siberian platform area, led to four noncommercial and eight commercial fields producing from Lower Cambrian and Upper Proterozoic strata.« less

The observation of spectral variation indicative of porphyrin biomarkers in reflectance spectra of source rock - The application of remote sensing technology to petroleum geochemistry

NASA Technical Reports Server (NTRS)

Holden, Peter Newhall; Gaffey, Michael J.

1990-01-01

The spectral signature of porphyrin compounds, considered to be biomarkers of depositional environment and thermal maturity, have been identified in reflectance spectra of oil shales. The key bands identified, in order of intensity, are the Soret (0.40 microns), alpha (0.57 microns), and beta (0.53 microns) bands. The observed bands represent the composite spectral signature of all porphyrin compounds present in the sample and, therefore, change position and intensity in accordance with changes in porphyrin chemistry.

Geology and assessment of undiscovered oil and gas resources of the Hope Basin Province, 2008

USGS Publications Warehouse

Bird, Kenneth J.; Houseknecht, David W.; Pitman, Janet K.; Moore, Thomas E.; Gautier, Donald L.

2018-01-04

The Hope Basin, an independent petroleum province that lies mostly offshore in the southern Chukchi Sea north of the Chukotka and Seward Peninsulas and south of Wrangel Island, the Herald Arch, and the Lisburne Peninsula, is the largest in a series of postorogenic (successor) basins in the East Siberian-Chukchi Sea region and the only one with exploratory-well control and extensive seismic coverage.In spite of the seismic coverage and well data, the petroleum potential of the Hope Basin Province is poorly known. The adequacy of hydrocarbon charge, in combination with uncertainties in source-rock potential and maturation, was the greatest risk in this assessment. A single assessment unit was defined and assessed, resulting in mean estimates of undiscovered, technically recoverable resources that include ~3 million barrels of oil and 650 billion cubic feet of nonassociated gas.

The influence of shale depositional fabric on the kinetics of hydrocarbon generation through control of mineral surface contact area on clay catalysis

NASA Astrophysics Data System (ADS)

Rahman, Habibur M.; Kennedy, Martin; Löhr, Stefan; Dewhurst, David N.; Sherwood, Neil; Yang, Shengyu; Horsfield, Brian

2018-01-01

Accurately assessing the temperature and hence the depth and timing of hydrocarbon generation is a critical step in the characterization of a petroleum system. Clay catalysis is a potentially significant modifier of hydrocarbon generation temperature, but experimental studies of clay catalysis show inconsistent or contradictory results. This study tests the hypothesis that source rock fabric itself is an influence on clay mineral catalysis as it controls the extent to which organic matter and clay minerals are physically associated. Two endmember clay-organic fabrics distinguish the source rocks studied: (1) a particulate fabric where organic matter is present as discrete, >5 μm particles and (2) a nanocomposite fabric in which amorphous organic matter is associated with clay mineral surfaces at sub-micron scale. High-resolution electron imaging and bulk geochemical characterisation confirm that samples of the Miocene Monterey Formation (California) are representative of the nanocomposite source rock endmember, whereas samples from the Permian Stuart Range Formation (South Australia) represent the particulate source rock endmember. Kinetic experiments are performed on paired whole rock and kerogen isolate samples from these two formations using open system, non-isothermal pyrolysis at three different heating rates (0.7, 2 and 5 K/min) to determine the effects of the different shale fabrics on hydrocarbon generation kinetics. Extrapolation to a modelled geological heating rate shows a 20 °C reduction in the onset temperature of hydrocarbon generation in Monterey Formation whole rock samples relative to paired kerogen isolates. This result is consistent with the Monterey Formations's nanocomposite fabric where clay catalysis can proceed because reactive clay minerals are intimately associated with organic matter. By contrast, there is no significant difference in the modelled hydrocarbon generation temperature of paired whole rock and kerogen isolates from the Stuart Range Formation. This is consistent with its particulate fabric, where relatively large, discrete organic particles have limited contact with the mineral matrix and the clay minerals are mainly diagenetic and physically segregated within pores. While heating rate may have a control on mineral matrix effects, this result shows that the extent to which organic matter and clay minerals are physically associated could have a significant effect on the timing of hydrocarbon generation, and is a function of the depositional environment and detrital vs diagenetic origin of clay minerals in source rocks.

Role of water in hydrocarbon generation from Type-I kerogen in Mahogany oil shale of the Green River Formation

USGS Publications Warehouse

Lewan, M.D.; Roy, S.

2011-01-01

Hydrous and anhydrous closed-system pyrolysis experiments were conducted on a sample of Mahogany oil shale (Eocene Green River Formation) containing Type-I kerogen to determine whether the role of water had the same effect on petroleum generation as reported for Type-II kerogen in the Woodford Shale. The experiments were conducted at 330 and 350??C for 72h to determine the effects of water during kerogen decomposition to polar-rich bitumen and subsequent bitumen decomposition to hydrocarbon-rich oil. The results showed that the role of water was more significant in bitumen decomposition to oil at 350??C than in kerogen decomposition to bitumen at 330??C. At 350??C, the hydrous experiment generated 29% more total hydrocarbon product and 33% more C15+ hydrocarbons than the anhydrous experiment. This is attributed to water dissolved in the bitumen serving as a source of hydrogen to enhance thermal cracking and facilitate the expulsion of immiscible oil. In the absence of water, cross linking is enhanced in the confines of the rock, resulting in formation of pyrobitumen and molecular hydrogen. These differences are also reflected in the color and texture of the recovered rock. Despite confining liquid-water pressure being 7-9 times greater in the hydrous experiments than the confining vapor pressure in the anhydrous experiments, recovered rock from the former had a lighter color and expansion fractures parallel to the bedding fabric of the rock. The absence of these open tensile fractures in the recovered rock from the anhydrous experiments indicates that water promotes net-volume increase reactions like thermal cracking over net-volume decrease reactions like cross linking, which results in pyrobitumen. The results indicate the role of water in hydrocarbon and petroleum formation from Type-I kerogen is significant, as reported for Type-II kerogen. ?? 2010.

The Sirte Basin province of Libya; Sirte-Zelten total petroleum system

USGS Publications Warehouse

Ahlbrandt, Thomas S.

2001-01-01

The Sirte (Sirt) Basin province ranks 13th among the world?s petroleum provinces, having known reserves of 43.1 bil-lion barrels of oil equivalent (36.7 billion barrels of oil, 37.7 tril-lion cubic feet of gas, 0.1 billion barrels of natural gas liquids). It includes an area about the size of the Williston Basin of the north-ern United States and southern Canada (?490,000 square kilome-ters). The province contains one dominant total petroleum system, the Sirte-Zelten, based on geochemical data. The Upper Cretaceous Sirte Shale is the primary hydrocarbon source bed. Reservoirs range in rock type and age from fractured Precam-brian basement, clastic reservoirs in the Cambrian-Ordovician Gargaf sandstones, and Lower Cretaceous Nubian (Sarir) Sand-stone to Paleocene Zelten Formation and Eocene carbonates commonly in the form of bioherms. More than 23 large oil fields (>100 million barrels of oil equivalent) and 16 giant oil fields (>500 million barrels of oil equivalent) occur in the province. Abstract 1 Production from both clastic and carbonate onshore reservoirs is associated with well-defined horst blocks related to a triple junc-tion with three arms?an eastern Sarir arm, a northern Sirte arm, and a southwestern Tibesti arm. Stratigraphic traps in combina-tion with these horsts in the Sarir arm are shown as giant fields (for example, Messla and Sarir fields in the southeastern portion of the province). Significant potential is identified in areas marginal to the horsts, in the deeper grabens and in the offshore area. Four assessment units are defined in the Sirte Basin prov-ince, two reflecting established clastic and carbonate reservoir areas and two defined as hypothetical units. Of the latter, one is offshore in water depths greater than 200 meters, and the other is onshore where clastic units, mainly of Mesozoic age, may be res-ervoirs for laterally migrating hydrocarbons that were generated in the deep-graben areas. The Sirte Basin reflects significant rifting in the Early Cre-taceous and syn-rift sedimentary filling during Cretaceous through Eocene time, and post-rift deposition in the Oligocene and Miocene. Multiple reservoirs are charged largely by verti-cally migrating hydrocarbons along horst block faults from Upper Cretaceous source rocks that occupy structurally low posi-tions in the grabens. Evaporites in the middle Eocene, mostly post-rift, provide an excellent seal for the Sirte-Zelten hydrocarbon system. The offshore part of the Sirte Basin is complex, with subduction occurring to the northeast of the province boundary, which is drawn at the 2,000-meter isobath. Possible petroleum systems may be present in the deep offshore grabens on the Sirte Rise such as those involving Silurian and Eocene rocks; however, potential of these systems remains speculative and was not assessed.

Enhanced late gas generation potential of petroleum source rocks via recombination reactions: Evidence from the Norwegian North Sea

NASA Astrophysics Data System (ADS)

Erdmann, Michael; Horsfield, Brian

2006-08-01

Gas generation in the deep reaches of sedimentary basins is usually considered to take place via the primary cracking of short alkyl groups from overmature kerogen or the secondary cracking of petroleum. Here, we show that recombination reactions ultimately play the dominant role in controlling the timing of late gas generation in source rocks which contain mixtures of terrigeneous and marine organic matter. These reactions, taking place at low levels of maturation, result in the formation of a thermally stable bitumen, which is the major source of methane at very high maturities. The inferences come from pyrolysis experiments performed on samples of the Draupne Formation (liptinitic Type II kerogen) and Heather Formation (mixed marine-terrigeneous Type III kerogen), both Upper Jurassic source rocks stemming from the Norwegian northern North Sea Viking Graben system. Non-isothermal closed system micro scale sealed vessel (MSSV) pyrolysis, non-isothermal open system pyrolysis and Rock Eval type pyrolysis were performed on the solvent extracted, concentrated kerogens of the two immature samples. The decrease of C 6+ products in the closed system MSSV pyrolysis provided the basis for the calculation of secondary gas (C 1-5) formation. Subtraction of the calculated secondary gas from the total observed gas yields a "remaining" gas. In the case of the Draupne Formation this is equivalent to primary gas cracked directly from the kerogen, as detected by a comparison with multistep open pyrolysis data. For the Heather Formation the calculated remaining gas formation profile is initially attributable to primary gas but there is a second major gas pulse at very high temperature (>550 °C at 5.0 K min -1) that is not primary. This has been explained by a recondensation process where first formed high molecular weight compounds in the closed system yield a macromolecular material that undergoes secondary cracking at elevated temperatures. The experiments provided the input for determination of kinetic parameters of the different gas generation types, which were used for extrapolations to a linear geological heating rate of 10 -11 K min -1. Peak generation temperatures for the primary gas generation were found to be higher for Heather Formation ( Tmax = 190 °C, equivalent to Ro appr. 1.7%) compared to Draupne Formation ( Tmax = 175 °C, equivalent to appr. Ro 1.3%). Secondary gas peak generation temperatures were calculated to be 220 °C for the Heather Formation and 205 to 215 °C for the Draupne Formation, respectively, with equivalent vitrinite reflectance values ( Ro) between 2.4% and 2.0%. The high temperature secondary gas formation from cracking of the recombination residue as detected for the Heather Formation is quantitatively important and is suggested to occur at very high temperatures ( Tmax approx. 250 °C) for geological heating rates. The prediction of a significant charge of dry gas from the Heather Formation at very high maturity levels has important implications for petroleum exploration in the region, especially to the north of the Viking Graben where Upper Jurassic sediments are sufficiently deep buried to have experienced such a process.

Geology and petroleum resources of Venezuela

DOE Office of Scientific and Technical Information (OSTI.GOV)

Klemme, H.D.

1986-05-01

Venezuela occupies a peripheral position to the Guiana shield and craton in northern South America. The larger sedimentary basins of the Venezuelan craton zone are marginal cratonic basins (Lanos-Barinas), resulting from Tertiary Andean eastward movements, and basins formed by collisional, extensional, and transformed movement of the American portion of Tethys (eastern Venezuela-Trinidad). The smaller sedimentary basins of Venezuela are Tertiary transverse-wrench basins in the disturbed intermontane zone peripheral to the cratonic basins (Maracaibo, Falcon, parts of the Gulf of Venezuela, Carioca, and parts of Tobago-Margarita). Venezuela accounts for 75% of the recoverable oil and 55% of the gas discovered inmore » South America. These deposits occur primarily in two basins (East Venezuela and Maracaibo - where one complex, the Bolivar Coastal and lake pools, represents 40% of South American discovered oil). The East Venezuela basin contains the Orinico heavy oil belt, currently assessed at 1 to 2 trillion bbl of oil in place. Source rocks for Venezuelan hydrocarbons are middle Cretaceous calcareous bituminous shales and marls (40% of discovered hydrocarbons), lower Tertiary deltaic and transitional shales, Paleocene-Eocene (40%), and Oligocene-Miocene deltaic and coastal shales (20%). A key factor in high recovery of hydrocarbons appears to be preservation of middle Cretaceous and lower Tertiary source rocks during maturation and migration. Reservoirs are dominantly (> 90%) clastic sediments (sandstones) within, above, or updip from source sequences. Cap rocks are interbedded and overlying shale.« less

Hydrocarbons related to early Cretaceous source rocks, reservoirs and seals, trapped in northeastern Neuqun basin, Argentina

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gulisano, C.; Minniti, S.; Rossi, G.

1996-08-01

The Jurassic-Cretaceous backarc Neuqun Basin, located in the west central part of Argentina, is currently the most prolific oil basin of the country. The primary objective of this study is to evaluate an Early Cretaceous to Tertiary petroleum system in the northeastern portion of the basin, where oil and gas occurrences (e.g., Puesto Hernandez, Chihuido de la Sierra Negra, El Trapial and Filo Morado oil fields, among others) provide 82 MMBO/yr comprising 67% of the basin oil production and 31% of Argentina. The source rocks are represented by two thick sections of basinal kerogen type I and II organic-rich shales,more » deposited during transgressive peaks (Agrio Formation), with TOC content up to 5.1%. Lowstand sandstones bodies, 10 to 100 m thick, are composed of eolian and fluvial facies with good reservoir conditions (Avil and Troncoso Sandstones). The seals are provided by the organic-rich shales resting sharply upon the Avil Sandstone and a widespread Aptian-Albian evaporitic event (Huitrin Formation) on top of the Troncoso reservoir. Tertiary structural traps (duplex anticlines) are developed in the outer foothills, whereas structural, combined and stratigraphic traps are present in the adjacent stable structural platform. Oil-to-source rock and oil-to-oil correlation by chromatographic and biomarker fingerprints, carbon isotopic composition and the geological evidences support the proposed oil system.« less

The Progreso Basin Province of Northwestern Peru and Southwestern Ecuador: Neogene and Cretaceous-Paleogene Total Petroleum Systems

USGS Publications Warehouse

Higley, Debra K.

2004-01-01

The Progreso Basin province (6083) in northwestern Peru and southwestern Ecuador consists of the Paleogene Santa Elena block and Peru Bank, and the Neogene Tumbes-Progreso subbasin. The Santa Elena block and Peru Bank are part of the Cretaceous-Paleogene Total Petroleum System (TPS)(608302), which contains the Cretaceous-Paleogene Santa Elena Block Assessment Unit (60830201). The Tumbes- Progreso subbasin includes the Neogene TPS (608301) and associated Neogene Pull-Apart Basin Assessment Unit (60830101). The complex tectonic history of the Progreso Basin province influenced depositional and erosional patterns across the region, and also the location, timing, and types of seals, traps, possible source and reservoir rocks, and hydrocarbon generation and migration. Marine shales that are interbedded with and overlie reservoir intervals are the probable hydrocarbon source rocks. Timing of hydrocarbon generation and migration was probably Miocene and younger, following creation of the Tumbes-Progreso subbasin by movement along the Dolores-Guayaquil megashear. More than 220 million barrels of oil (MMBO) and 255 billion cubic feet of gas (BCFG) have been produced from the Progreso Basin province. The means of estimated recoverable oil, gas, and natural gas liquids (NGL) resources from undiscovered fields in the province are 237 MMBO, 695 BCFG, and 32 MMB NGL, respectively. The means of estimated recoverable oil, gas, and NGL resources from undiscovered onshore fields are 45 MMBO, 113 BCFG, and 5 MMBNGL, and from undiscovered offshore fields are 192 BBO, 582 BCFG, and 27 MMBNGL. These are USGS grown undiscovered resources that were determined by using a minimum field size of 1 million barrels of oil equivalent.

Comparison of petroleum generation kinetics by isothermal hydrous and nonisothermal open-system pyrolysis

USGS Publications Warehouse

Lewan, M.D.; Ruble, T.E.

2002-01-01

This study compares kinetic parameters determined by open-system pyrolysis and hydrous pyrolysis using aliquots of source rocks containing different kerogen types. Kinetic parameters derived from these two pyrolysis methods not only differ in the conditions employed and products generated, but also in the derivation of the kinetic parameters (i.e., isothermal linear regression and non-isothermal nonlinear regression). Results of this comparative study show that there is no correlation between kinetic parameters derived from hydrous pyrolysis and open-system pyrolysis. Hydrous-pyrolysis kinetic parameters determine narrow oil windows that occur over a wide range of temperatures and depths depending in part on the organic-sulfur content of the original kerogen. Conversely, open-system kinetic parameters determine broad oil windows that show no significant differences with kerogen types or their organic-sulfur contents. Comparisons of the kinetic parameters in a hypothetical thermal-burial history (2.5 ??C/my) show open-system kinetic parameters significantly underestimate the extent and timing of oil generation for Type-US kerogen and significantly overestimate the extent and timing of petroleum formation for Type-I kerogen compared to hydrous pyrolysis kinetic parameters. These hypothetical differences determined by the kinetic parameters are supported by natural thermal-burial histories for the Naokelekan source rock (Type-IIS kerogen) in the Zagros basin of Iraq and for the Green River Formation (Type-I kerogen) in the Uinta basin of Utah. Differences in extent and timing of oil generation determined by open-system pyrolysis and hydrous pyrolysis can be attributed to the former not adequately simulating natural oil generation conditions, products, and mechanisms.

USGS assessment of undiscovered oil and gas resources in Paleogene strata of the U.S. Gulf of Mexico coastal plain and state waters

USGS Publications Warehouse

Warwick, Peter D.; Coleman, James; Hackley, Paul C.; Hayba, Daniel O.; Karlsen, Alexander W.; Rowan, Elisabeth L.; Swanson, Sharon M.; Kennan, Lorcan; Pindell, James; Rosen, Norman C.

2007-01-01

This report presents a review of the U.S. Geological Survey (USGS) 2007 assessment of the undiscovered oil and gas resources in Paleogene strata underlying the U.S. Gulf of Mexico Coastal Plain and state waters. Geochemical, geologic, geophysical, thermal maturation, burial history, and paleontologic studies have been combined with regional cross sections and data from previous USGS petroleum assessments have helped to define the major petroleum systems and assessment units. Accumulations of both conventional oil and gas and continuous coal-bed gas within these petroleum systems have been digitally mapped and evaluated, and undiscovered resources have been assessed following USGS methodology.The primary source intervals for oil and gas in Paleogene (and Cenozoic) reservoirs are coal and shale rich in organic matter within the Wilcox Group (Paleocene-Eocene) and Sparta Formation of the Claiborne Group (Eocene); in addition, Cretaceous and Jurassic source rocks probably have contributed substantial petroleum to Paleogene (and Cenozoic) reservoirs.For the purposes of the assessment, Paleogene strata have divided into the following four stratigraphic study intervals: (1) Wilcox Group (including the Midway Group and the basal Carrizo Sand of the Claiborne Group; Paleocene-Eocene); (2) Claiborne Group (Eocene); (3) Jackson and Vicksburg Groups (Eocene-Oligocene); and (4) the Frio-Anahuac Formations (Oligocene). Recent discoveries of coal-bed gas in Paleocene strata confirm a new petroleum system that was not recognized in previous USGS assessments. In total, 26 conventional Paleogene assessment units are defined. In addition, four Cretaceous-Paleogene continuous (coal-bed gas) assessment units are included in this report. Initial results of the assessment will be released as USGS Fact Sheets (not available at the time of this writing).Comprehensive reports for each assessment unit are planned to be released via the internet and distributed on CD-ROMs within the next year.

Representative Bulk Composition of Oil Types for the 2002 U.S. Geological Survey Resource Assessment of National Petroleum Reserve in Alaska

USGS Publications Warehouse

Lillis, Paul G.

2004-01-01

Bulk oil composition is an important economic consideration of a petroleum resource assessment. Geological and geochemical interpretations from previous North Slope studies combined with recently acquired geochemical data are used to predict representative oil gravity (?API) and sulfur content (wt.% S) of the oil types for the 2002 U.S. Geological Survey resource assessment of the National Petroleum Reserve of Alaska (NPRA). The oil types are named after their respective source rock units and include Kuna-Lisburne, Shublik-Otuk, Kingak-Blankenship, and Pebble-GRZ-Torok. The composition of the oil (24?API, 1.6 wt.% S) in the South Barrow 12 well was selected as representative of Kuna-Lisburne oil. The average gravity and sulfur values (23?API and 1.6 wt.% S, respectively) of the Kuparuk field were selected to be representative of Shublik-Otuk oil type. The composition of the oil (39?API, 0.3 wt.% S) from the Alpine field discovery well (ARCO Bergschrund 1) was selected to be representative of Kingak-Blankenship oil. The oil composition (37?API, 0.1 wt.% S) of Tarn field was considered representative of the Pebble-GRZ-Torok oil type in NPRA.

The Niger Delta petroleum system; Niger Delta Province, Nigeria, Cameroon, and equatorial Guinea, Africa

USGS Publications Warehouse

Tuttle, Michele L.W.; Charpentier, Ronald R.; Brownfield, Michael E.

1999-01-01

In the Niger Delta province, we have identified one petroleum system--the Tertiary Niger Delta (Akata-Agbada) petroleum system. The delta formed at the site of a rift triple junction related to the opening of the southern Atlantic starting in the Late Jurassic and continuing into the Cretaceous. The delta proper began developing in the Eocene, accumulating sediments that now are over 10 kilometers thick. The primary source rock is the upper Akata Formation, the marine-shale facies of the delta, with possibly contribution from interbedded marine shale of the lowermost Agbada Formation. Oil is produced from sandstone facies within the Agbada Formation, however, turbidite sand in the upper Akata Formation is a potential target in deep water offshore and possibly beneath currently producing intervals onshore. Known oil and gas resources of the Niger Delta rank the province as the twelfth largest in the world. To date, 34.5 billion barrels of recoverable oil and 93.8 trillion cubic feet of recoverable gas have been discovered. In 1997, Nigeria was the fifth largest crude oil supplier to the United States, supplying 689,000 barrels/day of crude.

77 FR 15990 - Proposed Confidentiality Determinations for the Petroleum and Natural Gas Systems Source Category...

Federal Register 2010, 2011, 2012, 2013, 2014

2012-03-19

... Proposed Confidentiality Determinations for the Petroleum and Natural Gas Systems Source Category, and... the Petroleum and Natural Gas Systems Source Category, and Amendments to Table A-7, of the Greenhouse... on the proposed rule titled ``Proposed Confidentiality Determinations for the Petroleum and Natural...

Characterization of Northern California petroleum by stable carbon isotopes

USGS Publications Warehouse

Lillis, Paul G.; Magoon, Leslie B.; Stanley, Richard G.; McLaughlin, Robert J.; Warden, Augusta

2001-01-01

The purpose of this study is to characterize natural occurrences of petroleum at the surface and in the subsurface within northern California in order to define and map petroleum systems for U.S. Geological Survey energy resource assessments. Furthermore, the chemical characterization and mapping of natural petroleum occurrences could also be used to discriminate natural occurrences from accidental oil spills during the activities of extraction or transportation of petroleum. Samples include petroleum from exploratory well tests, producing fields, natural seeps, and oil-stained rocks, and condensates from gas wells. Most of the sample localities are in northern California but a few samples from central and southern California are included for comparison (table 1). Even though other analyses were performed, only stable carbon isotope (δ13C) data are presented here for brevity and because δ13C values are one of the most discriminating characteristics of California petroleum.

Interpreting benthic oxygen levels in mudrocks: A new approach

NASA Astrophysics Data System (ADS)

Wignall, Paul B.; Myers, Keith J.

1988-05-01

Quantified paleoecology and gamma-ray spectrometry have been applied in the analysis of the Kimmeridge Clay, a highly organic-rich British Jurassic mudrock. Decreasing benthic oxygen trends are reflected in decreasing species richness and dominance-diversity values. Similarly, the degree of fragmentation of the benthos reflects the benthic energy levels and covaries with benthic oxygen. The calculation of authigenic uranium values from data gathered by gamma-ray spectrometry shows enrichment in more oxygen-deficient environments. The good correlation between the independently derived paleoecological and authigenic U data indicates the importance of these techniques in environmental analysis of marine petroleum source rocks.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Vernet, R.

The Bas Congo basin extends from Gabon to Angola and is a prolific oil province where both pre-salt and post salt sources and reservoirs have been found. In the northern part of the basin referred to as the Congo coastal basin, the proven petroleum system is more specific: mature source rocks are found only in pre-salt series whereas by contrast 99 % proven hydrocarbon reserves am located in post-salt traps. Such a system is controlled by the following factors: Source rocks are mostly organic rich shales deposited in a restricted environment developed in a rift prior to the Atlantic Oceanmore » opening; Migration from pre-salt sources to post-salt traps is finalized by local discontinuities of the regional salt layer acting otherwise as a tight seal; Post-salt reservoirs are either carbonates or sands desposited in the evolutive shelf margin developped during Upper Cretaceous; Geometric traps are linked to salt tectonics (mostly turtle-shaped structures); Regional shaly seals are related to transgressive shales best developped during high rise sea level time interval. Stratigraphically, the age of hydrocarbon fields trends are younger and younger from West to East: lower Albian in Nkossa, Upper Albian and lower Cenomanian in Likouala, Yanga, Sendji, Upper Cenomanian in Tchibouela, Turonian in Tchendo, Turanian and Senonian in Emeraude.« less

Structure, stratigraphy, and petroleum geology of the Little Plain basin, northwestern Hungary

USGS Publications Warehouse

Mattick, R.E.; Teleki, P.G.; Phillips, R.L.; Clayton, J.L.; David, G.; Pogcsas, G.; Bardocz, B.; Simon, E.

1996-01-01

The basement of the Little Plain (Kisalfo??ld) basin is composed of two parts: an eastern part comprised of folded and overthrusted Triassic and Paleozoic rocks of the Pelso block (Transdanubian Central Range) compressed in the Early Cretaceous, and a western part consisting of stacked nappes of the Austroalpine zone of Paleozoic rocks, significantly metamorphosed during Cretaceous and later compression, overriding Jurassic oceanic rift-zone rocks of the Penninic zone. The evolution of the basin began in the late Karpatian-early Badenian (middle Miocene) when the eastern part of the basin began to open along conjugate sets of northeast- and northwest-trending normal faults. Neogene rocks in the study area, on the average, contain less than 0.5 wt. % total organic carbon (TOC) and, therefore, are not considered effective source rocks. Locally, however, where TOC values are as high as 3 wt. %, significant amounts of gas may have been generated and expelled. Although potential stratigraphic traps are numerous in the Neogene section, these potential traps must be downgraded because of the small amount of hydrocarbons discovered in structural traps to date. With the exception of the Cretaceous, the Mesozoic section has not been actively explored. Large anticlinal and overthrust structures involving pre-Cretaceous strata remain undrilled.

Alternative designs for petroleum product storage tanks for groundwater protection.

PubMed

Oke Adeleke, Samson

In developing countries, there are numerous occurrences of petroleum product spillage in groundwater. The current practice of burying storage tanks beneath the surface without adequate safety devices facilitates this phenomenon. Underground tanks rust and leak, and spilled petroleum products migrate downward. The movement of the oil in the soil depends on its viscosity and quantity, the permeability of the soil/rock, and the presence of fractures within the rock. The oil spreads laterally in the form of a thin pancake due to its lower specific gravity, and soluble components dissolve in water. The pollution plume of petroleum products and dissolved phases moves in the direction of groundwater flow in the aquifer within the pores of soil and sediments or along fractures in basement complex areas. Most communities reply heavily on groundwater for potable and industrial supplies. However, the sustainability of this resource is under threat in areas where there are filling stations as a result of significant groundwater contamination from petroleum product spillage. Drinking water becomes unpalatable when it contains petroleum products in low concentrations, and small quantities may contaminate large volumes of water. Considering the losses incurred from spillage, the cost of cleaning the aquifer, and the fact that total cleansing and attenuation is impossible, the need to prevent spillage and if it happens to prevent it from getting into the groundwater system is of paramount importance. This paper proposes alternative design procedures with a view to achieving these objectives.

Burial and thermal history of the Paradox Basin, Utah and Colorado, and petroleum potential of the Middle Pennsylvanian Paradox Basin

USGS Publications Warehouse

Nuccio, Vito F.; Condon, Steven M.

1996-01-01

The Ismay?Desert Creek interval and Cane Creek cycle of the Alkali Gulch interval of the Middle Pennsylvanian Paradox Formation in the Paradox Basin of Utah and Colorado contain excellent organic-rich source rocks having total organic carbon contents ranging from 0.5 to 11.0 percent. The source rocks in both intervals contain types I, II, and III organic matter and are potential source rocks for both oil and gas. Organic matter in the Ismay?Desert Creek interval and Cane Creek cycle of the Alkali Gulch interval (hereinafter referred to in this report as the ?Cane Creek cycle?) probably is more terrestrial in origin in the eastern part of the basin and is interpreted to have contributed to some of the gas produced there. Thermal maturity increases from southwest to northeast for both the Ismay?Desert Creek interval and Cane Creek cycle, following structural and burial trends throughout the basin. In the northernmost part of the basin, the combination of a relatively thick Tertiary sedimentary sequence and high basinal heat flow has produced very high thermal maturities. Although general thermal maturity trends are similar for both the Ismay?Desert Creek interval and Cane Creek cycle, actual maturity levels are higher for the Cane Creek due to the additional thickness (as much as several thousand feet) of Middle Pennsylvanian section. Throughout most of the basin, the Ismay?Desert Creek interval is mature and in the petroleum-generation window (0.10 to 0.50 production index (PI)), and both oil and gas are produced; in the south-central to southwestern part of the basin, however, the interval is marginally mature (0.10 PI) in the central part of the basin and is overmature (past the petroleum-generation window (>0.50 PI)) throughout most of the eastern part of the basin. The Cane Creek cycle generally produces oil and associated gas throughout the western and central parts of the basin and thermogenic gas in the eastern part of the basin. Burial and thermal-history models were constructed for six different areas of the Paradox Basin. In the Monument upwarp area, the least mature part of the basin, the Ismay?Desert Creek interval and Cane Creek cycle have thermal maturities of 0.10 and 0.20 PI and were buried to 13,400 ft and 14,300 ft, respectively. A constant heat flow through time of 40 mWm?2 (milliwatts per square meter) is postulated for this area. Significant petroleum generation began at 45 Ma for the Ismay?Desert Creek interval and at 69 Ma for the Cane Creek cycle. In the area around the confluence of the Green and Colorado Rivers, the Ismay?Desert Creek interval and Cane Creek cycle have thermal maturities of 0.20 and 0.25 PI and were buried to 13,000 ft and 14,200 ft, respectively. A constant heat flow through time of 42 mWm?2 is postulated for this area. Significant petroleum generation began at 60 Ma for the Ismay?Desert Creek interval and at 75 Ma for the Cane Creek cycle. In the area around the town of Green River, Utah, the Ismay?Desert Creek interval and Cane Creek cycle have thermal maturities of 0.60 and greater and were buried to 14,000 ft and 15,400 ft, respectively. A constant heat flow through time of 53 mWm?2 is proposed for this area. Significant petroleum generation began at 82 Ma for the Ismay?Desert Creek interval and at 85 Ma for the Cane Creek cycle. Around Moab, Utah, in the deeper, eastern part of the basin, the Ismay?Desert Creek interval and Cane Creek cycle have thermal maturities of 0.30 and around 0.35 PI and were buried to 18,250 ft and 22,000 ft, respectively. A constant heat flow through time of 40 mWm?2 is postulated for this area. Significant petroleum generation began at 79 Ma for the Ismay?Desert Creek interval and at 90 Ma for the Cane Creek cycle. At Lisbon Valley, also in the structurally deeper part of the basin, the Ismay?

Deceased Slabs Drive Oil

NASA Astrophysics Data System (ADS)

Stein, H. J.; Hannah, J. L.

2017-12-01

The application of Re-Os isotope geochemistry to dating single oils is a nascent field [1,2]. Challenges include dissection of oils into asphaltene-maltene (ASPH-MALT) components in a way that preserves meaningful chronologic and source information. Significantly, oil-water mixing rapidly transfers Os to the oil, while Re exchange is sluggish [3]. The Os initial ratio of the oil is shifted in the direction of Os carried in the aqueous fluid, whereas the Re-Os isotopic age is preserved. We show that this phenomenon is operative in natural systems. Further, we show that deserpentinization of old oceanic slabs [4], may be linked to expulsion of Os-enriched waters into overlying sedimentary sections - a process that may be of fundamental importance for oil generation. This conclusion does not diminish the role of traditional organic-rich shales as source rocks for the hydrocarbon, but shows that external fluids are essential to petroleum generation. Moreover, the external fluids may be an important driver for expulsion and migration of oils. We have taken apart several petroleum systems from source rock, to residual oil, to tar mat development, to in situ live oil, through to produced oil. In many cases, a fluid with low 187Os/188Os - unlike that of normal basinal brines - provides a critical component to the oil-water mixture. Funding - CHRONOS project supported by Norwegian petroleum industry (Eni-Norge, Lundin, Aker BP) Acknowledgement - Christine Fichler [4], who first queried us on old slabs and oil, and stimulated ideas. [1] Georgiev, S.V., Stein, H.J., Hannah, J.L., Galimberti, R., Nali, M., Yang, G., and Zimmerman, A. (2016) Re-Os dating of maltenes and asphaltenes within single samples of crude oil: Geochim. Cosmochim. Acta 179: 53-75. [doi.org/10.1016/j.gca.2016.01.016] [2] DiMarzio, J., Georgiev, S.V., Stein, H.J., and Hannah, J.L. (in press) Residency of rhenium and osmium in a heavy crude oil: Geochim. Cosmochim. Acta. [3] Hurtig, N.C., Georgiev, S.V., Stein, H.J., and Hannah, J.L. (in review) Re-Os in oil - in the company of water. [4] Fichler, C., Odinsen, T., Rueslåtten, H., Olesen, O., Vingstad, J.-E., Wienecke, S. (2011) Crustal inhomogenities in the northern North Sea from potential field modeling: inherited structure and serpentinites: Tectonophysics 510: 172-185. [doi:10.1016/j.tecto.2011.06.026

Petroleum potential of the Reggane Basin, Algeria

DOE Office of Scientific and Technical Information (OSTI.GOV)

Boudjema, A.; Hamel, M.; Mohamedi, A.

1990-05-01

The intracratonic Reggane basin is located on the Saharan platform, southwest of Algeria. The basin covers an area of approximately 140,000 km{sup 2}, extending between the Eglab shield in the south and the Ougarta ranges in the north. Although exploration started in the early 1950s, only a few wells were drilled in this basin. Gas was discovered with a number of oil shows. The sedimentary fill, mainly Paleozoic shales and sandstones, has a thickness exceeding 5,000 m in the central part of the basin. The reservoirs are Cambrian-Ordovician, Siegenian, Emsian, Tournaisian, and Visean sandstones with prospective petrophysical characteristics. Silurian Uppermore » Devonian and, to a lesser extent Carboniferous shales are the main source rocks. An integrated study was done to assess the hydrocarbon potential of this basin. Tectonic evolution source rocks and reservoirs distribution maturation analyses followed by kinetic modeling, and hydrogeological conditions were studied. Results indicate that gas accumulations could be expected in the central and deeper part of the basin, and oil reservoirs could be discovered on the basin edge.« less

Multiple component end-member mixing model of dilution: hydrochemical effects of construction water at Yucca Mountain, Nevada, USA

NASA Astrophysics Data System (ADS)

Lu, Guoping; Sonnenthal, Eric L.; Bodvarsson, Gudmundur S.

2008-12-01

The standard dual-component and two-member linear mixing model is often used to quantify water mixing of different sources. However, it is no longer applicable whenever actual mixture concentrations are not exactly known because of dilution. For example, low-water-content (low-porosity) rock samples are leached for pore-water chemical compositions, which therefore are diluted in the leachates. A multicomponent, two-member mixing model of dilution has been developed to quantify mixing of water sources and multiple chemical components experiencing dilution in leaching. This extended mixing model was used to quantify fracture-matrix interaction in construction-water migration tests along the Exploratory Studies Facility (ESF) tunnel at Yucca Mountain, Nevada, USA. The model effectively recovers the spatial distribution of water and chemical compositions released from the construction water, and provides invaluable data on the matrix fracture interaction. The methodology and formulations described here are applicable to many sorts of mixing-dilution problems, including dilution in petroleum reservoirs, hydrospheres, chemical constituents in rocks and minerals, monitoring of drilling fluids, and leaching, as well as to environmental science studies.

Sea Level and Paleoenvironment Control on Late Ordovician Source Rocks, Hudson Bay Basin, Canada

NASA Astrophysics Data System (ADS)

Zhang, S.; Hefter, J.

2009-05-01

Hudson Bay Basin is one of the largest Paleozoic sedimentary basins in North America, with Southampton Island on its north margin. The lower part of the basin succession comprises approximately 180 to 300 m of Upper Ordovician strata including Bad Cache Rapids and Churchill River groups and Red Head Rapids Formation. These units mainly comprise carbonate rocks consisting of alternating fossiliferous limestone, evaporitic and reefal dolostone, and minor shale. Shale units containing extremely high TOC, and interpreted to have potential as petroleum source rocks, were found at three levels in the lower Red Head Rapids Formation on Southampton Island, and were also recognized in exploration wells from the Hudson Bay offshore area. A study of conodonts from 390 conodont-bearing samples from continuous cores and well cuttings from six exploration wells in the Hudson Bay Lowlands and offshore area (Comeault Province No. 1, Kaskattama Province No. 1, Pen Island No. 1, Walrus A-71, Polar Bear C-11 and Narwhal South O-58), and about 250 conodont-bearing samples collected from outcrops on Southampton Island allows recognition of three conodont zones in the Upper Ordovician sequence, namely (in ascendant sequence) Belodina confluens, Amorphognathus ordovicicus, and Rhipidognathus symmetricus zones. The three conodont zones suggest a cycle of sea level changes of rising, reaching the highest level, and then falling during the Late Ordovician. Three intervals of petroleum potential source rock are within the Rhipidognathus symmetricus Zone in Red Head Rapids Formation, and formed in a restricted anoxic and hypersaline condition during a period of sea level falling. This is supported by the following data: 1) The conodont Rhipidognathus symmetricus represents the shallowest Late Ordovician conodont biofacies and very shallow subtidal to intertidal and hypersaline condition. This species has the greatest richness within the three oil shale intervals to compare other parts of Red Head Rapids Formation. 2) Type I kerogen is normally formed in quiet, oxygen-deficient, shallow water environment. Rock-Eval6 data from 40 samples of the three oil shale intervals, collected from outcrops on Southampton Island, demonstrate that the proportion of Type I kerogen gradually increases in the mixed Type I-Type II kerogen from the lower to upper oil shale intervals. 3) Pristane/phytane ratio can be used as a paleoenvironment indicator. The low ratios in the three oil shale intervals range from 0.5 to 0.9 and indicate anoxic and hypersaline conditions. In addition, the presence of isorenieratene derivatives from green phototrophic sulfur bacteria (Chlorobiaceae), with highest relative concentrations in the lower oil shale intervals, points to anoxia reaching into the photic zone of the water column.

Water and Proppant Requirements and Water Production Associated with Undiscovered Petroleum in the Bakken and Three Forks Formations, North Dakota and Montana, USA

NASA Astrophysics Data System (ADS)

Haines, S. S.; Varela, B. A.; Thamke, J.; Hawkins, S. J.; Gianoutsos, N. J.; Tennyson, M. E.

2017-12-01

Water is used for several stages of oil and gas production, in particular for hydraulic fracturing that is typically used during production of petroleum from low-permeability shales and other rock types (referred to as "continuous" petroleum accumulations). Proppant, often sand, is also consumed during hydraulic fracturing. Water is then produced from the reservoir along with the oil and gas, representing either a disposal consideration or a possible source of water for further petroleum development or other purposes. The U.S. Geological Survey (USGS) has developed an approach for regional-scale estimation of these water and proppant quantities in order to provide an improved understanding of possible impacts and to help with planning and decision-making. Using the new methodology, the USGS has conducted a quantitative assessment of water and proppant requirements, and water production volumes, associated with associated with possible future production of undiscovered petroleum resources in the Bakken and Three Forks Formations, Williston Basin, USA. This water and proppant assessment builds directly from the 2013 USGS petroleum assessment for the Bakken and Three Forks Formations. USGS petroleum assessments incorporate all available geologic and petroleum production information, and include the definition of assessment units (AUs) that specify the geographic regions and geologic formations for the assessment. The 2013 petroleum assessment included 5 continuous AUs for the Bakken Formation and one continuous AU for the Three Forks Formation. The assessment inputs are defined probabilistically, and a Monte Carlo approach provides outputs that include uncertainty bounds. We can summarize the assessment outputs with the mean values of the associated distributions. The mean estimated total volume of water for well drilling and cement for all six continuous AUs is 5.9 billion gallons, and the mean estimated volume of water for hydraulic fracturing for all AUs is 164.3 billion gallons. The mean estimated quantity of proppant for hydraulic fracturing is 101.3 million tons. Summing over all of the AUs, the mean estimated total flowback water volume is 9.9 billion gallons and the mean estimated total produced water is 414.5 billion gallons.

Profiles of Reservoir Properties of Oil-Bearing Plays for Selected Petroleum Provinces in the United States

USGS Publications Warehouse

Freeman, P.A.; Attanasi, E.D.

2015-11-05

Each province profile figure consists of five strip charts and a boxplot. The five strip charts display for individual plays the following reservoir-fluid and reservoir properties: A, oil density (American Petroleum Institute [API] gravity in degrees); B, computed pseudo-Dykstra-Parsons coefficient; C, reservoir porosity (in percent); D, reservoir permeability (in millidarcies); and E, estimates of the original oil in place (OOIP) per unit volume of reservoir rock (in barrels per acre-foot). The OOIP per unit volume of reservoir rock is an indicator of the relative richness of the oil reservoir and is derived from estimates in the CRD of OOIP, reservoir acreage, and net pay. The net pay is the interval of productive reservoir rock. The same data for OOIP per unit volume are graphed as a strip chart (E) and a boxplot (F).

Environmental Assessment/Section 404(b) Evaluation and Finding of no Significant Impact for the Main-Tenance Dredging of the Black Rock Harbor-Cedar Creek Federal Navigation Channel, Bridgeport, Connecticut.

DTIC Science & Technology

1982-07-01

petroleum hydrocarbons will be bioaccumulated in quantity. In view of the findings noted above special handling of the sediments would appear appropriate...indicate the fractions of the generic group, petroleum hydrocarbons , that were analyzed. This information is needed for interpreting the bioaccumulation ...results for petroleum hydrocarbons . We continue to object to the use of two controls in the bioassay/ bioaccumulation tests. We also question the use of a

Organic geochemistry, lithology, and paleontology of Tertiary and Mesozoic rocks from wells on the Alaska Peninsula

USGS Publications Warehouse

McLean, Hugh James

1977-01-01

Core chips and drill cuttings from eight of the nine wells drilled along the Bering Sea lowlands of the Alaska Peninsula were subjected to lithologic and paleontologic analyses. Results suggest that at least locally, sedimentary rocks of Tertiary age contain oil and gas source and reservoir rocks capable of generating and accumulating liquid and gas hydrocarbons. Paleogene strata rich in organic carbon are immature. However, strata in offshore basins to the north and south may have been subjected to a more productive thermal environment. Total organic carbon content of fine grained Neogene strata appears to be significantly lower than in Paleogene rocks, possibly reflecting nonmarine or brackish water environments of deposition. Neogene sandstone beds locally yield high values of porosity and permeability to depths of about 8,000 feet (2,439 m). Below this depth, reservoir potential rapidly declines. The General Petroleum, Great Basins No. 1 well drilled along the shore of Bristol Bay reached granitic rocks. Other wells drilled closer to the axis of the present volcanic arc indicate that both Tertiary and Mesozoic sedimentary rocks have been intruded by dikes and sills of andesite and basalt. Although the Alaska Peninsula has been the locus of igneous activity throughout much of Mesozoic and Tertiary time, thermal maturity indicators such as vitrinite reflectance and coal rank suggest, that on a regional scale, sedimentary rocks have not been subjected to abnormally high geothermal gradients.

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

USGS Publications Warehouse

Schenk, Christopher J.; Nelson, Philip H.; Klett, Timothy R.; Le, Phuong A.; Anderson, Christopher P.; Schenk, Christopher J.

2015-01-01

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

Petroleum systems of Zhu III depression in Pearl River Mouth Basin, South China Sea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Weilin, Zhu; Li Mingbi; Wu Peikang

Zhu III depression is located in the west part of Pearl River Mouth Basin, and covers an area of 11,000 sq km. Until now more than twenty wells have been drilled in the depression and its surrounding area, and all oil-gas fields and oil-gas discoveries are concentrated inside the depression. Integrated study indicates that there are two petroleum systems in Zhu III depression. One is Wenchang - Zhuhai, Zhujiang oil system which is mainly distributed in Wenchang B sag in the southwest part of the depression. Its source rock, the Wenchang formation is mainly composed of dark mudstone of lacustrinemore » facies, with thicknesses up to more than 1000 m. Its reservoir includes tidal sandstone of transitional facies of Zhuhai formation and neritic sandstone of the lower part of Zhujiang formation. Through bounding faults and margin coarse sediment zone, oil generated from the Wenchang formation migrated into overlying sandstone of Zhuhai formation, which was overlaid by mudstone beds of bay facies of Zhuhai formation or neritic facies of Zhujiang formation, and formed oil accumulations. The other system is Enping - Zhuhai gas system, distributed in Wenchang A sag in the northeast part of the depression, whose source rock in the Enping formation deposited in the contracting stage of the lake, dominated by swamp coal measure in lithology and terrestrial plant clastics in kerogen components. The gas generated from Enping formation directly migrated into overlying tidal sandstone of Zhuhai formation and formed gas accumulations. Therefore, exploration in Wenchang A sag in the northeast part of the depression is for gas accumulations, and oil accumulations in Wenchang B sag in the southwest part of the depression, while oil-gas mixed accumulations are likely to be found in the transitional area of two systems.« less

New exploration approach: Pennsylvanian Lower Tyler central Montana

DOE Office of Scientific and Technical Information (OSTI.GOV)

Shepard, W.

Modern exploration methods utilizing a plate tectonics structural model and a recent alluvial valley analog, the Brazos from the Texas Gulf Coast, have helped revive interest in Pennsylvanian Lower Tyler exploration in the central Montana petroleum province. The central Montana trough is now visualized as an aulacogen, reaching from the Rocky Mountain trench near Butte, Montana, eastward to the Williston basin. It is 60 mi wide by about 400 mi long. Pennsylvanian Lower Tyler sediments occur in this narrow east-west-trending rift system. The regional setting is an aulacogen, or intracratonic rift, that connected the Williston basin to the Cordilleran geosynclinemore » during much of geologic time, beginning in late Precambrian. The Lower Tyler is a westward-draining Pennsylvanian (Morrowan) alluvial valley-fill system consisting of a number of river valleys that funneled into the topographic low of the aulacogen. Rift-controlled, estuarine, euxinic limestones and shales above and below the Lower Tyler provide petroleum-rich source rocks. These source rocks are mature and have generated oil, probably in the Paleocene and early Eocene. The modern Brazos River Valley of southeastern Texas is a near mirror-image analog for Lower Tyler alluvial valley fill. The Brazos valleys are 6 mi wide, 150 to 300 ft thick, and contain 60 to 70% backswamp shales and silts. Point-bar sands constitute a relatively small portion of the valley fill; the sands are 60 to 70 ft thick and about 3000 ft wide. Diagenesis has decreased net porosity distribution in the Lower Tyler to less than that of the Brazos, yet porosity parameters may still be applied to exploration in the Tyler sandstones.« less

Petroleum geochemistry of oils and rocks in Arctic National Wildlife Refuge, Alaska

DOE Office of Scientific and Technical Information (OSTI.GOV)

Magoon, L.B.; Anders, D.E.

1987-05-01

Thirteen oil seeps or oil-stained outcrops in or adjacent to the coastal plain of the Arctic National Wildlife Refuge (ANWR) in northeastern Alaska indicate that commercial quantities of hydrocarbons may be present in the subsurface. The area is flanked by two important petroleum provinces: the Prudhoe Bay area on the west and the Mackenzie delta on the east. Organic carbon content (wt. %), organic matter type, and pyrolysis hydrocarbon yield show that rock units such as the Kingak Shale (average 1.3 wt. %), pebble shale unit (2.1 wt. %), and Canning Formation (1.9 wt. %) contain predominantly type III organicmore » matter. The exception is the Hue Shale (5.9 wt. %), which contains type II organic matter. Pre-Cretaceous rocks that crop out in the Brooks Range could not be adequately evaluated because of high thermal maturity. Thermal maturity thresholds for oil, condensate, and gas calculated from vitrinite reflectance gradients in the Point Thomson area are 4000, 7300, and 9330 m, respectively (12,000, 22,500, and 28,000 ft). Time-temperature index (TTI) calculations for the Beli-1 and Point Thomson-1 wells immediately west of ANWR indicate that maturity first occurred in the south and progressed north. The Cretaceous Hue Shale matured in the Beli-1 well during the Eocene and in the Point Thomson-1 well in the late Miocene to early Pliocene. In the Point Thomson area, the condensate and gas recovered from the Thomson sandstone and basement complex based on API gravity and gas/oil ratio (GOR) probably originated from the pebble shale unit, and on the same basis, the oil recovered from the Canning Formation probably originated from the Hue Shale. The gas recovered from the three wells in the Kavik area is probably thermal gas from overmature source rocks in the immediate area.« less

Soda Lake-Painted Rock(!) Petroleum System in the Cuyama Basin, California, U.S.A.

USGS Publications Warehouse

Lillis, Paul G.

1994-01-01

The Cuyama basin, located in the central California Coast Ranges, was formed by extension during early Miocene time and was filled with a variety of nonmarine, marginal marine, and neritic to bathyal marine sediments. Low sulfur oil is produced primarily from the lower Miocene Painted Rock Sandstone Member of the Vaqueros Formation along a structural trend parallel to the Russell fault, which was active from 23 to 5 Ma. A major fold and thrust belt beginning about 3 Ma formed the Caliente and Sierra Madre ranges and partially obscures the Miocene extensional basin. Stable carbon isotope and biomarker data indicate that the lower Miocene Soda Lake Shale Member of the Vaqueros Formation is the predominant source rock for the oil in the Cuyama area. Burial and thermal history modeling shows that oil generation began in middle-late Miocene time and that oil migrated into existing traps. Younger traps that formed in the overthrust are barren of oil because migration occurred prior to the development of the fold and thrust belt or because subthrust oil was unable to migrate into the overthrust.

Uzbek licensing round brings geology, potential into focus

DOE Office of Scientific and Technical Information (OSTI.GOV)

Heafford, A.P.; Lichtman, G.S.

1993-08-09

Uzbekistan is a Central Asian Republic that declared independence from the former Soviet Union in 1991. Uzbekistan produces about 18 million bbl/year of oil and 40 bcf/year of gas. It is the third largest gas producer in the Commonwealth of Independent States and imports oil. The Uzbek government and oil and gas industry are offering exploration acreage for foreign participation via competitive bid. Acreage on offer includes fields for development and unproven-underexplored areas. Terms awaiting approval by the Cabinet of Ministers provide financial incentives for rapid development of existing reserves, creation of required infrastructure, and long term investment growth. Licensemore » areas concentrate on acreage where western equipment and technology can bring new reserves economically on line in the near future. National oil company Uzbekneftegaz was created in 1992 to oversee the extraction, transport, and refining of hydrocarbons in Uzbekistan. The paper describes some of the fields and infrastructure in place, the structural geology, stratigraphy, petroleum distribution, source rocks, reservoir rocks, cap rocks, traps, and hydrocarbon composition, which includes oil, gases, and gas condensates.« less

Petroleum geology and resources of the middle Caspian Basin, Former Soviet Union

USGS Publications Warehouse

Ulmishek, Gregory F.

2001-01-01

The Middle Caspian basin occupies a large area between the Great Caucasus foldbelt and the southern edge of the Precambrian Russian craton. The basin also includes the central part of the Caspian Sea and the South Mangyshlak subbasin east of the sea. The basin was formed on the Hercynian accreted terrane during Late Permian?Triassic through Quaternary time. Structurally, the basin consists of the fold-and-thrust zone of the northern Caucasus foothills, the foredeep and foreland slope, the Stavropol-Prikumsk uplift and East Manych trough to the north of the slope, and the South Mangyshlak subbasin and slope of the Karabogaz arch east of the Caspian Sea. All these major structures extend offshore. Four total petroleum systems (TPS) have been identified in the basin. The South Mangyshlak TPS contains more than 40 discovered fields. The principal reserves are in Lower?Middle Jurassic sandstone reservoirs in structural traps. Source rocks are poorly known, but geologic data indicate that they are in the Triassic taphrogenic sequence. Migration of oil and gas significantly postdated maturation of source rocks and was related to faulting and fracturing during middle Miocene to present time. A single assessment unit covers the entire TPS. Largest undiscovered resources of this assessment unit are expected in the largely undrilled offshore portion of the TPS, especially on the western plunge of the Mangyshlak meganticline. The Terek-Caspian TPS occupies the fold-and-thrust belt, foredeep, and adjoining foreland slope. About 50 hydrocarbon fields, primarily oil, have been discovered in the TPS. Almost all hydrocarbon reserves are in faulted structural traps related to thrusting of the foldbelt, and most traps are in frontal edges of the thrust sheets. The traps are further complicated by plastic deformation of Upper Jurassic salt and Maykop series (Oligocene? lower Miocene) shale. Principal reservoirs are fractured Upper Cretaceous carbonates and middle Miocene sandstones. Principal source rocks are organic-rich shales in the lower part of the Maykop series. Source rocks may also be present in the Eocene, Upper Jurassic, and Middle Jurassic sections, but their contribution to discovered reserves is probably small. Three assessment units are delineated in the TPS. One of them encompasses the thrust-and-fold belt of northern Caucasus foothills. This assessment unit contains most of the undiscovered oil resources. The second assessment unit occupies the foredeep and largely undeformed foreland slope. Undiscovered resources of this unit are relatively small and primarily related to stratigraphic traps. The third unit is identified in almost untested subsalt Jurassic rocks occurring at great depths and is speculative. The unit may contain significant amounts of gas under the Upper Jurassic salt seal. The Stavropol-Prikumsk TPS lies north of the Terek-Caspian TPS and extends offshore into the central Caspian Sea where geologic data are scarce. More than one hundred oil and gas fields have been found onshore. Offshore, only one well was recently drilled, and this well discovered a large oil and gas field. Almost the entire sedimentary section of the TPS is productive; however, the principal oil reserves are in Lower Cretaceous clastic reservoirs in structural traps of the Prikumsk uplift. Most original gas reserves are in Paleogene reservoirs of the Stavropol arch and these reservoirs are largely depleted. At least three source rock formations, in the Lower Triassic, Middle Jurassic, and Oligocene?lower Miocene (Maykop series), are present in the TPS. Geochemical data are inadequate to correlate oils and gases in most reservoirs with particular source rocks, and widespread mixing of hydrocarbons apparently took place. Three assessment units encompassing the onshore area of the TPS, the offshore continuation of the Prikumsk uplift, and the central Caspian area, are identified. The

Geochemical evaluation of Niger Delta sedimentary organic rocks: a new insight

NASA Astrophysics Data System (ADS)

Akinlua, Akinsehinwa; Torto, Nelson

2011-09-01

A geochemical evaluation of Niger Delta organic matter was carried out using supercritical fluid extraction (SFE) sample preparation procedure. Comparison of geochemical significance of gas chromatographic data of rock extracts of SFE with those of Soxhlet extraction method from previous studies was made in order to establish the usefulness of SFE in geochemical exploration. The assessment of geochemical character of the rock samples from the comparison and interpretation of other geochemical parameters were used to give more insights into understanding the source rocks characteristics of onshore and shelf portions of the Niger Delta Basin. The results of the gas chromatographic (GC) analysis of the rock extracts across the lithostratigraphic units show that Pr/Ph, Pr/nC17, Pr/nC18, CPI and odd/even preference ranged from 0.07 to 12.39, 0.04 to 6.66, 0.05 to 13.80, 0.12 to 8.4 and 0.06 to 8.12, respectively. The Rock-Eval pyrolysis data and geochemical ratios and parameters calculated from the GC data showed that most of the samples are mature and have strong terrestrial provenance while a few samples have strong marine provenance. The few marine source rocks are located in the deeper depth horizon. Pr/Ph and standard geochemical plots indicate that most of samples were derived from organic matter deposited in less reducing conditions, i.e. more of oxidizing conditions while a few samples have predominantly influence of reducing conditions. The results of trace metal analysis of older samples from Agbada Formation also indicate marine and mixed organic matter input deposited in less reducing conditions. The results obtained in this study are comparable with those obtained from previous studies when Soxhlet extraction method was used and also indicated the presence of more than one petroleum systems in the Niger Delta.

Revisions to the original extent of the Devonian Shale-Middle and Upper Paleozoic Total Petroleum System

USGS Publications Warehouse

Enomoto, Catherine B.; Rouse, William A.; Trippi, Michael H.; Higley, Debra K.

2016-04-11

Technically recoverable undiscovered hydrocarbon resources in continuous accumulations are present in Upper Devonian and Lower Mississippian strata in the Appalachian Basin Petroleum Province. The province includes parts of New York, Pennsylvania, Ohio, Maryland, West Virginia, Virginia, Kentucky, Tennessee, Georgia, and Alabama. The Upper Devonian and Lower Mississippian strata are part of the previously defined Devonian Shale-Middle and Upper Paleozoic Total Petroleum System (TPS) that extends from New York to Tennessee. This publication presents a revision to the extent of the Devonian Shale-Middle and Upper Paleozoic TPS. The most significant modification to the maximum extent of the Devonian Shale-Middle and Upper Paleozoic TPS is to the south and southwest, adding areas in Tennessee, Georgia, Alabama, and Mississippi where Devonian strata, including potential petroleum source rocks, are present in the subsurface up to the outcrop. The Middle to Upper Devonian Chattanooga Shale extends from southeastern Kentucky to Alabama and eastern Mississippi. Production from Devonian shale has been established in the Appalachian fold and thrust belt of northeastern Alabama. Exploratory drilling has encountered Middle to Upper Devonian strata containing organic-rich shale in west-central Alabama. The areas added to the TPS are located in the Valley and Ridge, Interior Low Plateaus, and Appalachian Plateaus physiographic provinces, including the portion of the Appalachian fold and thrust belt buried beneath Cretaceous and younger sediments that were deposited on the U.S. Gulf Coastal Plain.

2-Methylhopanoids: Biomarkers for Cyanobacteria and for Oxygenic Photosynthesis

NASA Technical Reports Server (NTRS)

Summons, R. E.; Jahnke, L. L.; Hope, J. M.; Logan, G. A.

1999-01-01

This paper reports new biomarker and carbon isotopic data for cultured cyanobacteria, cyano-bacterially- dominated ecosystems and ancient sedi-ments and petroleum. We found that cyanobacteria are the predominant source of a distinctive membrane lipid biomarker, namely 2- methylbacteriohopanepolyol (2-Me-BHP). We then sought evidence for a geochemical record of the fossil hydrocarbon analogues of these compounds (2- methylhopanes) and found a trend toward their in-creased relative abundance in marine sediments going back through geological time to 2500 Ma. We conclude that cyanobacteria were the dominant form of phytoplankton and source of molecular oxygen in the Proterozoic ocean. Extending the geological record of cyanobacteria further to Archean times is now a matter of finding a suitably preserved rock record. Additional information is contained in the original extended abstract.

Petroleum and individual polycyclic aromatic hydrocarbons

USGS Publications Warehouse

Albers, Peter H.; Hoffman, David J.; Rattner, Barnett A.; Burton, G. Allen; Cairns, John

1995-01-01

Crude petroleum, refined-petroleum products, and individual polycyclic aromatic hydrocarbons (PAHs) contained within petroleum are found throughout the world. their presence has been detected in living and nonliving components of ecosystems. Petroleum can be an environmental hazard for wild animals and plants. Individual PAHs are also hazardous to wildlife, but they are most commonly associated with human illnesses. Because petroleum is a major environmental source of these PAHs, petroleum and PAHs are jointly presented in this chapter. Composition, sources, environmental fate, and toxic effects on all living components of aquatic and terrestrial environments are addessed.

Alaska: A twenty-first-century petroleum province

USGS Publications Warehouse

Bird, K.J.

2001-01-01

Alaska, the least explored of all United States regions, is estimated to contain approximately 40% of total U.S. undiscovered, technically recoverable oil and natural-gas resources, based on the most recent U.S. Department of the Interior (U.S. Geological Survey and Minerals Management Service) estimates. Northern Alaska, including the North Slope and adjacent Beaufort and Chukchi continental shelves, holds the lion's share of the total Alaskan endowment of more than 30 billion barrels (4.8 billion m3) of oil and natural-gas liquids plus nearly 200 trillion cubic feet (5.7 trillion m3) of natural gas. This geologically complex region includes prospective strata within passive-margin, rift, and foreland-basin sequences. Multiple source-rock zones have charged several regionally extensive petroleum systems. Extensional and compressional structures provide ample structural objectives. In addition, recent emphasis on stratigraphic traps has demonstrated significant resource potential in shelf and turbidite systems in Jurassic to Tertiary strata. Despite robust potential, northern Alaska remains a risky exploration frontier - a nexus of geologic complexity, harsh economic conditions, and volatile policy issues. Its role as a major petroleum province in this century will depend on continued technological innovations, not only in exploration and drilling operations, but also in development of huge, currently unmarketable natural-gas resources. Ultimately, policy decisions will determine whether exploration of arctic Alaska will proceed.

Biomarker chemistry and flux quantification methods for natural petroleum seeps and produced oils, offshore southern California

USGS Publications Warehouse

Lorenson, T.D.; Leifer, Ira; Wong, Florence L.; Rosenbauer, Robert J.; Campbell, Pamela L.; Lam, Angela; Hostettler, Frances D.; Greinert, Jens; Finlayson, David P.; Bradley, Eliza S.; Luyendyk, Bruce P.

2011-01-01

Sustained, natural oil seepage from the seafloor is common off southern California, and is of great interest to resource managers, who are tasked with distinguishing natural from anthropogenic oil sources. The major purpose of this study was to build upon the work previously funded by the Bureau of Ocean Energy Management (BOEM) and the U.S. Geological Survey (USGS) that has refined the oil-fingerprinting process to enable differentiation of the highly similar Monterey Formation oils from Outer Continental Shelf (OCS) production and adjacent natural seeps. In these initial studies, biomarker and stable carbon isotope ratios were used to infer the age, lithology, organic-matter input, and depositional environment of the source rocks for 388 samples of produced crude oil, seep oil, and tarballs mainly from coastal California. The analysis resulted in a predictive model of oil source families that could be applied to samples of unknown origin.

Winters-Domengine Total Petroleum System—Northern Nonassociated Gas Assessment Unit of the San Joaquin Basin Province: Chapter 21 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Hosford Scheirer, Allegra; Magoon, Leslie B.

2008-01-01

The Northern Nonassociated Gas Assessment Unit (AU) of the Winters-Domengine Total Petroleum System of the San Joaquin Basin Province consists of all nonassociated gas accumulations in Cretaceous, Eocene, and Miocene sandstones located north of township 15 South in the San Joaquin Valley. The northern San Joaquin Valley forms a northwest-southeast trending asymmetrical trough. It is filled with an alternating sequence of Cretaceous-aged sands and shales deposited on Franciscan Complex, ophiolitic, and Sierran basement. Eocene-aged strata unconformably overlie the thick Cretaceous section, and in turn are overlain unconformably by nonmarine Pliocene-Miocene sediments. Nonassociated gas accumulations have been discovered in the sands of the Panoche, Moreno, Kreyenhagen, andDomengine Formations and in the nonmarine Zilch formation of Loken (1959) (hereafter referred to as Zilch formation). Most hydrocarbon accumulations occur in low-relief, northwest-southeast trending anticlines formed chiefly by differential compaction of sediment and by northeast southwest directed compression during the Paleogene (Bartow, 1991) and in stratigraphic traps formed by pinch out of submarine fan sands against slope shales. To date, 176 billion cubic feet (BCF) of nonassociated recoverable gas has been found in fields within the assessment unit (table 21.1). A small amount of biogenic gas forms near the surface of the AU. Map boundaries of the assessment unit are shown in figures 21.1 and 21.2; in plan view, this assessment unit is identical to the Northern Area Nonassociated Gas play 1007 considered by the U.S. Geological Survey (USGS) in its 1995 National Assessment (Beyer, 1996). The AU is bounded on the east by the mapped limits of Cretaceous sandstone reservoir rocks and on the west by the east flank of the Diablo Range. The southern limit of the AU is the southernmost occurrence of nonassociated thermogenic-gas accumulations. The northern limit of the AU corresponds to the Stanislaus-San Joaquin county line, which also defines the northern boundary of the San Joaquin Basin Province. In the vertical dimension, the AU extends from the uppermost crystalline basement to the topographic surface (fig. 21.3), to allow for the possibility of down-section charge across fault surfaces and up-dip migration. The gas in this AU may be sourced from the Winters- Domengine(?) petroleum system, located in the Sacramento Valley north of the San Joaquin Valley, as defined by Magoon and others (1994a,b) (question mark notation derives from convention of Magoon and Dow, 1994, and indicates speculative genetic relationship between hydrocarbons and source rock). The Winters-Domengine Total Petroleum System defined for this assessment contains about 7.2 trillion cubic feet (TCF) of known, recoverable gas and includes the Rio Vista gas field, which alone accounts for 4 TCF of recoverable gas through 2002 (CDOGGR, 2003). Alternatively, the northern nonassociated gas may be sourced from the Moreno Formation within the San Joaquin Valley itself.

Petroleum system of the Gippsland Basin, Australia

USGS Publications Warehouse

Bishop, Michele G.

2000-01-01

The Gippsland Basin Province 3930, located on the southeastern coast of Australia, is formed from two successive failed rifts that developed into a passive margin during the Cretaceous. Formation of this basin is related to the break up of Gondwana, which resulted in the separation of Antarctica from Australia, and the separation of the New Zealand and Lord Howe Rise continental crust from Australia. Coals and coaly shales of Late Cretaceous through Eocene age are the source rocks for oil and gas that accumulated predominantly in anticlinal traps. The basin was Australia?s major producing basin until 1996 when daily oil/condensate production from the North West Shelf surpassed it.

Hydrocarbon plays evaluation of eastern China

DOE Office of Scientific and Technical Information (OSTI.GOV)

Wu Shou Cheng

1991-03-01

In eastern China there are 78 depressed basins, most of which are tilt-block basins. Each of them engenders petroleum generation except the Cretaceous sag basin of Song-Liao. These depressed basins set up in the order of older to younger depending on the change of the mantle convection. Consequently, the order of sedimentation and source-reservoir are changed and the exploration targets are also changed. Tan-Lu fault system is of great significance in NNW (early) and NEE (later) accompanying faults for exploration play. The hydrocarbon accumulation rules of these plays are: (1) As a result of the Tertiary tilt-block basins, compaction-flow basinsmore » contain similar hydrodynamic, thermodynamic, and buried pressure fields. The direction of fluid flow is from generation center of the basin to the margins. So the hydrocarbon plays are distributed nearby the generation center and circum-center belt. (2) The richness of hydrocarbon plays is controlled by the form and distribution of source rock due to structural change of the tilt-block. The richest is the center uplift play and then the low-raised play, steep slope play, gentle-slope play, and, poorest, the low-lying play. (3) A variety of the composite hydrocarbon play models are formed by the different structure models, sedimentary model, and hydrocarbon model. Most of the recovery reserves are set in one or two plays even though there are many hydrocarbon plays in a tilt-block basin. (4) There are 3 types and 25 subtypes of petroleum pools formed by the different characters of plays. Therefore, there are numerous technologies, methodologies, and strategies of petroleum exploration.« less

Laboratory measurements of the effective-stress law of carbonate rocks under deformation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Warpinski, N.R.; Teufel, L.W.

The behavior of rocks under the combined effects of confining stress and pore pressure is an important issue for any in situ petroleum process. In order to simplify the difficulties in dealing with two independent parameters, it is customary to introduce an effective-stress law which relates a net, or effective, stress to some combination of confining stress and pore pressure. This report documents laboratory tests of mechanical properties of five carbonate rocks.

Conference on the topic: {open_quotes}Exploration and production of petroleum and gas from chalk reservoirs worldwide{close_quotes}

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kuznetsov, V.G.

1995-07-01

More than 170 delegates from 14 countries in Europe, North America, Africa, and Asia took part in a conference on the topic: Exploration and Production of Petroleum and Gas from Chalk Reservoirs Worldwide. The conference was held in Copenhagen, Denmark in September,1994, and was a joint meeting of the American Association of Petroleum Geologists (AAPG), and the European Association of Petroleum Geoscientists and Engineers (EAPG). In addition to the opening remarks, 25 oral and nine poster reports were presented. The topics included chalk deposits as reservoir rocks, the occurrence of chalk deposits worldwide, the North Sea oil and gas fields,more » and other related topics.« less

Summary report on the regional geology, environmental considerations for development, petroleum potential, and estimates of undiscovered recoverable oil and gas resources of the United States southeastern Atlantic continental margin in the area of proposed oil and gas lease sale No. 78

USGS Publications Warehouse

Dillon, William P.

1981-01-01

This report summarizes our general knowledge of the geology and petroleum potential, as well as potential problems and hazards associated with development of petroleum resources, of the area proposed for nominations for lease sale number 78. This area includes the U.S. eastern continental margin from the mouth of Chesapeake Bay to approximately Cape Canaveral, Florida, including the upper Continental Slope and inner Blake Plateau. The area for possible sales and the previous areas leased are shown in figure 1; physiographic features of the region are shown in figure 2. Six exploration wells have been drilled within the proposed lease area (figs. 3 and 4) but no commercial discoveries have been made. All six wells were drilled on the Continental Shelf in the Southeast Georgia Embayment. No commercial production has been obtained onshore in the region. The areas already drilled have thin sedimentary sections, and the deeper rocks are dominantly continental facies. Petroleum formation may have been hindered by a lack of organic material and sufficient burial for thermal maturation. Analysis of drill and seismic profiling data presented here, however, indicates that a much thicker sedimentary rock section containing a much higher proportion of marine deposits exists seaward of the exploratory wells on the Continental Shelf. These geologic conditions imply that the offshore basins may be more favorable environments for generating petroleum.

Hydrocarbon potential of Central Monagas, Eastern Venezuela Basin, Venezuela

DOE Office of Scientific and Technical Information (OSTI.GOV)

Barrios, F.; Daza, J.; Iusco, G.

1996-08-01

The Central Monagas area is part of the foreland sub-basin located on the southern flank of the Eastern Venezuela Basin. The sedimentary column of the Central Monagas is at least 7500 in thick and consists of Mesozoic (Cretaceous) and Cenozoic rocks. Interpretations of 60 regional seismic sections have been integrated with data from 12 existing wells, which cover an area of 1200 km{sup 2}. From these interpretations, basin-wide structure and interval isopach maps were constructed in order to aid the depiction of the basin architecture and tectonic history. The sub-basin developed on the southern flank of the Eastern Venezuela Basinmore » is tightly linked to its evolution from a Mesozoic extensional regime into a Cenozoic compressional and strike-slip stage. The basin formed in the Middle Mesozoic by crustal extension of a rifting process. Regional northward tilting of the slab continued during the Late Cretaceous. Finally, the transpression of the Caribbean Plate during the Oligocene-Neogene induced the overprint of compressional deformation associated with the deposition of a foredeep wedge. Geochemical source rock analysis gave an average of 1.2 TOC, and R{sub o} of 0.66 indicating a mature, marine source. The modeling of the hydrocarbon generative history of the basin indicates that the oil migration started in the Middle Miocene, after the trap was formed. Analysis and mapping of reservoir rocks and seal rocks defined the effective area limits of these critical factors. The main play in the area is the extension of the Lower Oficina Formation which is the proven petroleum target in the Eastern Venezuela Basin.« less

Ground-based hyperspectral imaging and terrestrial laser scanning for fracture characterization in the Mississippian Boone Formation

NASA Astrophysics Data System (ADS)

Sun, Lei; Khan, Shuhab D.; Sarmiento, Sergio; Lakshmikantha, M. R.; Zhou, Huawei

2017-12-01

Petroleum geoscientists have been using cores and well logs to study source rocks and reservoirs, however, the inherent discontinuous nature of these data cannot account for horizontal heterogeneities. Modern exploitation requires better understanding of important source rocks and reservoirs at outcrop scale. Remote sensing of outcrops is becoming a first order tool for reservoir analog studies including horizontal heterogeneities. This work used ground-based hyperspectral imaging, terrestrial laser scanning (TLS), and high-resolution photography to study a roadcut of the Boone Formation at Bella Vista, northwest Arkansas, and developed an outcrop model for reservoir analog analyses. The petroliferous Boone Formation consists of fossiliferous limestones interbedded with chert of early Mississippian age. We used remote sensing techniques to identify rock types and to collect 3D geometrical data. Mixture tuned matched filtering classification of hyperspectral data show that the outcrop is mostly limestones with interbedded chert nodules. 1315 fractures were classified according to their strata-bounding relationships, among these, larger fractures are dominantly striking in ENE - WSW directions. Fracture extraction data show that chert holds more fractures than limestones, and both vertical and horizontal heterogeneities exist in chert nodule distribution. Utilizing ground-based remote sensing, we have assembled a virtual outcrop model to extract mineral composition as well as fracture data from the model. We inferred anisotropy in vertical fracture permeability based on the dominancy of fracture orientations, the preferential distribution of fractures and distribution of chert nodules. These data are beneficial in reservoir analogs to study rock mechanics and fluid flow, and to improve well performances.

Petroleum potential of wilderness lands in the Western United States

USGS Publications Warehouse

Miller, Betty M.

1983-01-01

In 1982-83, the U.S. Geological Survey (USGS) conducted an investigation of the oil and gas potential of the designated and proposed Wilderness Lands in the Western United States. The scope of this study was limited to the assessment of conventional recoverable petroleum resources occurring in the designated and proposed Wilderness Lands of the Western United States that are administered under four Federal agencies: Bureau of Land Management (BLM), U.S. Forest Service (USFS), National Park Service (NPS), and Fish and Wildlife Service (FWS). The total area of the study included approximately 74 million acres of Wilderness Lands in these 11 Western States: Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming. The 74 million acres represent 31 percent of the total Federal lands within these 11 Western States. Approximately 49 percent of all the lands in these States are federally owned. The objective of this study was to assemble through various means all the available pertinent information that could be brought together within the USGS and integrate these data into a computer-based digital cartographic data system that was focused upon the single issue of reviewing the known geological and geophysical data to determine the geologic characteristics favorable or unfavorable for the occurrence of petroleum resources in these Wilderness Lands. In a joint effort in the USGS between the Geologic Division (GD) and the National Mapping Division (NMD) all of the mappable information used in this study was prepared and processed by using digital cartographic techniques. These include digitizing the location and boundaries of the Wilderness Lands; acreage calculations; the boundaries of the USGS petroleum provinces; and the geologic and tectonic boundaries within each petroleum province and State. In addition, searches were conducted on well data files which provided the locations and geologic information on over 5,000 wells drilled within or immediately adjacent to the Wilderness Lands. An analysis of all the geologic characteristics favorable or unfavorable for petroleum occurrence in conjunction with the geologic settings for the Wilderness Lands scattered within the framework of the petroleum provinces was performed by a team of geologists on each of the wilderness tracts. The geologic characteristics reviewed for each tract included the presence or absence of the following: adequate source beds and reservoir rocks; adequate trapping mechanisms; favorable thermal and maturation histories; presence of petroleum seeps or adjacent wells with shows or production; and the presence of favorable sedimentary rock sections underlying volcanic terrane or faulted and overthrust areas. A description of the geology and geologic framework is provided for each State along with an explanation of the interpretative geology and evaluation of the petroleum potential within the locale of each of the wilderness tracts. The assessment of the petroleum resources on the Wilderness Lands was completed in two separate stages. In the first stage the geologists evaluated the geological characteristics for the favorability or lack of favorability for the occurrence of oil and natural gas within each wilderness tract and assigned a qualitative rating for each tract's potential for the occurrence of recoverable oil and gas resources. In the second stage in evaluating the petroleum potential for the wilderness tracts, an effort was made to arrive at a quantitative assessment within the framework of the USGS's latest published resource estimates which are made on a province basis. The geologic characteristics evaluated for the favorability of petroleum occurrence within each of the clusters of wilderness tracts were the determining factors for the subjective assessments of the petroleum potential for each wilderness tract occurring within the respective basin or province. The quantitative resource

SANTA LUCIA WILDERNESS, AND GARCIA MOUNTAIN, BLACK MOUNTAIN, LA PANZA, MACHESNA MOUNTAIN, LOS MACHOS HILLS, BIG ROCKS, AND STANLEY MOUNTAIN ROADLESS AREAS, CALIFORNIA.

USGS Publications Warehouse

Frizzell, Virgil A.; Kuizon, Lucia

1984-01-01

The Santa Lucia Wilderness Area and Garcia Mountain, Black Mountain, La Panza, Machesna Mountain, Los Machos Hills, Big Rocks, and Stanley Mountain Roadless Areas together occupy an area of about 218 sq mi in the Los Padres National Forest, California. On the basis of a mineral-resource evaluation a small area in the Black Mountain Roadless Area has a probable mineral-resource potential for uranium, and a small area in the Stanley Mountain Roadless Area has probable potential for low-grade mercury resources. Although petroleum resources occur in rocks similar to those found in the study area, no potential for petroleum resources was identified in the wilderness or any of the roadless areas. No resource potential for other mineral resources was identified in any of the areas. Detailed geologic mapping and geochemical sampling probably would increase knowledge about distribution and modes of occurrence of uranium and cinnabar in those areas, respectively.

Petroleum source rock evaluation of the Alum and Dictyonema Shales (Upper Cambrian-Lower Ordovician) in the Baltic Basin and Podlasie Depression (eastern Poland)

NASA Astrophysics Data System (ADS)

Kosakowski, Paweł; Kotarba, Maciej J.; Piestrzyński, Adam; Shogenova, Alla; Więcław, Dariusz

2017-03-01

We present geochemical characteristics of the Lower Palaeozoic shales deposited in the Baltic Basin and Podlasie Depression. In the study area, this strata are represented by the Upper Cambrian-Lower Ordovician Alum Shale recognized in southern Scandinavia and Polish offshore and a equivalent the Lower Tremadocian Dictyonema Shale from the northern Estonia and the Podlasie Depression in Poland. Geochemical analyses reveal that the Alum Shale and Dictyonema Shale present high contents of organic carbon. These deposits have the best source quality among the Lower Palaeozoic strata, and they are the best source rocks in the Baltic region. The bituminous shales complex has TOC contents up to ca. 22 wt%. The analysed rocks contain low-sulphur, oil-prone Type-II kerogen deposited in anoxic or sub-oxic conditions. The maturity of the Alum and Dictyonema Shales changes gradually, from the east and north-east to the west and south-west, i.e. in the direction of the Tornquist-Teisseyre Zone. Samples, located in the seashore of Estonia and in the Podlasie region, are immature and in the initial phase of "oil window". The mature shales were found in the central offshore part of the Polish Baltic Basin, and the late mature and overmature are located in the western part of the Baltic Basin. The Alum and Dictyonema Shales are characterized by a high grade of radioactive elements, especially uranium. The enrichment has a syngenetic or early diagenetic origin. The measured content of uranium reached up to 750 ppm and thorium up to 37 ppm.

Organic sedimentation and genesis of petroleum in Mahakam Delta, Borneo

DOE Office of Scientific and Technical Information (OSTI.GOV)

Combaz, A.; de Matharel, M.

1978-09-01

The delta on the eastern coast of Kalimantan, Borneo, is a typical sedimentary-delta model for hydrocarbon accumulation. Because of a remarkable sedimentary continuity since the middle Miocene, three superimposed paleodeltas separated by two transgressive sequences are preserved. Several oil fields have been discovered in the area. Geochemical and microscopic studies of the organic material indicate a history of biochemical and catagenetic degradation, migration of the hydrocarbons generated, and their concentration in the sandstone reservoirs. The organic material in the source rocks generally is of continental and vegetal origin. The oils studied are highly paraffinic, increase in gravity with depth, andmore » have a very low sulfur content and a CPI close to 1. The oils of the two fields of Bekapai and Handil do not differ significantly, except that the degree of maturation of oil seems lower in Handil than in Bekapai. The characteristics of the source-rock chloroform extract are basically the same as those of the oils but the CPI is greater, between C25 and C29, and there is a higher proportion of alkanes in the extracts. The isoprenoid spectra, however, are very similar in both families of products. As a result it is concluded that the accumulations are probably not from source rocks in the vicinity of the reservoirs but originate at greater depths. The hydrocarbons could have migrated vertically about 3,000 m, chiefly along the faults present at both Bekapai and Handil. This process also could provoke the segregation of oils of increasing gravity with depth.« less

Petroleum geology of Cook Inlet basin - an exploration model

USGS Publications Warehouse

Magoon, L.B.; Claypool, G.E.

1981-01-01

Oil exploration commenced onshore adjacent to lower Cook Inlet on the Iniskin Peninsula in 1900, shifted with considerable success to upper Cook Inlet from 1957 through 1965, then returned to lower Cook Inlet in 1977 with the COST well and Federal OCS sale. Lower Cook Inlet COST No. 1 well, drilled to a total depth of 3,775.6 m, penetrated basinwide unconformities at the tops of Upper Cretaceous, Lower Cretaceous, and Upper Jurassic strata at 797.1, 1,540.8, and 2,112.3 m, respectively. Sandstone of potential reservoir quality is present in the Cretaceous and lower Tertiary rocks. All siltstones and shales analyzed are low (0 to 0.5 wt. %) in oil-prone organic matter, and only coals are high in humic organic matter. At total depth, vitrinite readings reached a maximum ave age reflectance of 0.65. Several indications of hydrocarbons were present. Oil analyses suggest that oils from the major fields of the Cook Inlet region, most of which produce from the Tertiary Hemlock Conglomerate, have a common source. More detailed work on stable carbon isotope ratios and the distribution of gasoline-range and heavy (C12+) hydrocarbons confirms this genetic relation among the major fields. In addition, oils from Jurassic rocks under the Iniskin Peninsula and from the Hemlock Conglomerate at the southwestern tip of the Kenai lowland are members of the same or a very similar oil family. The Middle Jurassic strata of the Iniskin Peninsula are moderately rich in organic carbon (0.5 to 1.5 wt. %) and yield shows of oil and of gas in wells and in surface seeps. Extractable hydrocarbons from this strata are similar in chemi al and isotopic composition to the Cook Inlet oils. Organic matter in Cretaceous and Tertiary rocks is thermally immature in all wells analyzed. Oil reservoirs in the major producing fields are of Tertiary age and unconformably overlie Jurassic rocks; the pre-Tertiary unconformity may be significant in exploration for new oil reserves. The unconformable relation between reservoir rocks and likely Middle Jurassic source rocks also implies a delay in the generation and expulsion of oil from Jurassic until late Tertiary when localized basin subsidence and thick sedimentary fill brought older, deeper rocks to the temperature required for petroleum generation. Reservoir porosities, crude oil properties, the type of oil field traps, and the tectonic framework of the oil fields on the west flank of the basin provide evidence used to reconstruct an oil migration route. The route is inferred to commence deep in the truncated Middle Jur ssic rocks and pass through the porous West Foreland Formation in the McArthur River field area to a stratigraphic trap in the Oligocene Hemlock Conglomerate and the Oligocene part of the Tyonek Formation at the end of Miocene time. Pliocene deformation shut off this route and created localized structural traps, into which the oil moved by secondary migration to form the Middle Ground Shoal, McArthur River, and Trading Bay oil fields. Oil generation continued into the Pliocene, but this higher API gravity oil migrated along a different route to the Granite Point field.

Possibilities and challenges for biosurfactants use in petroleum industry.

PubMed

Perfumo, Amedea; Rancich, Ivo; Banat, Ibrahim M

2010-01-01

Biosurfactants are a group of microbial molecules identified by their unique capabilities to interact with hydrocarbons. Emulsification and de-emulsification, dispersion, foaming, wetting and coating are some of the numerous surface activities that biosurfactants can achieve when applied within systems such as immiscible liquid/liquid (e.g., oil/water), solid/ liquid (e.g., rock/oil and rock/water) and gas/liquid. Therefore, the possibilities of exploiting these bioproducts in oil-related sciences are vast and made petroleum industry their largest possible market at present. The role of biosurfactants in enhancing oil recovery from reservoirs is certainly the best known; however they can be effectively applied in many other fields from transportation of crude oil in pipeline to the clean-up of oil storage tanks and even manufacturing of fine petrochemicals. When properly used, biosurfactants are comparable to traditional chemical analogues in terms of performances and offer advantages with regard to environment protection/conservation. This chapter aims at providing an up-to-date overview of biosurfactant roles, applications and possible future uses related to petroleum industry.

Organic metamorphism in the California petroleum basins; Chapter A, Rock-Eval and vitrinite reflectance

USGS Publications Warehouse

Price, Leigh C.; Pawlewicz, Mark J.; Daws, Ted A.

1999-01-01

The results of ROCK-EVAL and vitrinite reflectance analyses of a large sample base from more than 70 wells located in three oil-rich California petroleum basins are reported. The cores from these wells have a wide range of present-day burial temperatures (40 ? to 220 ? C). The rocks in these basins were deposited under highly variable conditions, sometimes resulting in substantially different organic matter (OM) types in rocks tens of meters vertically apart from each other in one well. The kinetic response of these different OM types to equivalent wellknown burial histories is a pivotal point of this study. In the Los Angeles and Ventura Basins, rock organic-richness significantly increased with depth, as did kerogen hydrogen content, and the percentage of fine-grained versus coarsegrained rocks. The shales in these basins are perceived as containing primarily hydrogen-rich amorphous OM. In actuality, the shallowest 2,000 to 3,000 m of rocks in the basins, and at least the upper 6,000 m of rocks in parts of the Los Angeles Basin central syncline, are dominated by type III/IV OM. In the Los Angeles Basin, mainstage hydrocarbon (HC) generation commences in the type III/IV OM at present-day burial temperatures of 85 ? to 110 ? C, most likely around 100 ? C, and is largely complete by 220 ? C. In the Southern San Joaquin Valley Basin, mainstage HC generation commences in type III/IV OM at 150 ? C and is also largely complete by 220 ? C. In the Ventura Basin, mainstage HC generation commences above 140 ? C in type III/IV OM. The apparent lower temperatures for commencement of HC generation in the Los Angeles Basin are attributed to the fact that parts of the basin were cooled from maximal burial temperatures by increased meteoric water flows during the last glaciations. All aspects of organic metamorphism, including mainstage HC generation, are strongly suppressed in rocks with hydrogenrich OM in these basins. For example, ROCK-EVAL data suggest that mainstage HC generation has not commenced in rocks with hydrogen-rich OM at present-day temperatures of 198?C. This observation is attributed to much stronger bonds in hydrogen- rich OM compared to types III and IV OM and, therefore, significantly higher burial temperatures are required to break these bonds. This difference in OM kinetics has profound ramifications for petroleum-geochemical exploration models. Organic-matter characteristics inherited from original depositional conditions were overlaid on, and at times confused interpretation of, characteristics from organic metamorphism in all study areas. In all the basins examined in this study, immature fine-grained rocks occasionally had high to very high carbon-normalized concentrations of pre-generation indigenous bitumen. This unusual characteristic may be due to unique depositional conditions in these basins.

Application of Landsat imagery to problems of petroleum exploration in Qaidam Basin, China

USGS Publications Warehouse

Bailey, G.B.; Anderson, P.D.

1982-01-01

Tertiary and Quaternary nonmarine, petroleum-bearing sedimentary rocks have been extensively deformed by compressive forces. These forces created many folds which are current targets of Chinese exploration programs. Image-derived interpretations of folds, strike-slip faults, thrust faults, normal or reverse faults, and fractures compared very favorably, in terms of locations and numbers mapped, with Chinese data compiled from years of extensive field mapping. Many potential hydrocarbon trapping structures were precisely located. Orientations of major structural trends defined from Landsat imagery correlate well with those predicted for the area based on global tectonic theory. These correlations suggest that similar orientations exist in the eastern half of the basin where folded rocks are mostly obscured by unconsolidated surface sediments and where limited exploration has occurred.--Modified journal abstract.

Solubility of crude oil in methane as a function of pressure and temperature

USGS Publications Warehouse

Price, L.C.; Wenger, L.M.; Ging, T.; Blount, C.W.

1983-01-01

The solubility of a 44?? API (0.806 sp. gr.) whole crude oil has been measured in methane with water present at temperatures of 50 to 250??C and pressures of 740 to 14,852 psi, as have the solubilities of two high molecular weight petroleum distillation fractions at temperatures of 50 to 250??C and pressures of 4482 to 25,266 psi. Both increases in pressure and temperature increase the solubility of crude oil and petroleum distillation fractions in methane, the effect of pressure being greater than that of temperature. Unexpectedly high solubility levels (0.5-1.5 grams of oil per liter of methane-at laboratory temperature and pressure) were measured at moderate conditions (50-200??C and 5076-14504 psi). Similar results were found for the petroleum distillation fractions, one of which was the highest molecular weight material of petroleum (material boiling above 266??C at 6 microns pressure). Unexpectedly mild conditions (100??C and 15,200 psi; 200??C and 7513 psi) resulted in cosolubility of crude oil and methane. Under these conditions, samples of the gas-rich phase gave solubility values of 4 to 5 g/l, or greater. Qualitative analyses of the crude-oil solute samples showed that at low pressure and temperature equilibration conditions, the solute condensate would be enriched in C5-C15 range hydrocarbons and in saturated hydrocarbons in the C15+ fraction. With increases in temperature and especially pressure, these tendencies were reversed, and the solute condensate became identical to the starting crude oil. The data of this study, compared to that of previous studies, shows that methane, with water present, has a much greater carrying capacity for crude oil than in dry systems. The presence of water also drastically lowers the temperature and pressure conditions required for cosolubility. The data of this and/or previous studies demonstrate that the addition of carbon dioxide, ethane, propane, or butane to methane also has a strong positive effect on crude oil solubility, as does the presence of fine grained rocks. The n-paraffin distributions (as well as the overall composition) of the solute condensates are controlled by the temperature and pressure of solution and exsolution, as well as by the composition of the original starting material. It appears quite possible that primary migration by gaseous solution could 'strip' a source rock of crude-oil like components leaving behind a bitumen totally unlike the migrated crude oil. The data of this study demonstrate previous criticisms of primary petroleum migration by gas solution are invalid; that primary migration by gaseous solution cannot occur because methane cannot dissolve sufficient volumes of crude oil or cannot dissolve the highest molecular weight components of petroleum (tars and asphaltenes). ?? 1983.

Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province

USGS Publications Warehouse

Gautier, Donald L.

2005-01-01

The North Sea Graben of northwestern Europe, World Energy Project Province 4025, is entirely offshore within the territorial waters of Denmark, Germany, the Netherlands, Norway, and the United Kingdom. Extensional tectonics and failed rifting are fundamental to the distribution of oil and gas in the province. Accordingly, the geologic history and reser-voir rocks of the province are considered in the context of their temporal relationship to the principal extension and rifting events. The oil and gas accumulations of the province are considered part of a single petroleum system: the Kimmeridg-ian Shales Total Petroleum System (TPS). Source rocks of the Kimmeridgian Shales TPS were deposited in Late Jurassic to earliest Cretaceous time during the period of intensive exten-sion and rifting. The Kimmeridgian Shales contain typical 'type II' mixed kerogen. Oil and gas generation began locally in the North Sea Graben Province by Cretaceous time and has continued in various places ever since. Reservoirs are found in strata with ages ranging from Devonian to Eocene. Pre-rift reservoirs are found in fault-block structures activated during rifting and can be of any age prior to the Late Jurassic. Syn-rift reservoirs are restricted to strata actually deposited during maximum extension and include rocks of Late Jurassic to earliest Cretaceous age. Post-rift reservoirs formed after rifting and range in age from Early Cretaceous to Eocene. Seals are diverse, depending upon the structural setting and reservoir age. Pre-rift reservoirs com-monly have seals formed by fine-grained, post-rift sedimentary sequences that drape the Late Jurassic to earliest Cretaceous structures. Contemporaneous shales such as the Kimmeridge Clay seal many syn-rift reservoirs. Fields with post-rift res-ervoirs generally require seals in fine-grained Tertiary rocks. In most of the North Sea Graben, source rocks have been continuously buried since deposition. Structural trap forma-tion has also taken place continuously since Mesozoic time. As a result, oil and gas are present in a wide variety of settings within Province 4025. Assessment units for the World Energy Project were defined geographically in order to capture regional differ-ences in exploration history, geography, and geological evolution. Three geographic areas were assessed. The Viking Graben, in the northern part of the province, includes both United Kingdom and Norwegian territorial areas. The Moray Firth/Witch Ground in the west-central part of the province is entirely in United Kingdom. waters. The Central Graben in the southern part of the province includes territorial areas of Denmark, Germany, the Netherlands, Norway, and the United Kingdom. The North Sea Graben is estimated to contain between 4.3 and 25.6 billion barrels (BBO) of undiscovered, conventionally recoverable oil. Of that total, the Viking Graben is believed to contain 2.2 to 14.8 BBO of undiscov-ered oil, the Moray Firth/Witch Ground may contain between 0.3 and 1.9 BBO, and the Central Graben was estimated to contain undiscovered oil resources of 1.7 to 8.8 BBO. Prov-ince 4025 was also estimated to hold between 11.8 and 75 trillion cubic feet (TCF) of undiscovered natural gas. Of this total, 6.8 to 44.5 TCF is thought to exist in the Viking Graben, 0.6 to 3.4 TCF is estimated to be in the Moray Firth/Witch Ground, and 4.5 to 27.1 TCF of undiscovered gas is estimated to be in the Central Graben.

Offshore S. Cuba -- Quaternary lobsters and Eocene reefs

DOE Office of Scientific and Technical Information (OSTI.GOV)

Rebora, M.

When Cuba is mentioned, the first image that comes to an explorationist's mind is one of complex imbricated thrust sheets, fractured carbonate reservoirs, volcanics and ophiolitic, and heavy and high sulfur oil. It is now known that this stimulating'' scenario does not apply to the whole of Cuba but only to the northern and central part where plate collisions and robust wrench tectonics exacted their toll on sediments and hydrocarbons alike. Seismic data recently acquired by Taurus Petroleum off the southern coast of Cuba reveal a rather different scenario: Mesozoic sediments several thousands of meters thick, deformed by moderate wrenchmore » tectonics into low-relief flower structures, and overlain by a variety of Paleogene shelf edge reefs, atolls, and banks that look as if reproduced from the pages of AAPG's Memoir 57. The whole is topped by Oligocene and Miocene evaporites, shales, and carbonates. The paper describes the southern shelf area, exploration in Cuba, reefs, oil and gas shows, source rocks, reservoir rocks, seals, and potential reserves.« less

Preliminary stratigraphy and facies analysis of the Upper Cretaceous Kaguyak Formation, including a brief summary of newly discovered oil stain, upper Alaska Peninsula

USGS Publications Warehouse

Wartes, Marwan A.; Decker, Paul L.; Stanley, Richard G.; Herriott, Trystan M.; Helmold, Kenneth P.; Gillis, Robert J.

2013-01-01

The Alaska Division of Geological and Geophysical Surveys has an ongoing program aimed at evaluating the Mesozoic forearc stratigraphy, structure, and petroleum systems of lower Cook Inlet. Most of our field studies have focused on the Jurassic component of the petroleum system (this report). However, in late July and early August of 2012, we initiated a study of the stratigraphy and reservoir potential of the Upper Cretaceous Kaguyak Formation. The Kaguyak Formation is locally well exposed on the upper Alaska Peninsula (fig. 25) and was named by Keller and Reiser (1959) for a sequence of interbedded siltstone and sandstone of upper Campanian to Maastrichtian age that they estimated to be 1,450 m thick.Subsequent work by Detterman and Miller (1985) examined 900 m of section and interpreted the unit as the record of a prograding submarine fan.This interpretation of deep-water deposition contrasts with other Upper Cretaceous rocks exposed along the Alaska Peninsula and lower Cook Inlet that are generally described as nonmarine to shallow marine (Detterman and others, 1996; LePain and others, 2012).Based on foraminifera and palynomorphs from the COST No. 1 well, Magoon (1986) concluded that the Upper Cretaceous rocks were deposited in a variety of water depths and environments ranging from upper bathyal to nonmarine. During our recent fieldwork west and south of Fourpeaked Mountain, we similarly encountered markedly varying lithofacies in the Kaguyak Formation (fig. 25), and we also found oil-stained rocks that are consistent with the existence of an active petroleum system in Upper Cretaceous rocks on the upper Alaska Peninsula and in lower Cook Inlet. These field observations are summarized below.

Geologic Assessment of Undiscovered Oil and Gas Resources of the West Greenland-East Canada Province

USGS Publications Warehouse

Schenk, Christopher J.

2010-01-01

The U.S. Geological Survey (USGS) recently assessed the potential for undiscovered oil and gas resources of the West Greenland-East Canada Province as part of the USGS Circum-Arctic Resource Appraisal program. The province lies in the offshore area between western Greenland and eastern Canada and includes Baffin Bay, Davis Strait, Lancaster Sound, and Nares Strait west of and including part of Kane Basin. A series of major tectonic events led to the formation of several distinct structural domains that are the geologic basis for defining five assessment units (AU) in the province, all of which are within the Mesozoic-Cenozoic Composite Total Petroleum System (TPS). Potential petroleum source rocks within the TPS include strata of Ordovician, Early and Late Cretaceous, and Paleogene ages. The five AUs defined for this study-the Eurekan Structures AU, Northwest Greenland Rifted Margin AU, Northeast Canada Rifted Margin AU, Baffin Bay Basin AU, and the Greater Ungava Fault Zone AU-encompass the entire province and were assessed for undiscovered, technically recoverable resources.

How Conoco uses GIS technology to map geology, geography through time

DOE Office of Scientific and Technical Information (OSTI.GOV)

Foley, D.C.; Ghazi, T.Y.

1995-05-08

Conoco Inc.`s Advanced Exploration Organization (AEO) is in the business of studying foreign sedimentary basins from a regional perspective to evaluate their potential for petroleum exploration. Recently the company decided to focus some of the AEO`s resources on developing a global ranking system for those areas of the world where hydrocarbons might occur. AEO obtained software from the University of Texas, Arlington that rotates continents or portions of continents through time. Using the software, company geoscientists have created a series of maps, known as a PaleoAtlas, that depicts the geography and selected geological features for different periods in Phanerozoic time.more » In addition, the AEO has developed a software package based on ARC/INFO (ESRI Inc., Redlands, Calif.), a commercial GIS platform, to manage, integrate, and analyze those time-slice maps. Entitled PaleoAtlas Geographic Evaluation system (Pages), this software also sequences portions of the maps in a montage effect that geoscientists can use to study the geological evolution of petroleum source rocks. The paper describes the AEO project and its software.« less

Petrographic and Vitrinite Reflectance Analyses of a Suite of High Volatile Bituminous Coal Samples from the United States and Venezuela

USGS Publications Warehouse

Hackley, Paul C.; Kolak, Jonathan J.

2008-01-01

This report presents vitrinite reflectance and detailed organic composition data for nine high volatile bituminous coal samples. These samples were selected to provide a single, internally consistent set of reflectance and composition analyses to facilitate the study of linkages among coal composition, bitumen generation during thermal maturation, and geochemical characteristics of generated hydrocarbons. Understanding these linkages is important for addressing several issues, including: the role of coal as a source rock within a petroleum system, the potential for conversion of coal resources to liquid hydrocarbon fuels, and the interactions between coal and carbon dioxide during enhanced coalbed methane recovery and(or) carbon dioxide sequestration in coal beds.

Powder X-ray diffraction laboratory, Reston, Virginia

USGS Publications Warehouse

Piatak, Nadine M.; Dulong, Frank T.; Jackson, John C.; Folger, Helen W.

2014-01-01

The powder x-ray diffraction (XRD) laboratory is managed jointly by the Eastern Mineral and Environmental Resources and Eastern Energy Resources Science Centers. Laboratory scientists collaborate on a wide variety of research problems involving other U.S. Geological Survey (USGS) science centers and government agencies, universities, and industry. Capabilities include identification and quantification of crystalline and amorphous phases, and crystallographic and atomic structure analysis for a wide variety of sample media. Customized laboratory procedures and analyses commonly are used to characterize non-routine samples including, but not limited to, organic and inorganic components in petroleum source rocks, ore and mine waste, clay minerals, and glassy phases. Procedures can be adapted to meet a variety of research objectives.

Interfacial sciences in unconventional petroleum production: from fundamentals to applications.

PubMed

He, Lin; Lin, Feng; Li, Xingang; Sui, Hong; Xu, Zhenghe

2015-08-07

With the ever increasing demand for energy to meet the needs of growth in population and improvement in the living standards in particular in developing countries, the abundant unconventional oil reserves (about 70% of total world oil), such as heavy oil, oil/tar sands and shale oil, are playing an increasingly important role in securing global energy supply. Compared with the conventional reserves unconventional oil reserves are characterized by extremely high viscosity and density, combined with complex chemistry. As a result, petroleum production from unconventional oil reserves is much more difficult and costly with more serious environmental impacts. As a key underpinning science, understanding the interfacial phenomena involved in unconventional petroleum production, such as oil liberation from host rocks, oil-water emulsions and demulsification, is critical for developing novel processes to improve oil production while reducing GHG emission and other environmental impacts at a lower operating cost. In the past decade, significant efforts and advances have been made in applying the principles of interfacial sciences to better understand complex unconventional oil-systems, while many environmental and production challenges remain. In this critical review, the recent research findings and progress in the interfacial sciences related to unconventional petroleum production are critically reviewed. In particular, the chemistry of unconventional oils, liberation mechanisms of oil from host rocks and mechanisms of emulsion stability and destabilization in unconventional oil production systems are discussed in detail. This review also seeks to summarize the current state-of-the-art characterization techniques and brings forward the challenges and opportunities for future research in this important field of physical chemistry and petroleum.

Thermal maturity patterns (conodont color alteration index and vitrinite reflectance) in Upper Ordovician and Devonian rocks of the Appalachian basin: a major revision of USGS Map I-917-E using new subsurface collections: Chapter F.1 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Repetski, John E.; Ryder, Robert T.; Weary, David J.; Harris, Anita G.; Trippi, Michael H.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

The conodont color alteration index (CAI) introduced by Epstein and others (1977) and Harris and others (1978) is an important criterion for estimating the thermal maturity of Ordovician to Mississippian rocks in the Appalachian basin. Consequently, the CAI isograd maps of Harris and others (1978) are commonly used by geologists to characterize the thermal and burial history of the Appalachian basin and to better understand the origin and distribution of oil and gas resources in the basin. The main objectives of this report are to present revised CAI isograd maps for Ordovician and Devonian rocks in the Appalachian basin and to interpret the geologic and petroleum resource implications of these maps. The CAI isograd maps presented herein complement, and in some areas replace, the CAI-based isograd maps of Harris and others (1978) for the Appalachian basin. The CAI data presented in this report were derived almost entirely from subsurface samples, whereas the CAI data used by Harris and others (1978) were derived almost entirely from outcrop samples. Because of the different sampling methods, there is little geographic overlap of the two data sets. The new data set is mostly from the Allegheny Plateau structural province and most of the data set of Harris and others (1978) is from the Valley and Ridge structural province, east of the Allegheny structural front (fig. 1). Vitrinite reflectance, based on dispersed vitrinite in Devonian black shale, is another important parameter for estimating the thermal maturity in pre-Pennsylvanian-age rocks of the Appalachian basin (Streib, 1981; Cole and others, 1987; Gerlach and Cercone, 1993; Rimmer and others, 1993; Curtis and Faure, 1997). This chapter also presents a revised percent vitrinite reflectance (%R0) isograd map based on dispersed vitrinite recovered from selected Devonian black shales. The Devonian black shales used for the vitrinite studies reported herein also were analyzed by RockEval pyrolysis and total organic carbon (TOC) content in weight percent. Although the RockEval and TOC data are included in this chapter (table 1), they are not shown on the maps. The revised CAI isograd and percent vitrinite reflectance isograd maps cover all or parts of Kentucky, New York, Ohio, Pennsylvania, Virginia, and West Virginia (fig. 1), and the following three stratigraphic intervals: Upper Ordovician carbonate rocks, Lower and Middle Devonian carbonate rocks, and Middle and Upper Devonian black shales. These stratigraphic intervals were chosen for the following reasons: (1) they represent target reservoirs for much of the oil and gas exploration in the Appalachian basin; (2) they are stratigraphically near probable source rocks for most of the oil and gas; (3) they include geologic formations that are nearly continuous across the basin; (4) they contain abundant carbonate grainstone-packstone intervals, which give a reasonable to good probability of recovery of conodont elements from small samples of drill cuttings; and (5) the Middle and Upper Devonian black shale contains large amounts of organic matter for RockEval, TOC, and dispersed vitrinite analyses. Thermal maturity patterns of the Upper Ordovician Trenton Limestone are of particular interest here, because they closely approximate the thermal maturity patterns in the overlying Upper Ordovician Utica Shale, which is the probable source rock for oil and gas in the Upper Cambrian Rose Run Sandstone (sandstone), Upper Cambrian and Lower Ordovician Knox Group (Dolomite), Lower and Middle Ordovician Beekmantown Group (dolomite or Dolomite), Upper Ordovician Trenton and Black River Limestones, and Lower Silurian Clinton/Medina sandstone (Cole and others, 1987; Jenden and others, 1993; Laughrey and Baldassare, 1998; Ryder and others, 1998; Ryder and Zagorski, 2003). The thermal maturity patterns of the Lower Devonian Helderberg Limestone (Group), Middle Devonian Onondaga Limestone, and Middle Devonian Marcellus Shale-Upper Devonian Rhine street Shale Member-Upper Devonian Ohio Shale are of interest, because they closely approximate the thermal maturity patterns in the Marcellus Shale, Upper Devonian Rhinestreet Shale Member, and Upper Devonian Huron Member of the Ohio Shale, which are the most important source rocks for oil and gas in the Appalachian basin (de Witt and Milici, 1989; Klemme and Ulmishek, 1991). The Marcellus, Rhinestreet, and Huron units are black-shale source rocks for oil and (or) gas in the Lower Devonian Oriskany Sandstone, the Upper Devonian sandstones, the Middle and Upper Devonian black shales, and the Upper Devonian-Lower Mississippian(?) Berea Sandstone (Patchen and others, 1992; Roen and Kepferle, 1993; Laughrey and Baldassare, 1998).

Thermal maturation and petroleum source rocks in Forest City and Salina basins, mid-continent, U. S. A

DOE Office of Scientific and Technical Information (OSTI.GOV)

Newell, K.D.; Watney, W.L.; Hatch, J.R.

1986-05-01

Shales in the Middle Ordovician Simpson Group are probably the source rocks for a geochemically distinct group of lower pristane and low phytane oils produced along the axis of the Forest City basin, a shallow cratonic Paleozoic basin. These oils, termed Ordovician-type oils, occur in some fields in the southern portion of the adjacent Salina basin. Maturation modeling by time-temperature index (TTI) calculations indicate that maturation of both basins was minimal during the early Paleozoic. The rate of maturation significantly increased during the Pennsylvanian because of rapid regional subsidence in response to the downwarping of the nearby Anadarko basin. Whenmore » estimated thicknesses of eroded Pennsylvanian, Permian, and Cretaceous strata are considered, both basins remain relatively shallow, with maximum basement burial probably not exceeding 2 km. According to maturation modeling and regional structure mapping, the axes of both basins should contain Simpson rocks in the early stages of oil generation. The probability of finding commercial accumulations of Ordovician-type oil along the northwest-southeast trending axis of the Salina basin will decrease in a northwestward direction because of (1) westward thinning of the Simpson Group, and (2) lesser maturation due to lower geothermal gradients and shallower paleoburial depths. The optimum localities for finding fields of Ordovician-type oil in the southern Salina basin will be in down-plunge closures on anticlines that have drainage areas near the basin axis.« less

Austin Chalk (!) Petroleum System: Upper Cretaceous, Southeastern Texas

DOE Office of Scientific and Technical Information (OSTI.GOV)

Dawson, W.C.; Katz, B.J.; Robison, V.D.

1995-10-01

The Austin Group (Coniacian-Santonian) is a sequence of interstratified chalk and marl deposited during a sea-level highstand as a transgressive unit. Austin Chalk deposition occurred on a southeastward-dipping carbonate ramp that exhibits distinctive onshore and offshore chalk lithofacies. Discrete intervals within offshore Austin lithofacies display good to excellent source rock potential. Organic carbon content ranges upward to 20.0 wt. % with generation potentials exceeding 45 mg HC/g of rock measured. Source potential increases basinward where offshore chalk units exhibit increases in both organic richness and net thickness. These organically rich units display an affinity for the Type II reference curve.more » Hydrogen index values typically exceed 300 mg HC/g TOC. Several geochemical indices suggest that the oil-window is located at relatively shallow depths (6,700 ft). Offshore chalks sourced onshore Austin reservoirs through lateral migration (along fractures and stylolites) which occurred during the middle Tertiary. Hydrocarbons may also have been sourced from the underlying Eagle Ford Shale (Turonian). Austin Shale reservoirs are characterized by low porosity/low permeability dual pore systems consisting of microporous matrix and fractures. Diagenesis (mechanical compaction, styloitization, and calcite cementation) has strongly modified Austin Chalk pore systems. Matrix porosity generally decreases with increasing depth because of progressive burial diagenesis. Austin reservoirs typically have two major sets of fractures; reservoir performance is related to fracture connectivity. Austin Chalk reservoirs are sealed by the overlying Taylor Marl (Campanian).« less

Fluid flow and coupled poroelastic response in low-permeability rocks

NASA Astrophysics Data System (ADS)

Hasanov, A.; Prasad, M.

2015-12-01

Hydraulic transport properties of reservoir rocks are traditionally defined as rock properties, responsiblefor the passage of fluids through the porous rock sample, as well as their storage. These properties arealso called permeability and storage capacity. The evaluation of both is an important part of any reservoircharacterization workflow. A vivid example of the importance of the transport properties is the bloomingbusiness of unconventional oil and gas production. Tight formations with ultra-low permeabilities and storagecapacities, which have never been perceived as reservoir rocks, today are actively exploited for oil and gas.This tremendous achievement in petroleum science and technology was only possible due to hydraulic frac-turing, which is essentially a process of enhancing permeability and storage capacity by creating a swarmof microcracks in the rock. The knowledge of hydraulic and poroelastic properties is also essential for proper simulations of diffusive pore fluidflow in petroleum reservoirs, as well as aquifers. This work is devoted to an integrated study of low-permeability rocks' hydraulic and poroe-lastic properties as measured with the oscillating pore pressure experiment. The oscillating pore pressuremethod is traditionally used to measure hydraulic transport properties. We modified the method and builtan experimental setup, capable of measuring all aforementioned rock properties simultaneously. The mea-surements were carried out for four sub-millidarcy rock samples at a range of oscillationfrequencies and effective stresses. An apparent frequency dependence of permeability was observed. Measured frequency dispersion of drained poroelastic propertiesindicates an intrinsically inelastic nature of the porous mineral rock frame. Standard Linear Model demon-strated the best fit to the experimental dispersion data. We established that hydraulically-measured storage capacitiesare in good agreement with elastically-derived ones. We also introduce a novel method, which allowedus to estimate the permeability from the full range of acquired frequency data by utilizing a nonlinear least-squares regression. The results of numerical simulation of oscillatory fluid flow confirm both the analyticalsolution and the experimental data.

Geothermal regime and Jurassic source rock maturity of the Junggar basin, northwest China

NASA Astrophysics Data System (ADS)

Nansheng, Qiu; Zhihuan, Zhang; Ershe, Xu

2008-01-01

We analyze the thermal gradient distribution of the Junggar basin based on oil-test and well-logging temperature data. The basin-wide average thermal gradient in the depth interval of 0-4000 m is 22.6 °C/km, which is lower than other sedimentary basins in China. We report 21 measured terrestrial heat flow values based on detailed thermal conductivity data and systematical steady-state temperature data. These values vary from 27.0 to 54.1 mW/m 2 with a mean of 41.8 ± 7.8 mW/m 2. The Junggar basin appears to be a cool basin in terms of its thermal regime. The heat flow distribution within the basin shows the following characteristics. (1) The heat flow decreases from the Luliang Uplift to the Southern Depression; (2) relatively high heat flow values over 50 mW/m 2 are confined to the northern part of the Eastern Uplift and the adjacent parts of the Eastern Luliang Uplift and Central Depression; (3) The lowest heat flow of smaller than 35 mW/m 2 occurs in the southern parts of the basin. This low thermal regime of the Junggar basin is consistent with the geodynamic setting, the extrusion of plates around the basin, the considerably thick crust, the dense lithospheric mantle, the relatively stable continental basement of the basin, low heat generation and underground water flow of the basin. The heat flow of this basin is of great significance to oil exploration and hydrocarbon resource assessment, because it bears directly on issues of petroleum source-rock maturation. Almost all oil fields are limited to the areas of higher heat flows. The relatively low heat flow values in the Junggar basin will deepen the maturity threshold, making the deep-seated widespread Permian and Jurassic source rocks in the Junggar basin favorable for oil and gas generation. In addition, the maturity evolution of the Lower Jurassic Badaowan Group (J 1b) and Middle Jurassic Xishanyao Group (J 2x) were calculated based on the thermal data and burial depth. The maturity of the Jurassic source rocks of the Central Depression and Southern Depression increases with depth. The source rocks only reached an early maturity with a R0 of 0.5-0.7% in the Wulungu Depression, the Luliang Uplift and the Western Uplift, whereas they did not enter the maturity window ( R0 < 0.5%) in the Eastern Uplift of the basin. This maturity evolution will provide information of source kitchen for the Jurassic exploration.

Regional framework, structural and petroleum aspects of rift basins in Niger, Chad and the Central African Republic (C.A.R.)

NASA Astrophysics Data System (ADS)

Genik, G. J.

1992-10-01

This paper overviews the regional framework, tectonic, structural and petroleum aspects of rifts in Niger, Chad and the C.A.R. The data base is from mainly proprietary exploration work consisting of some 50,000 kilometres of seismic profiles, 50 exploration wells, one million square kilometres of aeromagnetics coverage and extensive gravity surveys. There have been 13 oil and two oil and gas discoveries. A five phased tectonic history dating from the Pan African orogeny (750-550 MY B.P.) to the present suggests that the Western Central African Rift System (WCAS) with its component West African Rift Subsystem (WAS) and Central African Subsystem (CAS) formed mainly by the mechanical separation of African crustal blocks during the Early Cretaceous. Among the resulting rift basins in Niger, Chad and the C.A.R., seven are in the WAS—Grein, Kafra, Tenere. Tefidet, Termit, Bongor, and N'Dgel Edgi and three, Doba, Doseo, and Salamat are in the CAS. The WAS basins in Niger and Chad are all extensional and contain more than 14,000 m of continental to marine Early Cretaceous to Recent clastic sediments and minor amounts of volcanics. Medium to light oil (20° API-46° API) and gas have been discovered in the Termit basin in reservoir, source and seal beds of Late Cretaceous and Palaeogene age. The most common structural styles are extensional normal fault blocks and transtensional synthetic and antithetic normal fault blocks. The CAS Doba, Doseo and Salamat are extensional to transtensional rift basins containing up to 7500 m of terrestrial mainly Early Cretaceous clastics. Heavy to light oil (15°-39° API) and gas have been discovered in Doba and Doseo basins. Source rocks are Early Cretaceous lacustrine shales, whereas reservoirs and seals are both Early and Late Cretaceous. Dominant structural styles are extensional and transtensional fault blocks, transpressional anticlines and flower structures. The existence of a total rift basin sediment volume of more than one million cubic kilometres with structured reservoir, source and seal rocks favours the generation, migration and entrapment of additional significant volumes of hydrocarbons in many of these basins.

Determination of osmium concentrations and (187)Os/(188)Os of crude oils and source rocks by coupling high-pressure, high-temperature digestion with sparging OsO(4) into a multicollector inductively coupled plasma mass spectrometer.

PubMed

Sen, Indra S; Peucker-Ehrenbrink, Bernhard

2014-03-18

The (187)Os/(188)Os ratio that is based on the β(-)-decay of (187)Re to (187)Os (t1/2 = 41.6 billion years) is widely used to investigate petroleum system processes. Despite its broad applicability to studies of hydrocarbon deposits worldwide, a suitable matrix-matched reference material for Os analysis does not exist. In this study, a method that enables Os isotope measurement of crude oil with in-line Os separation and purification from the sample matrix is proposed. The method to analyze Os concentration and (187)Os/(187)Os involves sample digestion under high pressure and high temperature using a high pressure asher (HPA-S, Anton Paar), sparging of volatile osmium tetroxide from the sample solution, and measurements using multicollector inductively coupled plasma mass spectrometry (MC-ICPMS). This methods significantly reduced the total procedural time compared to conventional Carius tube digestion followed by Os separation and purification using solvent extraction, microdistillation and N-TIMS analysis. The method yields Os concentration (28 ± 4 pg g(-1)) and (187)Os/(188)Os (1.62 ± 0.15) of commercially available crude oil reference material NIST 8505 (1 S.D., n = 6). The reference material NIST 8505 is homogeneous with respect to Os concentration at a test portion size of 0.2 g. Therefore, (187)Os/(188)Os composition and Os concentration of NIST 8505 can serve as a matrix-matched reference material for Os analysis. Data quality was assessed by repeated measurements of the USGS shale reference material SCo-1 (sample matrix similar to petroleum source rock) and the widely used Liquid Os Standard solution (LOsSt). The within-laboratory reproducibility of (187)Os/(188)Os for a 5 pg of LOsSt solution, analyzed with this method over a period of 12 months was ∼1.4% (1 S.D., n = 26), respectively.

Modeling oil generation with time-temperature index graphs based on the Arrhenius equation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Hunt, J.M.; Lewan, M.D.; Hennet, R.J.C.

1991-04-01

The time and depth of oil generation from petroleum source rocks containing type II kerogens can be determined using time-temperature index (TTI) graphs based on the Arrhenius equation. Activation energies (E) and frequency factors (A) used in the Arrhenius equation were obtained from hydrous pyrolysis experiments on rock samples in which the kerogens represent the range of type II kerogen compositions encountered in most petroleum basins. The E and A values obtained were used to construct graphs that define the beginning and end of oil generation for most type II kerogens having chemical compositions in the range of these standards.more » Activation energies of these standard kerogens vary inversely with their sulfur content. The kerogen with the highest sulfur content had the lowest E value and was the fastest in generating oil, whereas the kerogen with the lowest sulfur content had the highest E value and was the slowest in generating oil. These standard kerogens were designated as types IIA, B, C, and D on the basis of decreasing sulfur content and corresponding increasing time-temperature requirements for generating oil. The {Sigma}TTI{sub ARR} values determined graphically with these type II kerogen standards in two basin models were compared with a computer calculation using 2,000 increments. The graphical method came within {plus minus} 3% of the computer calculation. As type II kerogens are the major oil generators in the world, these graphs should have wide application in making preliminary evaluations of the depth of the oil window in exploration areas.« less

New constraints on Neogene uplift of the northern Colorado Plateau

NASA Astrophysics Data System (ADS)

Van Wijk, J. W.; Raschilla, R.

2013-12-01

The Late Cretaceous Uinta Basin is located in northeastern Utah within the northern most portion of the Colorado Plateau. The basin's uplift and subsidence history and thermal evolution have impacted the maturity of source beds in the Parachute Creek Member of the Green River Formation. Using measured data of the petroleum system of the Uinta Basin, we were able to constrain timing and amplitude of uplift of the northern Colorado Plateau. We used sixty wells in a basin modeling study of the Uinta Basin's thermal structure, tectonic history and petroleum system. The wells reached into basement, and four wells provided vitrinite reflectance measurements. Vitrinite reflectance is a measurement of the percentage of reflected light from a polished vitrinite sample. The percentage of reflected light is related to the temperature conditions the sample experienced during burial, and vitrinite reflectance is a maturity indicator that covers a broad temperature range from diagenesis through the latest stages of catagenesis and records the maximum temperature a rock experiences during its burial history All models were calibrated to measured data, including vitrinite reflectance and transformation ratios from Rock-Eval pyrolysis. The models predict that the heat flow ranges from 65 mW/m2 to 45 mW/m2 from south to north in the study area. Additionally, model calibration provides a means for estimating the amount of uplift and erosion in the Uinta Basin. Uplift predicted for the Uinta Basin ranges from ~2050 m to ~2200 m and started in the Late Miocene. Our models also predicted the maturity of the rich oil shales of the Parachute Creek Member.

Cenozoic basin thermal history reconstruction and petroleum systems in the eastern Colombian Andes

NASA Astrophysics Data System (ADS)

Parra, Mauricio; Mora, Andres; Ketcham, Richard A.; Stockli, Daniel F.; Almendral, Ariel

2017-04-01

Late Mesozoic-Cenozoic retro-arc foreland basins along the eastern margin of the Andes in South America host the world's best detrital record for the study of subduction orogenesis. There, the world's most prolific petroleum system occur in the northernmost of these foreland basin systems, in Ecuador, Colombia and Venezuela, yet over 90% of the discovered hydrocarbons there occur in one single province in norteastern Venezuela. A successful industry-academy collaboration applied a multidisciplinary approach to the study of the north Andes with the aim of investigating both, the driving mechanisms of orogenesis, and its impact on hydrocarbon accumulation in eastern Colombia. The Eastern Cordillera is an inversion orogen located at the leading edge of the northern Andes. Syn-rift subsidence favored the accumulation of km-thick organic matter rich shales in a back-arc basin in the early Cretaceous. Subsequent late Cretaceous thermal subsidence prompted the accumulation of shallow marine sandstones and shales, the latter including the Turonian-Cenomanian main hydrocarbon source-rock. Early Andean uplift since the Paleocene led to development of a flexural basin, filled with mainly non-marine strata. We have studied the Meso-Cenozoic thermal evolution of these basins through modeling of a large thermochronometric database including hundreds of apatite and zircon fission-track and (U-Th)/He data, as well as paleothermometric information based on vitrinite reflectance and present-day temperatures measured in boreholes. The detrital record of Andean construction was also investigated through detrital zircon U-Pb geochronometry in outcrop and borehole samples. A comprehensive burial/exhumation history has been accomplished through three main modeling strategies. First, one-dimensional subsidence was used to invert the pre-extensional lithospheric thicknesses, the magnitude of stretching, and the resulting heat flow associated to extension. The amount of eroded section and the maximum temperatures for various stratigraphic units at each locality were calibrated with thermochronometry. Subsequently, two-dimensional thermal models were constructed using thermokinematic modeling of sequentially restored structural cross-sections, for which abundant thermochronometric data was inverse modeled using FETKIN, a software developed within this collaborative project. Finally, the spatial and temporal distribution of source rock exhumation was documented with quantitative modeling of U-Pb data. The results reveal that early Cretaceous back-arc development occurred along a pre-stretched, 90 km thick lithosphere with stretching factors of up to 1.8. Such conditions led to an early Cretaceous high heat flux which, along with rapid syn-rift subsidence, resulted in an early maturation of the potential early Cretaceous source rocks, limiting their ability to expulse hydrocarbons later on, during the petroleum system's critical moment. Our results reveal the competing roles of tectonic inheritance and climate-tectonic feedbacks in the construction of the North Andes and, importantly, illustrate that the Oligocene main inversion of the Eastern Cordillera was a key element for assessing the size of active hydrocarbon kitchens and is a decisive element to consider for volumetric calculations of yet-to-find resources. Our work in the northern Andes demonstrated that thermal and structural kinematic modeling in thrust-belts is greatly improved by a careful usage of geochronological data, which involves robust modeling strategies.

The relationship of angiosperms and oleanane in petroleum through geologic time

DOE Office of Scientific and Technical Information (OSTI.GOV)

Moldowan, J.M.; Dahl, J.E.; Huizinga, B.J.

1993-02-01

The biological marker oleanane has been suggested as an indicator of angiosperm (flowering plant) input into source rocks and their derived oils. Parallels should therefore be evident between the angiosperm fossil record and oleanane occurrence and abundance. A global selection of more than 50 core samples from marine rocks of different ages and from different locations was quantitatively analyzed for oleanane to determine its abundance over geologic time relative to the bacterial marker hopane. Oleanane was recognized using Metastable Reaction Monitoring (MRM) GC-MS. A parallel was observed between the oleanane/hopane ratio and angiosperm diversity in the fossil record through time.more » The first fossil evidence of angiosperms is during the Early Cretaceous with radiation during the Late Cretaceous and Tertiary. Occurrences of oleanane are confirmed throughout the Cretaceous system. Early-to-middle Cretaceous (Berriasian-Cenomanian) occurrences are sporadic and oleanan/hopane ratios are less than 0.07. Late Cretaceous (Turonian-Maastrichtian) oleanane/hopane ratios range up to 0.15 with higher ratios in many Tertiary samples. It appears that oleanane/hopane ratios of oils can restrict the age of their unavailable or unknown source rocks. High ratios indicate Tertiary age and lower ratios can indicate Cretaceous or Tertiary age, depending on depositional environment. While these data do not rule out pre-Cretaceous oleanane, preliminary data show that oleanane/hopane ratios for Jurassic and older rock extracts are typically below our detection limits (<0.03). While oleanane precursors are abundant in angiosperms, they also occur, rarely, in other modern plant groups. We identified oleanane in low abundances in three Early Cretaceous fossil benettitialeans, an extinct plant group (Late Triassic to Late Cretaceous) thought to be related to angiosperms. These findings suggest that oleanane could be present in low abundance in some pre-Cretaceous rocks and oils.« less

BASIN ANALYSIS AND PETROLEUM SYSTEM CHARACTERIZATION AND MODELING, INTERIOR SALT BASINS, CENTRAL AND EASTERN GULF OF MEXICO

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ernest A. Mancini; Donald A. Goddard; Ronald K. Zimmerman

2005-05-10

The principal research effort for Year 2 of the project has been data compilation and the determination of the burial and thermal maturation histories of the North Louisiana Salt Basin and basin modeling and petroleum system identification. In the first nine (9) months of Year 2, the research focus was on the determination of the burial and thermal maturation histories, and during the remainder of the year the emphasis has basin modeling and petroleum system identification. Existing information on the North Louisiana Salt Basin has been evaluated, an electronic database has been developed, regional cross sections have been prepared, structuremore » and isopach maps have been constructed, and burial history, thermal maturation history and hydrocarbon expulsion profiles have been prepared. Seismic data, cross sections, subsurface maps and related profiles have been used in evaluating the tectonic, depositional, burial and thermal maturation histories of the basin. Oil and gas reservoirs have been found to be associated with salt-supported anticlinal and domal features (salt pillows, turtle structures and piercement domes); with normal faulting associated with the northern basin margin and listric down-to-the-basin faults (state-line fault complex) and faulted salt features; and with combination structural and stratigraphic features (Sabine and Monroe Uplifts) and monoclinal features with lithologic variations. Petroleum reservoirs are mainly Upper Jurassic and Lower Cretaceous fluvial-deltaic sandstone facies and Lower Cretaceous and Upper Cretaceous shoreline, marine bar and shallow shelf sandstone facies. Cretaceous unconformities significantly contribute to the hydrocarbon trapping mechanism capacity in the North Louisiana Salt Basin. The chief petroleum source rock in this basin is Upper Jurassic Smackover lime mudstone beds. The generation of hydrocarbons from Smackover lime mudstone was initiated during the Early Cretaceous and continued into the Tertiary. Hydrocarbon expulsion commenced during the Early Cretaceous and continued into the Tertiary with peak expulsion occurring mainly during the Late Cretaceous.« less

Effects of Faults on Petroleum Fluid Dynamics, Borderland Basins of Southern California

NASA Astrophysics Data System (ADS)

Jung, B.; Garven, G.; Boles, J. R.

2012-12-01

Multiphase flow modeling provides a useful quantitative tool for understanding crustal processes such as petroleum migration in geological systems, and also for characterizing subsurface environmental issues such as carbon sequestration in sedimentary basins. However, accurate modeling of multi-fluid behavior is often difficult because of the various coupled and nonlinear physics affecting multiphase fluid saturation and migration, including effects of capillarity and relative permeability, anisotropy and heterogeneity of the medium, and the effects of pore pressure, composition, and temperature on fluid properties. Regional fault structures also play a strong role in controlling fluid pathlines and mobility, so considering hydrogeologic effects of these structures is critical for testing exploration concepts, and for predicting the fate of injected fluids. To address these issues on spatially large and long temporal scales, we have developed a 2-D multiphase fluid flow model, coupled to heat flow, using a hybrid finite element and finite volume method. We have had good success in applying the multiphase flow model to fundamental issues of long-distance petroleum migration and accumulation in the Los Angeles basin, which is intensely faulted and disturbed by transpressional tectonic stresses, and host to the world's richest oil accumulation. To constrain the model, known subsurface geology and fault structures were rendered using geophysical logs from industry exploration boreholes and published seismic profiles. Plausible multiphase model parameters were estimated, either from known fault permeability measurements in similar strata in the Santa Barbara basin, and from known formation properties obtained from numerous oil fields in the Los Angeles basin. Our simulations show that a combination of continuous hydrocarbon generation and primary migration from upper Miocene source rocks in the central LA basin synclinal region, coupled with a subsiding basin fluid dynamics, favored the massive accumulation and alignment of hydrocarbon pools along the Newport-Inglewood fault zone (NIFZ). According to our multiphase flow calculations, the maximum formation water velocities within fault zones likely ranged between 1 ~ 2 m/yr during the middle Miocene to Pliocene (13 to 2.6 Ma). The estimated time for long-distance (~ 25 km) petroleum migration from source beds in the central basin to oil fields along the NIFZ is approximately 150,000 ~ 250,000 years, depending on the effective permeability assigned to the faults and adjacent interbedded sandstone and siltstone "petroleum aquifers". With an average long-distance flow rate (~ 0.6 m/yr) and fault permeability of 100 millidarcys (10-13 m2), the total petroleum oil of Inglewood oil field of 450 million barrels (~ 1.6 × 105 m3) would have accumulated rather quickly, likely over 25,000 years or less. The results also suggest that besides the thermal and structural history of the basin, the fault permeability, capillary pressure, and the configuration of aquifer and aquitard layers played an important role in controlling petroleum migration rates, patterns of flow, and the overall fluid mechanics of petroleum accumulation.

The U.S. Chemical Industry, the Raw Materials It Uses

ERIC Educational Resources Information Center

Chemical and Engineering News, 1972

1972-01-01

The raw materials used by the industry are considered in this section of the annual chemical industry report, including data covering: natural gas, lead, mercury, phosphate rock, potash, salt, petroleum products including petrochemical feedstocks. (PR)

Geology report for proposed oil and gas lease sale No. 90; continental margin off the southeastern United States

USGS Publications Warehouse

Dillon, William P.

1983-01-01

This report summarizes our general knowledge of the geology and petroleum potential, as well as potential problems and hazards associated with development of petroleum resources, within the area proposed for nominations for lease sale number 90. This area includes the U.S. eastern continental margin from Raleigh Bay, just south of Cape Hatteras, to southern Florida, including the upper Continental Slope and inner Blake Plateau. The area for possible sales for lease sale number 90, as well as the area for lease sale number 78 and the previous areas leased are shown in figure 1; physiographic features of the region are shown in figure 2. Six exploration wells have been drilled within the proposed lease area (figs. 3 and 4), but no commercial discoveries have been made. All six wells were drilled on the Continental Shelf. No commercial production has been obtained onshore in the region. The areas already drilled have thin sedimentary rock sections, and the deeper strata are dominantly of continental facies. Petroleum formation may have been hindered by a lack of organic material and lack of sufficient burial for thermal maturation. However, analyses of drilling and seismic profiling data presented here indicate that a much thicker section of sedimentary rocks containing a much higher proportion of marine deposits, exists seaward of the Continental Shelf. These geologic conditions imply that the basins farther offshore may be more favorable environments for generating petroleum.

Assessment of undiscovered oil and gas resources of the Ordovician Utica Shale of the Appalachian Basin Province, 2012

USGS Publications Warehouse

Kirschbaum, Mark A.; Schenk, Christopher J.; Cook, Troy A.; Ryder, Robert T.; Charpentier, Ronald R.; Klett, Timothy R.; Gaswirth, Stephanie B.; Tennyson, Marilyn E.; Whidden, Katherine J.

2012-01-01

The U.S. Geological Survey assessed unconventional oil and gas resources of the Upper Ordovician Utica Shale and adjacent units in the Appalachian Basin Province. The assessment covers parts of Maryland, New York, Ohio, Pennsylvania, Virginia, and West Virginia. The geologic concept is that black shale of the Utica Shale and adjacent units generated hydrocarbons from Type II organic material in areas that are thermally mature for oil and gas. The source rocks generated petroleum that migrated into adjacent units, but also retained significant hydrocarbons within the matrix and adsorbed to organic matter of the shale. These are potentially technically recoverable resources that can be exploited by using horizontal drilling combined with hydraulic fracturing techniques.

Spreadsheet log analysis in subsurface geology

USGS Publications Warehouse

Doveton, J.H.

2000-01-01

Most of the direct knowledge of the geology of the subsurface is gained from the examination of core and drill-cuttings recovered from boreholes drilled by the petroleum and water industries. Wireline logs run in these same boreholes generally have been restricted to tasks of lithostratigraphic correlation and thee location of hydrocarbon pay zones. However, the range of petrophysical measurements has expanded markedly in recent years, so that log traces now can be transformed to estimates of rock composition. Increasingly, logs are available in a digital format that can be read easily by a desktop computer and processed by simple spreadsheet software methods. Taken together, these developments offer accessible tools for new insights into subsurface geology that complement the traditional, but limited, sources of core and cutting observations.

Programed oil generation of the Zubair Formation, Southern Iraq oil fields: Results from Petromod software modeling and geochemical analysis

USGS Publications Warehouse

Al-Ameri, T. K.; Pitman, Janet K.; Naser, M.E.; Zumberge, J.; Al-Haydari, H. A.

2011-01-01

1D petroleum system modeling was performed on wells in each of four oil fields in South Iraq, Zubair (well Zb-47), Nahr Umr (well NR-9), West Qurna (well WQ-15 and 23), and Majnoon (well Mj-8). In each of these fields, deposition of the Zubair Formation was followed by continuous burial, reaching maximum temperatures of 100°C (equivalent to 0.70%Ro) at depths of 3,344–3,750 m of well Zb-47 and 3,081.5–3,420 m of well WQ-15, 120°C (equivalent to 0.78%Ro) at depths of 3,353–3,645 m of well NR-9, and 3,391–3,691.5 m of well Mj-8. Generation of petroleum in the Zubair Formation began in the late Tertiary, 10 million years ago. At present day, modeled transformation ratios (TR) indicate that 65% TR of its generation potential has been reached in well Zb-47, 75% TR in well NR-9 and 55-85% TR in West Qurna oil field (wells WQ-15 and WQ-23) and up to 95% TR in well Mj-8, In contrast, younger source rocks are immature to early mature (<20% TR), whereas older source rocks are mature to overmature (100% TR). Comparison of these basin modeling results, in Basrah region, are performed with Kifle oil field in Hilla region of western Euphrates River whereas the Zubair Formation is immature within temperature range of 65–70°C (0.50%Ro equivalent) with up to 12% (TR = 12%) hydrocarbon generation efficiency and hence poor generation could be assessed in this last location. The Zubair Formation was deposited in a deltaic environment and consists of interbedded shales and porous and permeable sandstones. In Basrah region, the shales have total organic carbon of 0.5–7.0 wt%, Tmax 430–470°C and hydrogen indices of up to 466 with S2 = 0.4–9.4 of kerogen type II & III and petroleum potential of 0.4–9.98 of good hydrocarbon generation, which is consistent with 55–95% hydrocarbon efficiency. These generated hydrocarbons had charged (in part) the Cretaceous and Tertiary reservoirs, especially the Zubair Formation itself, in the traps formed by Alpine collision that closed the Tethys Ocean between Arabian and Euracian Plates and developed folds in Mesopotamian Basin 15–10 million years ago. These traps are mainly stratigraphic facies of sandstones with the shale that formed during the deposition of the Zubair Formation in transgression and regression phases within the main structural folds of the Zubair, Nahr Umr, West Qurna and Majnoon Oil fields. Oil biomarkers of the Zubair Formation Reservoirs are showing source affinity with mixed oil from the Upper Jurassic and Lower Cretaceous strata, including Zubair Formation organic matters, based on presentation of GC and GC-MS results on diagrams of global petroleum systems.

Shale gas characteristics of the Lower Toarcian Posidonia Shale in Germany: from basin to nanometre scale

NASA Astrophysics Data System (ADS)

Schulz, Hans-Martin; Bernard, Sylvain; Horsfield, Brian; Krüger, Martin; Littke, Ralf; di primio, Rolando

2013-04-01

The Early Toarcian Posidonia Shale is a proven hydrocarbon source rock which was deposited in a shallow epicontinental basin. In southern Germany, Tethyan warm-water influences from the south led to carbonate sedimentation, whereas cold-water influxes from the north controlled siliciclastic sedimentation in the northwestern parts of Germany and the Netherlands. Restricted sea-floor circulation and organic matter preservation are considered to be the consequence of an oceanic anoxic event. In contrast, non-marine conditions led to sedimentation of coarser grained sediments under progressively terrestrial conditions in northeastern Germany The present-day distribution of Posidonia Shale in northern Germany is restricted to the centres of rift basins that formed in the Late Jurassic (e.g., Lower Saxony Basin and Dogger Troughs like the West and East Holstein Troughs) as a result of erosion on the basin margins and bounding highs. The source rock characteristics are in part dependent on grain size as the Posidonia Shale in eastern Germany is referred to as a mixed to non-source rock facies. In the study area, the TOC content and the organic matter quality vary vertically and laterally, likely as a consequence of a rising sea level during the Toarcian. Here we present and compare data of whole Posidonia Shale sections, investigating these variations and highlighting the variability of Posidonia Shale depositional system. During all phases of burial, gas was generated in the Posidonia Shale. Low sedimentation rates led to diffusion of early diagenetically formed biogenic methane. Isochronously formed diagenetic carbonates tightened the matrix and increased brittleness. Thermogenic gas generation occurred in wide areas of Lower Saxony as well as in Schleswig Holstein. Biogenic methane gas can still be formed today in Posidonia Shale at shallow depth in areas which were covered by Pleistocene glaciers. Submicrometric interparticle pores predominate in immature samples. At thermal maturities beyond the oil window, intra-mineral and intra-organic pores develop. In such overmature samples, nanopores occur within pyrobitumen masses. Important for gas storage and transport, they likely result from exsolution of gaseous hydrocarbon. References Bernard S., Wirth R., Schreiber A., Bowen L., Aplin A.C., Mathia E.J., Schulz H-M., & Horsfield B.: FIB-SEM and TEM investigations of an organic-rich shale maturation series (Lower Toarcian Posidonia Shale): Nanoscale pore system and fluid-rock interactions. AAPG Bulletin Special Issue "Electron Microscopy of Shale Hydrocarbon Reservoirs" (in press). Bernard, S., Horsfield, B., Schulz, H-M., Wirth, R., Schreiber, A., & Sherwood, N., 2012, Geochemical evolution of organic-rich shales with increasing maturity: A STXM and TEM study of the Posidonia Shale (Lower Toarcian, northern Germany): Marine and Petroleum Geology 31 (1) 70-89. Lott, G.K., Wong, T.E., Dusar, M., Andsbjerg, J., Mönnig, E., Feldman-Olszewska, A. & Verreussel, R.M.C.H., 2010. Jurassic. In: Doornenbal, J.C. and Stevenson, A.G. (editors): Petroleum Geological Atlas of the Southern Permian Basin Area. EAGE Publications b.v. (Houten): 175-193.

Chapter 41: Geology and petroleum potential of the West Greenland-East Canada Province

USGS Publications Warehouse

Schenk, C.J.

2011-01-01

The US Geological Survey (USGS) assessed the potential for undiscovered oil and gas resources of the West Greenland-East Canada Province as part of the USGS Circum-Arctic Resource Appraisal programme. The province lies in the offshore area between western Greenland and eastern Canada and includes Baffin Bay, Davis Strait, Lancaster Sound and Nares Strait west of and including part of Kane Basin. A series of major tectonic events led to the formation of several distinct structural domains that are the geological basis for defining five assessment units (AU) in the province, all of which are within the Mesozoic-Cenozoic Composite Petroleum System. Potential petroleum source rocks include strata of Ordovician, Lower and Upper Cretaceous, and Palaeogene ages. The five AUs defined for this study - the Eurekan Structures AU, NW Greenland Rifted Margin AU, NE Canada Rifted Margin AU, Baffin Bay Basin AU and the Greater Ungava Fault Zone AU - encompass the entire province and were assessed for undiscovered technically recoverable resources. The mean volumes of undiscovered resources for the West Greenland-East Canada Province are 10.7 ?? 109 barrels of oil, 75 ?? 1012 cubic feet of gas, and 1.7 ?? 109 barrels of natural gas liquids. For the part of the province that is north of the Arctic Circle, the estimated mean volumes of these undiscovered resources are 7.3 ?? 109 barrels of oil, 52 ?? 1012 cubic feet of natural gas, and 1.1 ?? 109 barrels of natural gas liquids. ?? 2011 The Geological Society of London.

Tectonosedimentary framework of Upper Cretaceous -Neogene series in the Gulf of Tunis inferred from subsurface data: implications for petroleum exploration

NASA Astrophysics Data System (ADS)

Dhraief, Wissem; Dhahri, Ferid; Chalwati, Imen; Boukadi, Noureddine

2017-04-01

The objective and the main contribution of this issue are dedicated to using subsurface data to delineate a basin beneath the Gulf of Tunis and its neighbouring areas, and to investigate the potential of this area in terms of hydrocarbon resources. Available well data provided information about the subsurface geology beneath the Gulf of Tunis. 2D seismic data allowed delineation of the basin shape, strata geometries, and some potential promising subsurface structures in terms of hydrocarbon accumulation. Together with lithostratigraphic data obtained from drilled wells, seismic data permitted the construction of isochron and isobath maps of Upper Cretaceous-Neogene strata. Structural and lithostratigraphic interpretations indicate that the area is tectonically complex, and they highlight the tectonic control of strata deposition during the Cretaceous and Neogene. Tectonic activity related to the geodynamic evolution of the northern African margin appears to have been responsible for several thickness and facies variations, and to have played a significant role in the establishment and evolution of petroleum systems in northeastern Tunisia. As for petroleum systems in the basin, the Cretaceous series of the Bahloul, Mouelha and Fahdene formations are acknowledged to be the main source rocks. In addition, potential reservoirs (Fractured Abiod and Bou Dabbous carbonated formations) sealed by shaly and marly formations (Haria and Souar formations respectively) show favourable geometries of trap structures (anticlines, tilted blocks, unconformities, etc.) which make this area adequate for hydrocarbon accumulations.

Asphaltene-bearing mantle xenoliths from Hyblean diatremes, Sicily

NASA Astrophysics Data System (ADS)

Scirè, Salvatore; Ciliberto, Enrico; Crisafulli, Carmelo; Scribano, Vittorio; Bellatreccia, Fabio; Ventura, Giancarlo Della

2011-08-01

Microscopic blebs of sulfur-bearing organic matter (OM) commonly occur between the secondary calcite grains and fibrous phyllosilicates in extensively serpentinized and carbonated mantle-derived ultramafic xenoliths from Hyblean nephelinite diatremes, Sicily, Italy. Rarely, coarse bituminous patches give the rock a blackish color. Micro Fourier transform infrared spectra (μ-FTIR) point to asphaltene-like structures in the OM, due to partially condensed aromatic rings with aliphatic tails consisting of a few C atoms. X-ray photoelectron spectroscopy (XPS) analysis indicates the occurrence of minor S═O (either sulphonyl or sulphoxide) functional groups in the OM. Solubility tests in toluene, thermo-gravimetric (TGA) and differential thermal (DTA) analyses confirm the presence of asphaltene structures. It is proposed that asphaltenes derive from the in situ aromatization (with decrease in H/C ratio) of previous light aliphatic hydrocarbons. Field evidence excludes that hydrocarbon from an external source percolated through the xenolith bearing tuff-breccia. The discriminating presence of hydrocarbon in a particular type of xenolith only and the lack of hydrocarbon in the host breccia matrix, are also inconsistent with an interaction between the ascending eruptive system and a supposed deep-seated oil reservoir. Assuming that the Hyblean unexposed basement consists of mantle ultramafics and mafic intrusive rocks having hosted an early abyssal-type hydrothermal system, one can put forward the hypothesis that the hydrocarbon production was related to hydrothermal activity in a serpentinite system. Although a bacteriogenesis or thermogenesis cannot be ruled out, the coexisting serpentine, Ni-Fe ores and hydrocarbon strongly suggest a Fischer-Tropsch-type (FTT) synthesis. Subsequent variations in the chemical and physical conditions of the system, for example an increase in the water/rock ratio, gave rise to partial oxidation and late carbonation of the serpentinite hosted hydrocarbon. Admitting an authigenic origin for most of the modal calcite (30-50% by volume) in these rocks, one can conclude as a general rule that un-carbonated serpentinites tectonically emplaced at shallow crustal levels are potential reservoir rocks (as well putative source rocks) for exploitable petroleum reserves.

Petroleum Market Model of the National Energy Modeling System. Part 1

DOE Office of Scientific and Technical Information (OSTI.GOV)

NONE

The purpose of this report is to define the objectives of the Petroleum Market Model (PMM), describe its basic approach, and provide detail on how it works. This report is intended as a reference document for model analysts, users, and the public. The PMM models petroleum refining activities, the marketing of petroleum products to consumption regions, the production of natural gas liquids in gas processing plants, and domestic methanol production. The PMM projects petroleum product prices and sources of supply for meeting petroleum product demand. The sources of supply include crude oil, both domestic and imported; other inputs including alcoholsmore » and ethers; natural gas plant liquids production; petroleum product imports; and refinery processing gain. In addition, the PMM estimates domestic refinery capacity expansion and fuel consumption. Product prices are estimated at the Census division level and much of the refining activity information is at the Petroleum Administration for Defense (PAD) District level.« less

Application of seismic-refraction techniques to hydrologic studies

USGS Publications Warehouse

Haeni, F.P.

1986-01-01

During the past 30 years, seismic-refraction methods have been used extensively in petroleum, mineral, and engineering investigations, and to some extent for hydrologic applications. Recent advances in equipment, sound sources, and computer interpretation techniques make seismic refraction a highly effective and economical means of obtaining subsurface data in hydrologic studies. Aquifers that can be defined by one or more high seismic-velocity surfaces, such as (1) alluvial or glacial deposits in consolidated rock valleys, (2) limestone or sandstone underlain by metamorphic or igneous rock, or (3) saturated unconsolidated deposits overlain by unsaturated unconsolidated deposits,are ideally suited for applying seismic-refraction methods. These methods allow the economical collection of subsurface data, provide the basis for more efficient collection of data by test drilling or aquifer tests, and result in improved hydrologic studies.This manual briefly reviews the basics of seismic-refraction theory and principles. It emphasizes the use of this technique in hydrologic investigations and describes the planning, equipment, field procedures, and intrepretation techniques needed for this type of study.Examples of the use of seismic-refraction techniques in a wide variety of hydrologic studies are presented.

Application of seismic-refraction techniques to hydrologic studies

USGS Publications Warehouse

Haeni, F.P.

1988-01-01

During the past 30 years, seismic-refraction methods have been used extensively in petroleum, mineral, and engineering investigations and to some extent for hydrologic applications. Recent advances in equipment, sound sources, and computer interpretation techniques make seismic refraction a highly effective and economical means of obtaining subsurface data in hydrologic studies. Aquifers that can be defined by one or more high-seismic-velocity surface, such as (1) alluvial or glacial deposits in consolidated rock valleys, (2) limestone or sandstone underlain by metamorphic or igneous rock, or (3) saturated unconsolidated deposits overlain by unsaturated unconsolidated deposits, are ideally suited for seismic-refraction methods. These methods allow economical collection of subsurface data, provide the basis for more efficient collection of data by test drilling or aquifer tests, and result in improved hydrologic studies. This manual briefly reviews the basics of seismic-refraction theory and principles. It emphasizes the use of these techniques in hydrologic investigations and describes the planning, equipment, field procedures, and interpretation techniques needed for this type of study. Further-more, examples of the use of seismic-refraction techniques in a wide variety of hydrologic studies are presented.

Map showing drill-hole depths, lithologic intercepts, and partial isopachs of basin fill in the Winnemucca 1 degree by 2 degrees Quadrangle, Nevada

USGS Publications Warehouse

Moring, B.C.

1990-01-01

Wells logs used for this map of the Winnemucca quadrangle are from the following sources: (1) logs of more than 1,000 water wells reported to the State of Nevada Division of Water Resources, which are on file with them in Reno and at the with U.S. Geological Survey in Carson City, (2) 44 petroleum wells collected by the Nevada Bureau of Mines (Lintz, 1957; Schilling and Garside, 1968; Garside and Schilling, 1977, Garside and others, 1977; 1988), and (3) Two geothermal wells reported in Zoback (1979) and Flynn and others (1982). Data from isostatic residual and Bouguer gravity maps by Wagini (1985) contributed to the interpretation of basin configuration. Gravity models of Dixie Valley (Schaefer, 1982, and Speed, 1976) and Grass Valley (Grannell and Noble, 1977) and seismic profiles of Grass and Pine Valleys (Potter and others, 1987) helped refine basis interpretations in those areas. The geologic base map of Paleozoic and Mesozoic igneous and sedimentary rocks, Tertiary volcanic and sedimentary rocks, and Cenozoic structures was simplified from Stewart and Carlson (1976b).

Field Verification Program (Aquatic Disposal): Comparison of Field and Laboratory Bioaccumulation of Organic and Inorganic Contaminants from Black Rock Harbor Dredged Material

DTIC Science & Technology

1988-05-01

include poly- chlorinated biphenyls (PCBs) and related chlorinated pesticides of similar polarity in addition to the petroleum hydrocarbons . The...Ui It tILL (JV: FIELD VERIFICATION PROGRAM (AQUATIC DISPOSAL).’Wh TECHNICAL REPORT D-87-6 COMPARISON OF FIELD AND LABORATORY BIOACCUMULATION OF...Laboratory Bioaccumulation of Organic and Inorganic Contaminants from Black Rock Harbor Dredged Material 12 PERSONAL AUTHOR(S) Lake, James L.; Galloway

Sedimentary rock-hosted Au deposits of the Dian-Qian-Gui area, Guizhou, and Yunnan Provinces, and Guangxi District, China

USGS Publications Warehouse

Peters, S.G.; Jiazhan, H.; Zhiping, L.; Chenggui, J.

2007-01-01

Sedimentary rock-hosted Au deposits in the Dian-Qian-Gui area in southwest China are hosted in Paleozoic and early Mesozoic sedimentary rocks along the southwest margin of the Yangtze (South China) Precambrian craton. Most deposits have characteristics similar to Carlin-type Au deposits and are spatially associated, on a regional scale, with deposits of coal, Sb, barite, As, Tl, and Hg. Sedimentary rock-hosted Au deposits are disseminated stratabound and(or) structurally controlled. The deposits have many similar characteristics, particularly mineralogy, geochemistry, host rock, and structural control. Most deposits are associated with structural domes, stratabound breccia bodies, unconformity surfaces or intense brittle-ductile deformation zones, such as the Youjiang fault system. Typical characteristics include impure carbonate rock or calcareous and carbonaceous host rock that contains disseminated pyrite, marcasite, and arsenopyrite-usually with ??m-sized Au, commonly in As-rich rims of pyrite and in disseminations. Late realgar, orpiment, stibnite, and Hg minerals are spatially associated with earlier forming sulfide minerals. Minor base-metal sulfides, such as galena, sphalerite, chalcopyrite, and Pb-Sb-As-sulphosalts also are present. The rocks locally are silicified and altered to sericite-clay (illite). Rocks and(or) stream-sediment geochemical signatures typically include elevated concentrations of As, Sb, Hg, Tl, and Ba. A general lack of igneous rocks in the Dian-Qian-Gui area implies non-pluton-related, ore forming processes. Some deposits contain evidence that sources of the metal may have originated in carbonaceous parts of the sedimentary pile or other sedimentary or volcanic horizons. This genetic process may be associated with formation and mobilization of petroleum and Hg in the region and may also be related to As-, Au-, and Tl-bearing coal horizons. Many deposits also contain textures and features indicative of strong structural control by tectonic domes or shear zones and also suggest syndeformational ore deposition, possibly related to the Youjiang fault system. Several sedimentary rock-hosted Au deposits in the Dian-Qian-Gui area also are of the red earth-type and Au grades have been concentrated and enhanced during episodes of deep weathering. ?? 2006 Elsevier B.V. All rights reserved.

Petroleum developments in North Africa in 1979

DOE Office of Scientific and Technical Information (OSTI.GOV)

Nicod, M.A.

In the 6 countries covered by this report, the extent of valid petroleum rights, seismic work, and drilling was nearly the same as in 1978. The success rate of wildcat drilling decreased slightly, to 28% (33% in 1978), with 26 oil or gas discoveries. In southwestern Tunisia, the Amoco Sabrina Nord 1 tested 930 bbl of 39/sup 0/ APl oil from Cambrian-Ordovician sandstones - the first oil to come from lower Paleozoic rocks in Tunisia. First commercial oil from Cambrian-Ordovician rocks in western Libya was discovered by Agip A1-NC40 which flowed 1,400 b/d. Highlight of the year in North Africamore » was in the interior basin of Sudan where the Chevron Abu Gabra 1 tested 900 BOPD of 40/sup 0/ APl oil from Cretaceous rocks; 2 other wells, spudded in late 1979 in the same area, have tested 3,200 and 7,300 b/d, respectively, in early 1980. Discovery well of the interior basin was Chevron Unity 1 which tested small amounts of oil in 1978. Oil production in North Africa in 1979 averaged 3,939,500 b/d compared with 3,802,800 b/d in 1978, an increase of 3.6%.« less

Tectonic evolution of the Anadyr Basin, northeastern Eurasia, and its petroleum resource potential

NASA Astrophysics Data System (ADS)

Antipov, M. P.; Bondarenko, G. E.; Bordovskaya, T. O.; Shipilov, E. V.

2009-09-01

The published data on the sedimentation conditions, structure, and tectonic evolution of the Anadyr Basin in the Mesozoic and Cenozoic are reviewed. These data are re-examined in the context of modern tectonic concepts concerning the evolution of the northwestern Circum-Pacific Belt. The re-examination allows us not only to specify the regional geology and tectonic history, but also to forecast of the petroleum resource potential of the sedimentary cover based on a new concept. The sedimentary cover formation in the Anadyr Basin is inseparably linked with the regional tectonic evolution. The considered portion of the Chukchi Peninsula developed in the Late Mesozoic at the junction of the ocean-type South Anyui Basin, the Asian continental margin, and convergent zones of various ages extending along the Asia-Pacific interface. Strike-slip faulting and pulses of extension dominated in the Cenozoic largely in connection with oroclinal bending of structural elements pertaining to northeastern Eurasia and northwestern North America against the background of accretion of terranes along the zone of convergence with the Pacific oceanic plates. Three main stages are recognized in the formation of the sedimentary cover in the Anadyr Basin. (1) The lower portion of the cover was formed in the Late Cretaceous-Early Eocene under conditions of alternating settings of passive and active continental margins. The Cenomanian-lower Eocene transitional sedimentary complex is located largely in the southern Anadyr Basin (Main River and Lagoonal troughs). (2) In the middle Eocene and Oligocene, sedimentation proceeded against the background of extension and rifting in the northern part of the paleobasin and compression in its southern part. The compression was caused by northward migration of the foredeep in front of the accretionary Koryak Orogen. The maximum thickness of the Eocene-Oligocene sedimentary complex is noted mainly in the southern part of the basin and in the Central and East Anadyr troughs. (3) The middle Miocene resumption of sedimentation was largely related to strike-slip faulting and rifting. In the Miocene to Quaternary, sedimentation was the most intense in the central and northern parts of the Anadyr Basin, as well as in local strike-slip fault-line depressions of the Central Trough. Geological and geophysical data corroborate thrusting in the southern Anadyr Basin. The amplitude of thrusting over the Main River Trough reaches a few tens of kilometers. The vertical thickness of the tectonically screened Paleogene and Neogene rocks in the southern Main River Trough exceeds 10 km. The quantitative forecast of hydrocarbon emigration from Cretaceous and Paleogene source rocks testifies to the disbalance between hydrocarbons emigrated and accumulated in traps of petroleum fields discovered in the Anadyr Basin. The southern portion of the Anadyr Basin is the most promising for the discovery of new petroleum fields in the Upper Cretaceous, Eocene, and Upper Oligocene-Miocene porous and fracture-porous reservoir rocks in subthrust structural and lithological traps.

Update on BioVapor Analysis (Draft Deliberative Document)

EPA Science Inventory

An update is given on EPA ORD's evaluation of the BioVapor model for petroleum vapor intrusion assessment. Results from two scenarios are presented: a strong petroleum source and a weaker source. Model results for the strong source are shown to depend on biodegradation rate, oxyg...

Study of southern CHAONAN sag lower continental slope basin deposition character in Northern South China Sea

NASA Astrophysics Data System (ADS)

Tang, Y.

2009-12-01

Northern South China Sea Margin locates in Eurasian plate,Indian-Australia plate,Pacific Plates.The South China Sea had underwent a complicated tectonic evolution in Cenozoic.During rifting,the continental shelf and slope forms a series of Cenozoic sedimentary basins,including Qiongdongnan basin,Pearl River Mouth basin,Taixinan basin.These basins fill in thick Cenozoic fluviolacustrine facies,transitional facies,marine facies,abyssal facies sediment,recording the evolution history of South China Sea Margin rifting and ocean basin extending.The studies of tectonics and deposition of depression in the Southern Chaonan Sag of lower continental slope in the Norther South China Sea were dealt with,based on the sequence stratigraphy and depositional facies interpretation of seismic profiles acquired by cruises of“China and Germany Joint Study on Marine Geosciences in the South China Sea”and“The formation,evolution and key issues of important resources in China marginal sea",and combining with ODP 1148 cole and LW33-1-1 well.The free-air gravity anomaly of the break up of the continental and ocean appears comparatively low negative anomaly traps which extended in EW,it is the reflection of passive margin gravitational effect.Bouguer gravity anomaly is comparatively low which is gradient zone extended NE-SW.Magnetic anomaly lies in Magnetic Quiet Zone at the Northern Continental Margin of the South China Sea.The Cenozoic sediments of lower continental slope in Southern Chaonan Sag can be divided into five stratum interface:SB5.5,SB10.5,SB16.5,SB23.8 and Hg,their ages are of Pliocene-Quaternary,late Miocene,middle Miocene,early Miocene,paleogene.The tectonic evolution of low continental slope depressions can be divided into rifting,rifting-depression transitional and depression stages,while their depositional environments change from river to shallow marine and abyssa1,which results in different topography in different stages.The topographic evolvement in the study area includes three stages,that is Eogene,middle stage of lately Oligocene to early Miocene and middle Miocene to Present.Result shows that there are a good association of petroleum source rocks,reservoir rocks and seal rocks and structural traps in the Cenozoic and Mesozoic strata,as well as good conditions for the generation-migration-accumulation-preservation of petroleum in the lower continatal slope of Southern Chaoshan Sag.So the region has good petroleum prospect. Key words:Northern South China Sea;Chaoshan Sag; lower continental slope; deposition.

76 FR 22825 - Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems

Federal Register 2010, 2011, 2012, 2013, 2014

2011-04-25

... Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems AGENCY: Environmental Protection Agency... Subpart W: Petroleum and Natural Gas Systems of the Greenhouse Gas Reporting Rule. As part of the... greenhouse gas emissions for the petroleum and natural gas systems source category of the greenhouse gas...

Source profiles for nonmethane organic compounds in the atmosphere of Cairo, Egypt.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Doskey, P. V.; Fukui, Y.; Sultan, M.

1999-07-01

Profiles of the sources of nonmethane organic compounds (NMOCs) were developed for emissions from vehicles, petroleum fuels (gasoline, liquefied petroleum gas (LPG), and natural gas), a petroleum refinery, a smelter, and a cast iron factory in Cairo, Egypt. More than 100 hydrocarbons and oxygenated hydrocarbons were tentatively identified and quantified. Gasoline-vapor and whole-gasoline profiles could be distinguished from the other profiles by high concentrations of the C{sub 5} and C{sub 6} saturated hydrocarbons. The vehicle emission profile was similar to the whole-gasoline profile, with the exception of the unsaturated and aromatic hydrocarbons, which were present at higher concentrations in themore » vehicle emission profile. High levels of the C{sub 2}-C{sub 4} saturated hydrocarbons, particularly n-butane, were characteristic features of the petroleum refinery emissions. The smelter and cast iron factory emissions were similar to the refinery emissions; however, the levels of benzene and toluene were greater in the former two sources. The LPG and natural gas emissions contained high concentrations of n-butane and ethane, respectively. The NMOC source profiles for Cairo were distinctly different from profiles for U.S. sources, indicating that NMOC source profiles are sensitive to the particular composition of petroleum fuels that are used in a location.« less

Chemical composition of selected Kansas brines as an aid to interpreting change in water chemistry with depth

USGS Publications Warehouse

Dingman, R.J.; Angino, E.E.

1969-01-01

Chemical analyses of approximately 1,881 samples of water from selected Kansas brines define the variations of water chemistry with depth and aquifer age. The most concentrated brines are found in the Permian rocks which occupy the intermediate section of the geologic column of this area. Salinity decreases below the Permian until the Ordovician (Arbuckle) horizon is reached and then increases until the Precambrian basement rocks are reached. Chemically, the petroleum brines studied in this small area fit the generally accepted pattern of an increase in calcium, sodium and chloride content with increasing salinity. They do not fit the often-predicted trend of increases in the calcium to chloride ratio, calcium content and salinity with depth and geologic age. The calcium to chloride ratio tends to be asymptotic to about 0.2 with increasing chloride content. Sulfate tends to decrease with increasing calcium content. Bicarbonate content is relatively constant with depth. If many of the hypotheses concerning the chemistry of petroleum brines are valid, then the brines studied are anomolous. An alternative lies in accepting the thesis that exceptions to these hypotheses are rapidly becoming the rule and that indeed we still do not have a valid and general hypothesis to explain the origin and chemistry of petroleum brines. ?? 1969.

Sediments, structural framework, petroleum potential, environmental conditions, and operational considerations of the United States North Atlantic Outer Continental Shelf

USGS Publications Warehouse

,

1975-01-01

The area designated for possible oil and gas lease sale as modified from BLM memorandum 3310 #42 (722) and referred to therein as the North Atlantic Outer Continental Shelf (OCS) contains about 58,300 sq km of shelf beneath water depths of less than 200 m and lies chiefly within the Georges Bank basin. The oldest sediments drilled or dredged on the bordering Continental Slope are sandstone, clay, and silt of Upper Cretaceous age. In Upper Cretaceous exposures, on Marthas Vineyard and nearby New England islands, the predominant lithology appears to be clay. About 125 km northeast of the eastern tip of Georges Bank, the Shell B-93 well penetrated clays and silts of Upper and Lower Cretaceous age above dense Jurassic carbonate rocks which overlie a basement of lower Paleozoic slate, schist, quartzite, and granite. Structurally, the Georges Bank basin is a westerly trending trough which opens to the west-southwest. Post-Paleozoic sediments are more than 8 km thick in parts of the basin. Major structural features appear to be directly related to basement structures. Local anticlines, probably caused by differential compaction over basement flexures and horst blocks or by later uplift along basement faults are reflected principally in Lower Cretaceous and older sediments, though some of these features continue upward to within 0.7 of a second (about 650 m) of the seafloor. Tertiary deposits in the Georges Bank basin are probably up to a kilometre thick and are made up of poorly consolidated sand, silt, and clay. The Cretaceous section is inferred to be up to 3.5 km thick and to be mainly clastics -- shale, siltstone, calcareous shale, changing to limestone in the lowest part of the system. Jurassic rocks in the deepest part of the basin appear to be about 3.6 to 4.0 km thick and probably consist mainly of dense carbonates. Potential source rocks in the Georges Bank basin may include organic-rich Cretaceous shale and carbonaceous Jurassic limestone. By analogy with the Scotian Shelf, Cretaceous sandstones are considered to be potential reservoir rocks. Local zones of porous dolomite are believed to be present in carbonate rocks of Jurassic age and should not be overlooked as potential reservoirs. Structural highs related to draping and differential compaction over basement blocks could be important potential petroleum traps. Additional traps may include reef structures near the shelf edge, updip pinchouts, and stratigraphic traps in both clastic and carbonate sediment. A statistical mean for the undiscovered recoverable petroleum resources is calculated to be 0.9 billion barrels of oil and 4.2 trillion cubic feet of gas. At the 5 percent probability level (1 in 20 chance) the undiscovered recoverable petroleum resources are calculated to be 2.4 billion barrels of oil and 12.5 trillion cubic feet of gas. These undiscovered recoverable petroleum resources are those quantities of oil and gas that may be reasonably expected to exist in favorable settings, but which have not yet been identified by drilling. Such estimates, therefore, carry a high degree of uncertainty. Environmental studies of Georges Bank indicated a low-moderate risk from petroleum development. However, the risk estimate is based on very limited data. Drift bottle returns used to infer oil spill trajectories show about a 2% overall recovery rate. Meteorologic data comes mainly from nearby land areas and from ships attempting to avoid storms. Seismicity on Georges Bank is low. This may reflect, in large part, the difficulty of land-based stations in recording earthquakes far from the coast. Direct data on the engineering properties of shallow buried sediment comes mainly from two Texas Tower surveys of limited areas on Georges Shoal and Nantucket Shoals made in the early 1950's. The 17 holes (most less than 30 m deep) reveal some silty layers below loose sand and much lateral variability in sediment type over short distances. The technology for exploration at the required water depths (20 m - 200 m) is available. Mobil drilling units are in great demand around the world and will have to be brought in from other areas along with skilled manpower. Our highest estimates indicate 50 platforms, 800 producing wells, 1,100 km of pipeline, and 5 onshore terminals may be needed. The time frame for production, using our high estimates (5% probability) for the undiscovered recoverable resources, could include 4-5 years for significant development, 6-7 years until production commences, and 18 years until peak production.

Energy resources of the United States

USGS Publications Warehouse

Theobald, P.K.; Schweinfurth, Stanley P.; Duncan, Donald Cave

1972-01-01

Estimates are made of United States resources of coal, petroleum liquids, natural gas, uranium, geothermal energy, and oil from oil shale. The estimates, compiled by specialists of the U.S. Geological Survey, are generally made on geologic projections of favorable rocks and on anticipated frequency of the energy resource in the favorable rocks. Accuracy of the estimates probably ranges from 20 to 50 percent for identified-recoverable resources to about an order of magnitude for undiscovered-submarginal resources. The total coal resource base in the United States is estimated to be about 3,200 billion tons, of which 200-390 billion tons can be considered in the category identified and recoverable. More than 70 percent of current production comes from the Appalachian basin where the resource base, better known than for the United States as a whole, is about 330 billion tons, of which 22 billion tons is identified and recoverable. Coals containing less than 1 percent sulfur are the premium coals. These are abundant in the western coal fields, but in the Appalachian basin the resource base for low-sulfur coal is estimated to be only a little more than 100 billion tons, of which 12 billion tons is identified and recoverable. Of the many estimates of petroleum liquids and natural-gas resources, those of the U.S. Geological Survey are the largest because, in general, our estimates include the largest proportion of favorable ground for exploration. We estimate the total resource base for petroleum liquids to be about 2,900 billion barrels, of which 52 billion barrels is identified and recoverable. Of the total resource base, some 600 billion barrels is in Alaska or offshore from Alaska, 1,500 billion barrels is offshore from the United States, and 1,300 billion barrels is onshore in the conterminous United States. Identified-recoverable resources of petroleum liquids corresponding to these geographic units are 11, 6, and 36 billion barrels, respectively. The total natural-gas resource of the United States is estimated to be about 6,600 trillion cubic feet, of which 290 trillion cubic feet is identified and recoverable. In geographic units comparable to those for petroleum liquids, the resource bases are 1,400, 3,400, and 2,900 trillion cubic feet, and the identified-recoverable resources are 31, 40, and 220 trillion cubic feet, respectively. Uranium resources in conventional deposits, where uranium is the major product, are estimated at 1,600,000 tons of U3O8, of which 250,000 tons is identified and recoverable. A potential byproduct resource of more than 7 million tons of U3O8, is estimated for phosphate rock, but none of this resource is recoverable under present economic conditions. The resources of heat in potential geothermal energy sources are poorly known. The total resource base for the United States is certainly greater than 10 22 calories, of which only 2.5 ? 10 18 calories can be considered identified and recoverable at present. Oil shale is estimated to contain 26 trillion barrels of oil. None of this resource is economic at present, but if prices increase moderately, 160-600 billion barrels of this oil could be shifted into the identified-recoverable category.

Regional stratigraphy and petroleum potential, Ghadames basin, Algeria

DOE Office of Scientific and Technical Information (OSTI.GOV)

Emme, J.J.; Sunderland, B.L.

1991-03-01

The Ghadames basin in east-central Algeria extends over 65,000 km{sup 2} (25,000 mi{sup 2}), of which 90% is covered by dunes of the eastern Erg. This intracratonic basin consists of up to 6000 m (20,000 ft) of dominantly clastic Paleozoic through Mesozoic strata. The Ghadames basin is part of a larger, composite basin complex (Ilizzi-Ghadames-Triassic basins) where Paleozoic strata have been truncated during a Hercynian erosional event and subsequently overlain by a northward-thickening wedge of Mesozoic sediments. Major reservoir rocks include Triassic sandstones that produce oil, gas, and condensate in the western Ghadames basin, Siluro-Devonian sandstones that produce mostly oilmore » in the shallower Ilizzi basin to the south, and Cambro-Ordovician orthoquartzites that produce oil at Hassi Messaoud to the northwest. Organic shales of the Silurian and Middle-Upper Devonian are considered primary source rocks. Paleozoic shales and Triassic evaporite/red bed sequences act as seals for hydrocarbon accumulations. The central Ghadames basin is underexplored, with less than one wildcat well/1700 km{sup 2} (one well/420,000 ac). Recent Devonian and Triassic oil discoveries below 3500 m (11,500 ft) indicate that deep oil potential exists. Exploration to date has concentrated on structural traps. Subcrop and facies trends indicate that potential for giant stratigraphic or combination traps exists for both Siluro-Devonian and Triassic intervals. Modern seismic acquisition and processing techniques in high dune areas can be used to successfully identify critical unconformity-bound sequences with significant stratigraphic trap potential. Advances in seismic and drilling technology combined with creative exploration should result in major petroleum discoveries in the Ghadames basin.« less

Earth Observations taken by the Expedition 13 crew

NASA Image and Video Library

2006-05-25

ISS013-E-26488 (25 May 2006) --- Yates Oilfield, west Texas is featured in this image photographed by an Expedition 13 crewmember on the International Space Station. The Permian Basin of west Texas and southeastern New Mexico is one of the most productive petroleum provinces of North America. The Basin is a large depression in the Precambrian bedrock surface along the southern edge of the North American craton, or oldest bedrock core of the continent. The Yates Oil Field is marked in this image by numerous white well locations and petroleum infrastructure dotting the layered sedimentary rocks of the Permian Basin. The Pecos River bed borders the oil field to the east-northeast. The Yates Field started petroleum production in 1926, and by 1995 had produced over 2 billion barrels of oil.

40 CFR 70.2 - Definitions.

Code of Federal Regulations, 2012 CFR

2012-07-01

...: (i) Coal cleaning plants (with thermal dryers); (ii) Kraft pulp mills; (iii) Portland cement plants... plants; (xii) Phosphate rock processing plants; (xiii) Coke oven batteries; (xiv) Sulfur recovery plants...) totaling more than 250 million British thermal units per hour heat input; (xxii) Petroleum storage and...

40 CFR 71.2 - Definitions.

Code of Federal Regulations, 2012 CFR

2012-07-01

...: (i) Coal cleaning plants (with thermal dryers); (ii) Kraft pulp mills; (iii) Portland cement plants... plants; (xii) Phosphate rock processing plants; (xiii) Coke oven batteries; (xiv) Sulfur recovery plants...) totaling more than 250 million British thermal units per hour heat input; (xxii) Petroleum storage and...

EIA model documentation: Petroleum market model of the national energy modeling system

DOE Office of Scientific and Technical Information (OSTI.GOV)

NONE

1995-12-28

The purpose of this report is to define the objectives of the Petroleum Market Model (PMM), describe its basic approach, and provide detail on how it works. This report is intended as a reference document for model analysts, users, and the public. Documentation of the model is in accordance with EIA`s legal obligation to provide adequate documentation in support of its models. The PMM models petroleum refining activities, the marketing of petroleum products to consumption regions, the production of natural gas liquids in gas processing plants, and domestic methanol production. The PMM projects petroleum product prices and sources of supplymore » for meeting petroleum product demand. The sources of supply include crude oil, both domestic and imported; other inputs including alcohols and ethers; natural gas plant liquids production; petroleum product imports; and refinery processing gain. In addition, the PMM estimates domestic refinery capacity expansion and fuel consumption. Product prices are estimated at the Census division level and much of the refining activity information is at the Petroleum Administration for Defense (PAD) District level.« less

Prospecting for Methane in Arabia Terra, Mars - First Results

NASA Technical Reports Server (NTRS)

Allen, Carlton C.; Oehler, Dotoyhy Z.; Venechuk, Elizabeth M.

2006-01-01

Methane has been measured in the Martian atmosphere at concentrations of approx. 10 ppb. Since the photochemical lifetime of this gas is approx. 300 years, it is likely that methane is currently being released from the surface. Possible sources for the methane include 1) hydrothermal activity, 2) serpentinization of basalts and other water-rock interactions, 3) thermal maturation of sedimentary organic matter, and 4) metabolism of living bacteria. Any such discovery would revolutionize our understanding of Mars. Longitudinal variations in methane concentration, as measured by the Planetary Fourier Spectrometer (PFS) on Mars Express, show the highest values over Arabia Terra, Elysium Planum, and Arcadia-Memnonia, suggesting localized areas of methane release. We are using orbital data and methodologies derived from petroleum exploration in an attempt to locate these release points.

Location and age of foraminifer samples collected by Chevron Petroleum geologists in California

USGS Publications Warehouse

Brabb, Earl E.; Parker, John M.

2003-01-01

Most of the geologic maps published for parts of central California in the past century have been made without the benefit of ages from microfossils. The ages of Jurassic, Cretaceous and Tertiary rocks in the mostly poorly exposed and structurally complex sedimentary rocks represented in the Coast Ranges are critical in determining stratigraphic succession or lack of it, and in determining whether the juxtaposition of similar appearing but different age formations means that a fault is present. Since the 1940's, at least, oil company geologists have used microfossils to assist them in geologic mapping and in determining the environments of deposition of the sedimentary rocks containing them. This information had been so confidential that even the names of species were coded by some paleontologists to prevent disclosure. In the past 20 years, however, the attitude of petroleum companies about this information has changed, and many of the formerly confidential materials and reports are now available. We report here on an estimated 50,000 Chevron foraminifer samples from surface localities in more than 600 U.S. Geological Survey 7.5' quadrangles in California. Ages are provided for more than 27,000 of these samples which have been donated by Chevron, along with locality maps, paleontology reports, and other data, to the California Academy of Sciences. To our knowledge, this collection is the largest ever released to the public by a petroleum company for the West Coast. The information from the slides can be used to update geologic maps prepared without the benefit of microfossils, to study foraminifers of Jurassic, Cretaceous and Tertiary age collected from a variety of geologic environments, to analyze the depth and temperature of ocean water covering parts of California during these periods, and for solving nomenclature and other scientific problems.

Maps showing sedimentary basins, surface thermal maturity, and indications of petroleum in the Central Alaska Province

USGS Publications Warehouse

Troutman, Sandra M.; Stanley, Richard G.

2003-01-01

This publication includes two maps (at 1:2,500,000 scale) and a pamphlet that describe sedimentary basins, surface thermal maturity, and 95 reported occurrences of petroleum in natural seeps, wells, and rock outcrops in central Alaska. No commercial petroleum production has been obtained from central Alaska, in contrast to the prolific deposits of oil and gas that have been found and developed in northern Alaska and the Cook Inlet region. Nevertheless, confirmed indications of petroleum in central Alaska include (1) natural seeps of methane gas on the Yukon Delta; (2) occurrences of methane gas in wells in the Bethel, Kotzebue, Nenana, Northway, and Yukon Flats basins; (3) oil and methane gas in seeps and wells in Norton Sound; (4) small quantities of liquid and solid hydrocarbons associated with mercury ore in the Kuskokwim Mountains; (5) oil shale and numerous occurrences of bitumen in the Kandik area; and (6) tasmanite, a form of oil shale, in the uplands north of Yukon Flats.

Evaluating the Poroelastic Effect on Anisotropic, Organic-Rich, Mudstone Systems

NASA Astrophysics Data System (ADS)

Suarez-Rivera, Roberto; Fjær, Erling

2013-05-01

Understanding the poroelastic effect on anisotropic organic-rich mudstones is of high interest and value for evaluating coupled effects of rock deformation and pore pressure, during drilling, completion and production operations in the oilfield. These applications include modeling and prevention of time-dependent wellbore failure, improved predictions of fracture initiation during hydraulic fracturing operations (Suarez-Rivera et al. Presented at the Canadian Unconventional Resources Conference held in Calgary, Alberta, Canada, 15-17 November 2011. CSUG/SPE 146998 2011), improved understanding of the evolution of pore pressure during basin development, including subsidence and uplift, and the equilibrated effective in situ stress (Charlez, Rock mechanics, vol 2 1997; Katahara and Corrigan, Pressure regimes in sedimentary basins and their prediction: AAPG Memoir, vol 76, pp 73-78 2002; Fjær et al. Petroleum related rock mechanics. 2nd edn 2008). In isotropic rocks, the coupled poro-elastic deformations of the solid framework and the pore fluids are controlled by the Biot and Skempton coefficients. These are the two fundamental properties that relate the rock framework and fluid compressibility and define the magnitude of the poroelastic effect. In transversely isotropic rocks, one desires to understand the variability of these coefficients along the directions parallel and longitudinal to the principal directions of material symmetry (usually the direction of bedding). These types of measurements are complex and uncommon in low-porosity rocks, and particularly problematic and scarce in tight shales. In this paper, we discuss a methodology for evaluating the Biot's coefficient, its variability along the directions parallel and perpendicular to bedding as a function of stress, and the homogenized Skempton coefficient, also as a function of stress. We also predict the pore pressure change that results during undrained compression. Most importantly, we provide values of transverse and longitudinal Biot's coefficients and the homogenized Skempton coefficient for two important North American, gas-producing, organic-rich mudstones. These results could be used for petroleum-related applications.

Use of nanotomographic images for structure analysis of carbonate rocks

DOE Office of Scientific and Technical Information (OSTI.GOV)

Nagata, Rodrigo; Appoloni, Carlos Roberto

Carbonate rocks store more than 50% of world's petroleum. These rocks' structures are highly complex and vary depending on many factors regarding their formation, e.g., lithification and diagenesis. In order to perform an effective extraction of petroleum it is necessary to know petrophysical parameters, such as total porosity, pore size and permeability of the reservoir rocks. Carbonate rocks usually have a range of pore sizes that goes from nanometers to meters or even dozen of meters. The nanopores and micropores might play an important role in the pores connectivity of carbonate rocks. X-ray computed tomography (CT) has been widely usedmore » to analyze petrophysical parameters in recent years. This technique has the capability to generate 2D images of the samples' inner structure and also allows the 3D reconstruction of the actual analyzed volume. CT is a powerful technique, but its results depend on the spatial resolution of the generated image. Spatial resolution is a measurement parameter that indicates the smallest object that can be detected. There are great difficulties to generate images with nanoscale resolution (nanotomographic images). In this work three carbonate rocks, one dolomite and two limestones (that will be called limestone A and limestone B) were analyzed by nanotomography. The measurements were performed with the SkyScan2011 nanotomograph, operated at 60 kV and 200 μA to measure the dolomite sample and 40 kV and 200 μA to measure the limestone samples. Each sample was measured with a given spatial resolution (270 nm for the dolomite sample, 360 nm for limestone A and 450 nm for limestone B). The achieved results for total porosity were: 3.09 % for dolomite, 0.65% for limestone A and 3.74% for limestone B. This paper reports the difficulties to acquire nanotomographic images and further analysis about the samples' pore sizes.« less

Geologic Controls of Hydrocarbon Occurrence in the Southern Appalachian Basin in Eastern Tennessee, Southwestern Virginia, Eastern Kentucky, and Southern West Virginia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Robert D. Hatcher

2003-05-31

This report summarizes the first-year accomplishments of a three-year program to investigate the geologic controls of hydrocarbon occurrence in the southern Appalachian basin in eastern Tennessee, southwestern Virginia, eastern Kentucky, and southern West Virginia. The project: (1) employs the petroleum system approach to understand the geologic controls of hydrocarbons; (2) attempts to characterize the T-P parameters driving petroleum evolution; (3) attempts to obtain more quantitative definitions of reservoir architecture and identify new traps; (4) is working with USGS and industry partners to develop new play concepts and geophysical log standards for subsurface correlation; and (5) is geochemically characterizing the hydrocarbonsmore » (cooperatively with USGS). First-year results include: (1) meeting specific milestones (determination of thrust movement vectors, fracture analysis, and communicating results at professional meetings and through publication). All milestones were met. Movement vectors for Valley and Ridge thrusts were confirmed to be west-directed and derived from pushing by the Blue Ridge thrust sheet, and fan about the Tennessee salient. Fracture systems developed during Paleozoic, Mesozoic, and Cenozoic to Holocene compressional and extensional tectonic events, and are more intense near faults. Presentations of first-year results were made at the Tennessee Oil and Gas Association meeting (invited) in June, 2003, at a workshop in August 2003 on geophysical logs in Ordovician rocks, and at the Eastern Section AAPG meeting in September 2003. Papers on thrust tectonics and a major prospect discovered during the first year are in press in an AAPG Memoir and published in the July 28, 2003, issue of the Oil and Gas Journal. (2) collaboration with industry and USGS partners. Several Middle Ordovician black shale samples were sent to USGS for organic carbon analysis. Mississippian and Middle Ordovician rock samples were collected by John Repetski (USGS) and RDH for conodont alteration index determination to better define regional P-T conditions. Efforts are being made to calibrate and standardize geophysical log correlation, seismic reflection data, and Ordovician lithologic signatures to better resolve subsurface stratigraphy and structure beneath the poorly explored Plateau in Tennessee and southern Kentucky. We held a successful workshop on Ordovician rocks geophysical log correlation August 7, 2003 that was cosponsored by the Appalachian PTTC, the Kentucky and Tennessee geological surveys, the Tennessee Oil and Gas Association, and small independents. Detailed field structural and stratigraphic mapping of a transect across part of the Ordovician clastic wedge in Tennessee was begun in January 2003 to assist in 3-D reconstruction of part of the southern Appalachian basin and better assess the nature of a major potential source rock assemblage. (3) Laying the groundwork through (1) and (2) to understand reservoir architecture, the petroleum systems, ancient fluid migration, and conduct 3-D analysis of the southern Appalachian basin.« less

Tectonic evolution, structural styles, and oil habitat in Campeche Sound, Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Angeles-Aquino, F.J.; Reyes-Nunez, J.; Quezada-Muneton, J.M.

1994-12-31

Campeche Sound is located in the southern part of the Gulf of Mexico. This area is Mexico`s most important petroleum province. The Mesozoic section includes Callovian salt deposits; Upper Jurassic sandstones, anhydrites, limestones, and shales; and Cretaceous limestones, dolomites, shales, and carbonate breccias. The Cenozoic section is formed by bentonitic shales and minor sandstones and carbonate breccias. Campeche Sound has been affected by three episodes of deformation: first extensional tectonism, then compressional tectonism, and finally extensional tectonism again. The first period of deformation extended from the middle Jurassic to late Jurassic and is related to the opening of the Gulfmore » of Mexico. During this regime, tilted block faults trending northwest-southwest were dominant. The subsequent compressional regime occurred during the middle Miocene, and it was related to northeast tangential stresses that induced further flow of Callovian salt and gave rise to large faulted, and commonly overturned, anticlines. The last extensional regime lasted throughout the middle and late Miocene, and it is related to salt tectonics and growth faults that have a middle Miocene shaly horizon as the main detachment surface. The main source rocks are Tithonian shales and shaly limestones. Oolite bars, slope and shelf carbonates, and regressive sandstones form the main reservoirs. Evaporites and shales are the regional seals. Recent information indicates that Oxfordian shaly limestones are also important source rocks.« less

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mann, U.; Stein, R.

A 290-m-thick middle Cretaceous black shale sequence in the upper Magdalena Valley, a present-day intramontane basin located between the Central and Eastern cordilleras of Colombia, was investigated with organic-geochemical and microscopic analyses. As a result of the investigation, we were able to (1) differentiate four organic facies types, (2) estimate their source rock potential, and (3) integrated these facies into a sequence stratigraphic framework. The four organic facies types were type C, BC, B, and D. Type C contains a district terrigenous organic matter component in lowstand or highstand deposits. Organic facies type BC is characterized by an increase andmore » a better preservation of marine organic matter. BC belongs to the lower part of the transgressive systems tract. Sediments of organic facies type B have the highest amount of marine organic matter due to excellent preservation under anoxic conditions. The absence of bioturbation and the enrichment of trace metals are further implications for deposition under anoxic conditions. Facies type B is found in the upper part of the transgressive systems tract and contains the best petroleum source rock potential. Facies B occurrence coincides with sea level highstand and correlates especially with a maximum flooding in northern South America during the Turonian. Organic facies type D is also related to highstand deposits, but shows a high rate of reworking and degradation of organic matter.« less

77 FR 64272 - Endangered and Threatened Wildlife and Plants; Proposed Revision of Critical Habitat for the...

Federal Register 2010, 2011, 2012, 2013, 2014

2012-10-19

.... (2008) found Peck's cave amphipod in gravel, rocks, and organic debris (leaves, roots, wood) immediately..., fertilizer nutrients, petroleum hydrocarbons, and semivolatile compounds such as industrial cleaning agents...; stormwater drainage pollutants including soaps, detergents, pharmaceuticals, heavy metals, fertilizer...

Petroleum system elements within the Late Cretaceous and Early Paleogene sediments of Nigeria's inland basins: An integrated sequence stratigraphic approach

NASA Astrophysics Data System (ADS)

Dim, Chidozie Izuchukwu Princeton; Onuoha, K. Mosto; Okeugo, Chukwudike Gabriel; Ozumba, Bertram Maduka

2017-06-01

Sequence stratigraphic studies have been carried out using subsurface well and 2D seismic data in the Late Cretaceous and Early Paleogene sediments of Anambra and proximal onshore section of Niger Delta Basin in the Southeastern Nigeria. The aim was to establish the stratigraphic framework for better understanding of the reservoir, source and seal rock presence and distribution in the basin. Thirteen stratigraphic bounding surfaces (consisting of six maximum flooding surfaces - MFSs and seven sequence boundaries - SBs) were recognized and calibrated using a newly modified chronostratigraphic chart. Stratigraphic surfaces were matched with corresponding foraminiferal and palynological biozones, aiding correlation across wells in this study. Well log sequence stratigraphic correlation reveals that stratal packages within the basin are segmented into six depositional sequences occurring from Late Cretaceous to Early Paleogene age. Generated gross depositional environment maps at various MFSs show that sediment packages deposited within shelfal to deep marine settings, reflect continuous rise and fall of sea levels within a regressive cycle. Each of these sequences consist of three system tracts (lowstand system tract - LST, transgressive system tract - TST and highstand system tract - HST) that are associated with mainly progradational and retrogradational sediment stacking patterns. Well correlation reveals that the sand and shale units of the LSTs, HSTs and TSTs, that constitute the reservoir and source/seal packages respectively are laterally continuous and thicken basinwards, due to structural influences. Result from interpretation of seismic section reveals the presence of hanging wall, footwall, horst block and collapsed crest structures. These structural features generally aid migration and offer entrapment mechanism for hydrocarbon accumulation. The combination of these reservoirs, sources, seals and trap elements form a good petroleum system that is viable for hydrocarbon exploration and development.

Source Test Report for the 205 Delayed Coking Unit Drum 205-1201 and Drum 205-1202 Depressurization Vents (Marathon Petroleum Company LLC)

EPA Pesticide Factsheets

The 2010 Source Test was performed during the atmospheric depressurization step of the delayed coking process prior to the removal of petroleum coke from the coke drum. The 205 DCU was operated under a variety of conditions during the 2010 Source Test.

Impact of Acid Attack on the Shear Behaviour of a Carbonate Rock Joint

NASA Astrophysics Data System (ADS)

Nouailletas, O.; Perlot, C.; Rivard, P.; Ballivy, G.; La Borderie, C.

2017-06-01

The mechanical behaviour of structural discontinuities in rock mass is a key element of the stability analysis in civil engineering, petroleum engineering and mining engineering. In this paper, the mechanical analysis is coupled with the acidic attack of a rock joint associated with leakage of CO2 through a geological fault in the context of carbon sequestration. Experiments were conducted at the laboratory scale to assess the shear behaviour of degraded joint: direct shear tests were performed on rock joints that have been previously immersed into water or into an acidic solution (pH 0.2). The shear behaviour of joints is governed by the roughness of its walls: the parameters Z2, Z3, Z4 and RL characterize the rough surfaces. They are calculated from the scans of joint surfaces after and before immersion. Their comparison pointed out a slight impact of the acidic attack. However, the results of the direct shear tests show significant modifications in the shear behaviour for the degraded joints: the tangential stress peak disappears, the tangential stiffness decreases in the stress/displacement curve, and the contraction increases, the dilation angle decreases in the dilation curve. Acid attack has a greater impact on the mechanical properties of the asperities than their geometric characteristics. The results of this study will be used to improve chemo-mechanical modelling to better simulate with higher accuracy the fault stability in different cases of civil engineering, petroleum engineering and mining engineering.

Earth observations taken by the Expedition 14 crew

NASA Image and Video Library

2006-10-30

ISS014-E-06812 (30 Oct. 2006) --- Gibraltar Bay, located near the southernmost tip of the Iberian Peninsula in the western Mediterranean Sea, is featured in this image photographed by an Expedition 14 crewmember on the International Space Station. According to scientists, the famous Rock of Gibraltar that forms the northeastern border of the Bay is formed of Jurassic seafloor sediments that were lithified to form limestone (a rock formed predominantly of the mineral calcite) and subsequently uplifted as a result of collision of the African and Eurasian tectonic plates. The cities of La Linea and Algeciras bordering the Bay -- together with petroleum-processing facilities along the northern Bay shoreline -- are part of Spain, whereas the city of Gibraltar itself (to the west of and including the Rock) is under the jurisdiction of the United Kingdom. The protected waters of the Bay and its proximity to Africa and the Strait of Gibraltar as the gateway between the Atlantic and Mediterranean contribute to the region's past and current strategic and economic importance. Numerous ships and several ship wakes are visible within the Bay; the majority of these are freighters and cargo tankers accessing the petroleum facilities. Ships nearer to the Rock are more likely cruise ships, as Gibraltar is a popular destination for tourists. Partial sunglint within the Bay highlights surface water roughened by winds funneled into the Bay by the surrounding highlands -- one such area is visible directly to the west of La Linea.

Generation and migration of petroleum in the Mahakam delta, Indonesia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Durand, B.; Bessereau, G.; Doligez, B.

1988-08-01

The Mahakam delta, located east of Kalimantan, Indonesia, contains sediments of Miocene-Pliocene age. Their thickness may reach more than 8,000 m in places, and sections which have been drilled are generally overpressured below 3,000 to 4,000 m. Petroleum was formed essentially from a kerogen originating in terrestrial land plants grown in an equatorial climate. The kerogen may occur either dispersed in clays or concentrated in humic coal beds. Petroleum potential (oil and gas) of this kerogen at the beginning of catagenesis is 200-250 mg HC/g organic carbon on the average (as measured by Rock-Eval pyrolysis) but is highly variable aroundmore » this mean value (100-400 mg HC/g organic carbon approximately). Although the kerogen is of terrestrial origin, the kerogen-containing sediments have the capacity to produce and expel oil at depth, as shown by large quantities of oil pooled in sandy reservoirs together with gas in a relatively small area. Depth of top oil kitchen varies from 2,500 to 4,000 m and is greater in synclines than on top of structures. Present isotherms follow more or less the same pattern. Migration is very recent and is till at work. Light hydrocarbons have migrated farther from their source than heavy ones did. Thus condensate in pooled gas and the density of pooled oil tend to increase with depth. These variations of oil and gas compositions along secondary and tertiary migration routes are likely to be provoked by evaporative fractionation processes.« less

A brief history of oil and gas exploration in the southern San Joaquin Valley of California: Chapter 3 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

USGS Publications Warehouse

Takahashi, Kenneth I.; Gautier, Donald L.

2007-01-01

The Golden State got its nickname from the Sierra Nevada gold that lured so many miners and settlers to the West, but California has earned much more wealth from so-called “black gold” than from metallic gold. The San Joaquin Valley has been the principal source for most of the petroleum produced in the State during the past 145 years. In attempting to assess future additions to petroleum reserves in a mature province such as the San Joaquin Basin, it helps to be mindful of the history of resource development. In this chapter we present a brief overview of the long and colorful history of petroleum exploration and development in the San Joaquin Valley. This chapter relies heavily upon the work of William Rintoul, who wrote extensively on the history of oil and gas exploration in California and especially in the San Joaquin Valley. No report on the history of oil and gas exploration in the San Joaquin Valley would be possible without heavily referencing his publications. We also made use of publications by Susan Hodgson and a U.S. Geological Survey Web site, Natural Oil and Gas Seeps in California (http://seeps.wr.usgs.gov/seeps/index.html), for much of the material describing the use of petroleum by Native Americans in the San Joaquin Valley. Finally, we wish to acknowledge the contribution of Don Arnot, who manages the photograph collection at the West Kern Oil Museum in Taft, California. The collection consists of more than 10,000 photographs that have been scanned and preserved in digital form on CD-ROM. Many of the historical photographs used in this paper are from that collection. Finally, to clarify our terminology, we use the term “San Joaquin Valley” when we refer to the geographical or topographical feature and the term “San Joaquin Basin” when we refer to geological province and the rocks therein.

Chemistry and origin of Miocene and Eocene oils and tars in the onshore and offshore Santa Cruz Basins, California

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kornacki, A.S.; McNeil, R.I.

1996-12-31

The Santa Cruz (La Honda) Basin is a small {open_quote}slice{close_quote} of the San Joaquin Basin that has been displaced c. 300 km to the northwest by the San Andreas Fault. The poorly-explored offshore area that now lies within the Monterey Bay NMS includes portions of the Outer Santa Cruz and Bodega basins. A modest amount (c. 1.3 MM bbl) of variable-quality oil has been produced from Eocene and Pliocene pay zones in the La Honda Field. Much smaller amounts of light oil ({ge}40{degrees} API) have been produced from three other fields (Oil Creek; Moody Gulch; Half Moon Bay). Large tarmore » deposits also outcrop near the city of Santa Cruz. Proven source rocks in this basin include the Eocene Twobar Shale and three Miocene units: the Lambert Shale, Monterey Formation, and the Santa Cruz Mudstone. A high-gravity oil sample from the Oil Creek Field contains isotopically-light carbon ({delta}{sup 13}C = - 28.2 per mil) and has a relatively high pristane/phytane ratio. This oil was generated at high temperature (c. 140{degrees}C) by pre-Miocene source rocks (probably the Twobar Shale). The presence of isotopically-heavy carbon in all other oil and tar samples demonstrates they were generated by Miocene source rocks. But the C{sub 7} oil-generation temperatures, sulfur content, vanadium/nickel ratios, and biomarker chemistry of these Miocene oils are significantly different than in Monterey oils from the prolific Santa Maria Basin (SMB). The sulfur content (8.0 wt%) and V-Ni chemistry of tarry petroleum recovered in the P-036-1 well (Outer Santa Cruz Basin) resembles the chemistry of very heavy (<15{degrees}API) oils generated by phosphatic Monterey shales in the SMB.« less

Chemistry and origin of Miocene and Eocene oils and tars in the onshore and offshore Santa Cruz Basins, California

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kornacki, A.S.; McNeil, R.I.

1996-01-01

The Santa Cruz (La Honda) Basin is a small [open quote]slice[close quote] of the San Joaquin Basin that has been displaced c. 300 km to the northwest by the San Andreas Fault. The poorly-explored offshore area that now lies within the Monterey Bay NMS includes portions of the Outer Santa Cruz and Bodega basins. A modest amount (c. 1.3 MM bbl) of variable-quality oil has been produced from Eocene and Pliocene pay zones in the La Honda Field. Much smaller amounts of light oil ([ge]40[degrees] API) have been produced from three other fields (Oil Creek; Moody Gulch; Half Moon Bay).more » Large tar deposits also outcrop near the city of Santa Cruz. Proven source rocks in this basin include the Eocene Twobar Shale and three Miocene units: the Lambert Shale, Monterey Formation, and the Santa Cruz Mudstone. A high-gravity oil sample from the Oil Creek Field contains isotopically-light carbon ([delta][sup 13]C = - 28.2 per mil) and has a relatively high pristane/phytane ratio. This oil was generated at high temperature (c. 140[degrees]C) by pre-Miocene source rocks (probably the Twobar Shale). The presence of isotopically-heavy carbon in all other oil and tar samples demonstrates they were generated by Miocene source rocks. But the C[sub 7] oil-generation temperatures, sulfur content, vanadium/nickel ratios, and biomarker chemistry of these Miocene oils are significantly different than in Monterey oils from the prolific Santa Maria Basin (SMB). The sulfur content (8.0 wt%) and V-Ni chemistry of tarry petroleum recovered in the P-036-1 well (Outer Santa Cruz Basin) resembles the chemistry of very heavy (<15[degrees]API) oils generated by phosphatic Monterey shales in the SMB.« less

10 CFR 503.38 - Permanent exemption for certain fuel mixtures containing natural gas or petroleum.

Code of Federal Regulations, 2010 CFR

2010-01-01

... natural gas or petroleum. 503.38 Section 503.38 Energy DEPARTMENT OF ENERGY (CONTINUED) ALTERNATE FUELS... mixtures containing natural gas or petroleum. (a) Eligibility. Section 212(d) of the Act provides for a... proposes to use a mixture of natural gas or petroleum and an alternate fuel as a primary energy source; (2...

Do your extractable TPH concentrations represent dissolved petroleum? An update on applied research

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zemo, D.A.

1997-12-31

Elevated concentrations of {open_quotes}dissolved-phase{close_quotes} extractable total petroleum hydrocarbons (TPH) in groundwater samples can be a significant impediment to site closure in states that regulate groundwater using TPH criteria. These analytical results are inconsistent with petroleum chemistry because of the relatively low water solubility of petroleum products. This paper presents an update of our research into the source of medium- to high-boiling TPH detections in groundwater samples and application of the results to multiple projects. This work follows from a 1995 publication in which positive interferences to the Method 8015M (GC-FID) TPH measurement by soluble, non-petroleum hydrocarbons resulting from intrinsic bioremediationmore » or non-dissolved petroleum adhered to particulates was described. The 1995 paper was largely theoretical and focused on one case study. Since 1995, we have evaluated the source of TPH detections in groundwater at numerous petroleum sites and have demonstrated the significance of interferences to the Method 8015M measurement to the California regulatory community. Our work has shown conclusively that elevated concentrations of extractable TPH are not representative of dissolved petroleum constituents. We have shown that a sample cleanup prior to analysis using silica gel cleanup (to remove polar non-petroleum hydrocarbons) and/or laboratory filtration (to reduce petroleum-affected particulates) is required to overcome the false positives caused by interferences to the Method 8015M measurement.« less

Identifying the source of petroleum pollution in sediment cores of southwest of the Caspian Sea using chemical fingerprinting of aliphatic and alicyclic hydrocarbons.

PubMed

Shirneshan, Golshan; Bakhtiari, Alireza Riyahi; Memariani, Mahmoud

2017-02-15

In this study, the concentration and sources of aliphatic and petroleum markers were investigated in 105 samples of Anzali, Rezvanshahr and Astara cores from the southwest of Caspian Sea. Petroleum importation was diagnosed as a main source in most depths of cores by the results of unresolved complex mixture, carbon preference index and hopanes and steranes. From the chemical diagnostic parameters, petroleum inputs in sediment of cores were determined to be different during years and the sources of hydrocarbons in some sections differed than Anzali and Turkmenistan and Azerbaijan oils. Diagenic ratios in most sediments of upper and middle sections in Astara core were determined to be highly similar to those of Azerbaijan oil, while the presence of Turkmenistan and Anzali oils were detected in a few sections of Anzali and Rezvanshahr cores and only five layers of downer section in Anzali core, respectively. Copyright © 2016. Published by Elsevier Ltd.

Occurrence, source and ecological assessment of baseline hydrocarbons in the intertidal marine sediments along the shoreline of Douglas Channel to Hecate Strait in British Columbia.

PubMed

Yang, Zeyu; Hollebone, Bruce P; Laforest, Sonia; Lambert, Patrick; Brown, Carl E; Yang, Chun; Shah, Keval; Landriault, Mike; Goldthorp, Michael

2017-09-15

The occurrence, source and ecological assessment of baseline hydrocarbons in the intertidal zone along the northern British shoreline were evaluated based on analyzing total petroleum hydrocarbons (TPH), n-alkanes, petroleum related biomarkers such as terpanes and steranes, and polycyclic aromatic hydrocarbons (PAHs) including non-alkylated and alkylated homologues (APAHs). The TPH levels, n-alkanes, petroleum biomarkers and PAHs in all the sampling sites, except for Masset Harbor/York Point at Gil Island were low, without obvious unresolved complex mixture (UCM) and petroleum contamination input. Specifically, n-alkanes showed a major terrestrial plants input; PAHs with abundant non-alkylated PAHs but minor APAHs showed a major pyrogenic input. However, obvious petroleum-derived hydrocarbons have impacted Masset Harbor. A historical petroleum input was found in York Point at Gil Island, due to the presence of the low level of petroleum biomarkers. Ecological assessment of 13 non-alkylated PAHs in Masset Harbor indicated no potential toxicity to the benthic organisms. Copyright © 2017 Elsevier Ltd. All rights reserved.

Experimental measurements of seismic attenuation in microfracture sedimentary rock

DOE Office of Scientific and Technical Information (OSTI.GOV)

Peacock, S.; McCann, C.; Sothcott, J.

1994-09-01

In a previous paper (Peacock et al., 1994), the authors related ultrasonic velocities in water-saturated Carrara Marble to crack densities in polished sections to verify Hudson's (1980, 1981, 1986) theory for velocities in cracked rock. They describe the empirical relationships between attenuation and crack density that they established during these experiments in the hope of clarifying the mechanism of attenuation in rocks with fluid-filled cracks. Relating seismic velocity and attenuation to crack density is important in predicting the productivity of fractured petroleum reservoirs such as the North Sea Brent Field. It also allows cracks to be used as stress indicatorsmore » throughout the shallow crust (Crampin and Lovell, 1991).« less

Geologic information from satellite images

NASA Technical Reports Server (NTRS)

Lee, K.; Knepper, D. H.; Sawatzky, D. L.

1974-01-01

Extracting geologic information from ERTS and Skylab/EREP images is best done by a geologist trained in photo-interpretation. The information is at a regional scale, and three basic types are available: rock and soil, geologic structures, and landforms. Discrimination between alluvium and sedimentary or crystalline bedrock, and between units in thick sedimentary sequences is best, primarily because of topographic expression and vegetation differences. Discrimination between crystalline rock types is poor. Folds and fractures are the best displayed geologic features. They are recognizable by topographic expression, drainage patterns, and rock or vegetation tonal patterns. Landforms are easily discriminated by their familiar shapes and patterns. Several examples demonstrate the applicability of satellite images to tectonic analysis and petroleum and mineral exploration.

Geological studies of the COST GE-1 well, United States South Atlantic outer continental shelf area

USGS Publications Warehouse

Scholle, Peter A.

1979-01-01

The COST No. GE-1 well is the first deep stratigraphic test to be drilled in the southern part of the U.S. Atlantic Outer Continental Shelf (AOCS) area. The well was drilled within the Southeast Georgia Embayment to a total depth of 13,254 ft (4,040 m). It penetrated a section composed largely of chalky limestones to a depth of about 3,300 ft (1,000 m) below the drill platform. Limestones and calcareous shales with some dolomite predominate between 3,300 and 7,200 ft (1,000 and 2,200 m), whereas interbedded sandstones and shales are dominant from 7,200 to 11,000 ft (2,200 to 3,350 m). From 11,000 ft (3,350 m) to the bottom, the section consists of highly indurated to weakly metamorphosed pelitic sedimentary rocks and meta-igneous flows or intrusives. Biostratigraphic examination has shown that the section down to approximately 3,500 ft (1,060 m) is Tertiary, the interval from 3,500 to 5,900 ft (1,060 to 1,800 m) is Upper Cretaceous, and the section from 5,900 to 11,000 ft (1,800 to 3,350 m) is apparently Lower Cretaceous. The indurated to weakly metamorphosed section below 11,000 ft (3,350 m) is barren of fauna or flora but is presumed to be Paleozoic based on radiometric age determinations. Rocks deposited at upper-slope water depths were encountered in the Upper Cretaceous, Oligocene, and Miocene parts of the section. All other units were deposited in outer-shelf to terrestrial environments. Examination of cores, well cuttings, and electric logs shows that potential hydrocarbon-reservoir units are present within the chalks in the uppermost part of the section as well as in sandstone beds to a depth of at least 10,000 ft (3,000 m). Sandstones below that depth, and the metamorphic section between 11,000 and 13.250 ft (3,350 and 4,040 m) have extremely low permeabilities and are unlikely to contain potential reservoir rock. Studies of organic geochemistry, vitrinite reflectance, and color alteration of visible organic matter indicate that the chalk section down to approximately 3,600 ft (1,100 m) contains low concentrations of indigenous hydrocarbons, is thermally immature, and has a very poor source-rock potential. The interval from 3,600 to 5,900 ft (1,100 to 1,800 m) has a high content of marine organic matter but appears to be thermally immature. Where buried more deeply, this interval may have significant potential as an oil source. The section from 5,900 to 8,850 ft (1,800 to 2,700 m) has geochemical characteristics indicative of a poor oil source rock and is thermally immature. Rocks below this depth, although they may be marginally to fully mature, are virtually barren of organic matter and thus have little or no source-rock potential. Therefore, despite the thermal immaturity of the overall section, the uppor half of the sedimentary section penetrated in the well shows the greatest petroleum source potential.

10 CFR 504.8 - Prohibitions against excessive use of petroleum or natural gas in mixtures-certifying powerplants.

Code of Federal Regulations, 2013 CFR

2013-01-01

... primary energy source. In assessing whether the unit is technically capable of using a mixture of petroleum or natural gas and coal or another alternate fuel as a primary energy source, for purposes of this... technically capable of using the mixture as a primary energy source under § 504.6(c), this certification...

10 CFR 504.8 - Prohibitions against excessive use of petroleum or natural gas in mixtures-certifying powerplants.

Code of Federal Regulations, 2014 CFR

2014-01-01

... primary energy source. In assessing whether the unit is technically capable of using a mixture of petroleum or natural gas and coal or another alternate fuel as a primary energy source, for purposes of this... technically capable of using the mixture as a primary energy source under § 504.6(c), this certification...

10 CFR 504.8 - Prohibitions against excessive use of petroleum or natural gas in mixtures-certifying powerplants.

Code of Federal Regulations, 2012 CFR

2012-01-01

... primary energy source. In assessing whether the unit is technically capable of using a mixture of petroleum or natural gas and coal or another alternate fuel as a primary energy source, for purposes of this... technically capable of using the mixture as a primary energy source under § 504.6(c), this certification...

Geology and total petroleum systems of the Gulf of Guinea province of West Africa

USGS Publications Warehouse

Brownfield, Michael E.; Charpentier, Ronald R.

2006-01-01

The Gulf of Guinea Province as defined by the U.S. Geological Survey (USGS) consists of the coastal and offshore areas of Cote d'Ivoire, Ghana, Togo, and Benin, and the western part of the coast of Nigeria, from the Liberian border east to the west edge of the Niger Delta. The province includes the Ivory Coast, Tano, Central, Saltpond, Keta, and Benin Basins and the Dahomey Embayment. The area has had relatively little hydrocarbon exploration since 1968, with only 33 small to moderate-sized oil and gas fields having been discovered prior to the USGS assessment. Most discoveries to 1995 have been located in water depths less than 500 m. Since 1995, only eight new offshore discoveries have been made, with four of the discoveries in the deep-water area of the province. Although as many as five total petroleum systems exist in the Gulf of Guinea Province, only one, the Cretaceous Composite Total Petroleum System, and its assessment unit, the Coastal Plain and Offshore Assessment Unit, had sufficient data to allow assessment. The province shows two important differences compared to the passive-margin basins south of the Niger Delta: (1) the influence of transform tectonics, and (2) the absence of evaporites and salt deformation. The province also lacks long-lived, large deltaic systems that typically result in rapid source rock burial and abundant high-quality hydrocarbon reservoirs. The USGS assessed the potential for undiscovered conventional oil and gas resources in the Gulf of Guinea Province as part of its World Petroleum Assessment 2000, estimating a mean of 1,004 million barrels of conventional undiscovered oil, 10,071 billion cubic feet of gas, and 282 million barrels of natural gas liquids. Most of the hydrocarbon potential is postulated to be in the offshore, deeper waters of the province. Gas resources may be large, as well as accessible, in areas where the zone of hydrocarbon generation is relatively shallow.

48 CFR 908.7109 - Fuels and packaged petroleum products.

Code of Federal Regulations, 2010 CFR

2010-10-01

... petroleum products. 908.7109 Section 908.7109 Federal Acquisition Regulations System DEPARTMENT OF ENERGY COMPETITION ACQUISITION PLANNING REQUIRED SOURCES OF SUPPLIES AND SERVICES Acquisition of Special Items 908... with 951, to acquire such products from Defense sources, they shall do so in accordance with FPMR 41...

Final Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards (NSPS) Fact Sheets

EPA Pesticide Factsheets

This page contains 3 September 2015 fact sheets with information regarding the final residual risk and technology review for the petroleum refinery source categories. The fact sheets provide an overview, a summary of changes, effects for the community.

Seismic definition of Lower Cretaceous delta, south Whale subbasin, offshore Newfoundland

DOE Office of Scientific and Technical Information (OSTI.GOV)

Jayasinghe, N.R.; Stokes, R.E.

1986-05-01

Recognition of stratigraphic traps in areas where previous prospects were structural is a trend attributable partly to the availability of new, high-quality seismic data. In the South Whale subbasin, offshore Newfoundland, Canada, such a change in exploration philosophy is presently being evaluated. Exploratory drilling offshore eastern Canada began in 1966 in the South Whale subbasin. By the end of 1973, 13 wells were drilled in this subbasin; however, lack of success discouraged further drilling. These wells evaluated large, salt-related structures, well defined by seismic data. Although an adequate reservoir was encountered in a number of these wells, faulting associated withmore » halokinesis may have resulted in petroleum migration out of the reservoir. Interpretation of recently acquired high-quality seismic data indicate a delta in the Lower Cretaceous Missisauga Formation in the study area. Seismic dip sections across the delta show a shingled progradation pattern suggesting a wave-dominated depositional environment. The delta comprises approximately 400 km/sup 2/, with closure in the eastern half. Data from wells in the area indicate that adequate source and sealing beds could be present. Furthermore, rocks of similar age in the nearby Avalon basin contain significant petroleum accumulations, the most notable being within the Hibernia oil field.« less

Source facies and oil families of the Malay Basin, Malaysia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Creaney, S.; Hussein, A.H.; Curry, D.J.

1994-07-01

The Malay Basin consists of a number of separate petroleum systems, driven exclusively by nonmarine source rocks. These systems range from lower Oligocene to middle Miocene and show a progression from lacustrine-dominated source facies in the lower Oligocene to lower Miocene section to coastal plain/delta plain coal-related sources in the lower to middle Miocene section. Two lacustrine sources are recognized in the older section, and multiple source/reservoir pairs are recognized in the younger coaly section. The lacustrine sources can be recognized using well-log analysis combined with detailed core and sidewall core sampling. Chemically, they are characterized by low pristane/phytane ratios,more » low oleanane contents, and a general absence of resin-derived terpanes. These sources have TOCs in the 1.0-4.0% range and hydrogen indices of up to 750. In contrast, the coal-related sources are chemically distinct with pristane/phytane ratios of up to 8, very high oleanane contents, and often abundant resinous compounds. All these sources are generally overmature in the basin center and immature toward the basin margin. The oils sourced from all sources in the Malay Basin are generally low in sulfur and of very high economic value. Detailed biomarker analysis of the oils in the Malay Basin has allowed the recognition of families associated with the above sources and demonstrated that oil migration has been largely strata parallel with little cross-stratal mixing of families.« less

Biological treatment process for removing petroleum hydrocarbons from oil field produced waters

DOE Office of Scientific and Technical Information (OSTI.GOV)

Tellez, G.; Khandan, N.

1995-12-31

The feasibility of removing petroleum hydrocarbons from oil fields produced waters using biological treatment was evaluated under laboratory and field conditions. Based on previous laboratory studies, a field-scale prototype system was designed and operated over a period of four months. Two different sources of produced waters were tested in this field study under various continuous flow rates ranging from 375 1/D to 1,800 1/D. One source of produced water was an open storage pit; the other, a closed storage tank. The TDS concentrations of these sources exceeded 50,000 mg/l; total n-alkanes exceeded 100 mg/l; total petroleum hydrocarbons exceeded 125 mg/l;more » and total BTEX exceeded 3 mg/l. Removals of total n-alkanes, total petroleum hydrocarbons, and BTEX remained consistently high over 99%. During these tests, the energy costs averaged $0.20/bbl at 12 bbl/D.« less

Uptake and trans-membrane transport of petroleum hydrocarbons by microorganisms

PubMed Central

Hua, Fei; Wang, Hong Qi

2014-01-01

Petroleum-based products are a primary energy source in the industry and daily life. During the exploration, processing, transport and storage of petroleum and petroleum products, water or soil pollution occurs regularly. Biodegradation of the hydrocarbon pollutants by indigenous microorganisms is one of the primary mechanisms of removal of petroleum compounds from the environment. However, the physical contact between microorganisms and hydrophobic hydrocarbons limits the biodegradation rate. This paper presents an updated review of the petroleum hydrocarbon uptake and transport across the outer membrane of microorganisms with the help of outer membrane proteins. PMID:26740752

Transition metal catalysis in the generation of petroleum and natural gas. Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mango, F.D.

1997-01-21

This project originated on the premise that natural gas could be formed catalytically in the earth rather than thermally as commonly believed. The intention was to test this hypothetical view and to explore generally the role of sedimentary metals in the generation of light hydrocarbons (C1 - C9). We showed the metalliferous source rocks are indeed catalytic in the generation of natural gas. Various metal compounds in the pure state show the same levels of catalytic activity as sedimentary rocks and the products are identical. Nickel is particularly active among the early transition metals and is projected to remain catalyticallymore » robust at all stages of catagenesis. Nickel oxide promotes the formation of n-alkanes in addition to natural gas (NG), demonstrating the full scope of the hypothetical catalytic process: The composition of catalytic gas duplicates the entire range of natural gas, from so-called wet gas to dry gas (60 to 95+ wt % methane), while gas generated thermally is consistently depleted in methane (10 to 60 wt % methane). These results support the view that metal catalysis is a major pathway through which natural gas is formed in the earth.« less

Transition metal catalysis in the generation of petroleum and natural gas. Final report, September 1, 1992--October 31, 1995

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mango, F.D.

1997-01-21

This project originated on the premise that natural gas could be formed catalytically in the earth rather than thermally as commonly believed. The intention was to test this hypothetical view and to explore generally the role of sedimentary metals in the generation of light hydrocarbons (C1 - C9). We showed the metalliferous source rocks are indeed catalytic in the generation of natural gas. Various metal compounds in the pure state show the same levels of catalytic activity as sedimentary rocks and the products are identical. Nickel is particularly active among the early transition metals and is projected to remain catalyticallymore » robust at all stages of catagenesis. Nickel oxide promotes the formation of n-alkanes in addition to natural gas (NG), demonstrating the full scope of the hypothetical catalytic process. The composition of catalytic gas duplicates the entire range of natural gas, from so-called wet gas to dry gas (60 to 95+ wt % methane), while gas generated thermally is consistently depleted in methane (10 to 60 wt % methane). These results support the view that metal catalysis is a major pathway through which natural gas is formed in the earth.« less

40 CFR 60.111 - Definitions.

Code of Federal Regulations, 2013 CFR

2013-07-01

... petroleum liquid being contained, and is equipped with a closure seal or seals to close the space between... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for... container used for the storage of petroleum liquids, but does not include: (1) Pressure vessels which are...

40 CFR 60.111 - Definitions.

Code of Federal Regulations, 2010 CFR

2010-07-01

... petroleum liquid being contained, and is equipped with a closure seal or seals to close the space between... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for... container used for the storage of petroleum liquids, but does not include: (1) Pressure vessels which are...

40 CFR 60.111 - Definitions.

Code of Federal Regulations, 2011 CFR

2011-07-01

... petroleum liquid being contained, and is equipped with a closure seal or seals to close the space between... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for... container used for the storage of petroleum liquids, but does not include: (1) Pressure vessels which are...

40 CFR 60.111 - Definitions.

Code of Federal Regulations, 2014 CFR

2014-07-01

... petroleum liquid being contained, and is equipped with a closure seal or seals to close the space between... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for... container used for the storage of petroleum liquids, but does not include: (1) Pressure vessels which are...

40 CFR 60.111 - Definitions.

Code of Federal Regulations, 2012 CFR

2012-07-01

... petroleum liquid being contained, and is equipped with a closure seal or seals to close the space between... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for... container used for the storage of petroleum liquids, but does not include: (1) Pressure vessels which are...

10 CFR 501.51 - Prohibitions by order-electing powerplants.

Code of Federal Regulations, 2012 CFR

2012-01-01

... 501.51 Energy DEPARTMENT OF ENERGY (CONTINUED) ALTERNATE FUELS ADMINISTRATIVE PROCEDURES AND SANCTIONS... order the use of petroleum or natural gas as a primary energy source or in amounts in excess of the... that would prohibit the use of petroleum or natural gas as a primary energy source, the finding...

10 CFR 501.51 - Prohibitions by order-electing powerplants.

Code of Federal Regulations, 2013 CFR

2013-01-01

... 501.51 Energy DEPARTMENT OF ENERGY (CONTINUED) ALTERNATE FUELS ADMINISTRATIVE PROCEDURES AND SANCTIONS... order the use of petroleum or natural gas as a primary energy source or in amounts in excess of the... that would prohibit the use of petroleum or natural gas as a primary energy source, the finding...

10 CFR 501.51 - Prohibitions by order-electing powerplants.

Code of Federal Regulations, 2011 CFR

2011-01-01

... 501.51 Energy DEPARTMENT OF ENERGY (CONTINUED) ALTERNATE FUELS ADMINISTRATIVE PROCEDURES AND SANCTIONS... order the use of petroleum or natural gas as a primary energy source or in amounts in excess of the... that would prohibit the use of petroleum or natural gas as a primary energy source, the finding...

10 CFR 501.51 - Prohibitions by order-electing powerplants.

Code of Federal Regulations, 2014 CFR

2014-01-01

... 501.51 Energy DEPARTMENT OF ENERGY (CONTINUED) ALTERNATE FUELS ADMINISTRATIVE PROCEDURES AND SANCTIONS... order the use of petroleum or natural gas as a primary energy source or in amounts in excess of the... that would prohibit the use of petroleum or natural gas as a primary energy source, the finding...

Emissions of organic carbon and methane from petroleum and dairy operations in California’s San Joaquin Valley

EPA Science Inventory

Petroleum and dairy operations are prominent sources of gas-phase organic compounds in California's San Joaquin Valley. It is essential to understand the emissions and air quality impacts of these relatively understudied sources, especially for oil/gas operations in light of incr...

78 FR 65875 - Approval and Promulgation of Air Quality Implementation Plans; Wisconsin; Removal of Gasoline...

Federal Register 2010, 2011, 2012, 2013, 2014

2013-11-04

...] Approval and Promulgation of Air Quality Implementation Plans; Wisconsin; Removal of Gasoline Vapor... Administrative Code, Chapter NR 420 Control of Organic Compound Emissions from Petroleum and Gasoline Sources... FROM PETROLEUM AND GASOLINE SOURCES. NR 420.01 as published in the (Wisconsin) Register, February, 1990...

Evaluation of a Sustainable Remediation Option: Beneficial Reuse of Petroleum-Contaminated Sediment as an Energy Source

EPA Science Inventory

The characteristics of petroleum-contaminated sediment (PCS) have been evaluated to assess whether the practice of its beneficial reuse as a sole or supplemental energy source is sustainable relative to other sediment remediation options such as monitored natural recovery (MNR), ...

Energy and public health: the challenge of peak petroleum.

PubMed

Frumkin, Howard; Hess, Jeremy; Vindigni, Stephen

2009-01-01

Petroleum is a unique and essential energy source, used as the principal fuel for transportation, in producing many chemicals, and for numerous other purposes. Global petroleum production is expected to reach a maximum in the near future and to decline thereafter, a phenomenon known as "peak petroleum." This article reviews petroleum geology and uses, describes the phenomenon of peak petroleum, and reviews the scientific literature on the timing of this transition. It then discusses how peak petroleum may affect public health and health care, by reference to four areas: medical supplies and equipment, transportation, energy generation, and food production. Finally, it suggests strategies for anticipating and preparing for peak petroleum, both general public health preparedness strategies and actions specific to the four expected health system impacts.

Dinosterane and other steroidal hydrocarbons of dinoflagellate origin in sediments and petroleum

DOE Office of Scientific and Technical Information (OSTI.GOV)

Summons, R.E.; Volkman, J.K.; Boreham, C.J.

1987-11-01

The steroidal alkanes of a selection of sediments and oils have been examined by GC-MS with multiple metastable reaction monitoring. Specific 4-methyl sterane isomers have been identified by comparison with isomers synthesized from sterols isolated from dinoflagellates. An immature marine oil shale and two mature marine oils of Triassic to early Cretaceous age contained high concentrations of C{sub 30} steranes comprising desmethyl, 24-ethyl-4{alpha}-methylcholestane and 4{alpha},23,24-trimethylcholestane (dinosterane) isomers. An immature non-marine oil shale and two non-marine oils of Cretaceous to Eocene age contained stereoisomers of 24-ethyl-4{alpha}-methylcholestane as the dominant C{sub 30} steranes. Reaction monitoring analyses in GC-MS are particularly suited tomore » unravelling complex distributions of homologous and stereoisomeric steroids encountered in oils and their source rocks.« less

Exploration limited since '70s in Libya's Sirte basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Thomas, D.

1995-03-13

Esso Standard made the first Libyan oil discovery in the western Ghadames basin in 1957. The Atshan-2 well tested oil from Devonian sandstones, and the play was a continuation of the Paleozoic trend found productive in the neighboring Edjeleh region of eastern Algeria. Exploration in the Sirte basin began in earnest in 1958. Within the next 10 years, 16 major oil fields had been discovered, each with recoverable reserves greater than 500 million bbl of oil. Libya currently produces under OPEC quota approximately 1.4 million b/d of oil, with discovered in-place reserves of 130 billion bbl of oil. The papermore » describes the structural framework, sedimentary basins of Libya, the Sirte basin, petroleum geology, play types, source rocks, generation and migration of hydrocarbons, oil reserves, potential, and acreage availability.« less

Pore morphology effect in microlog for porosity prediction in a mature field

USGS Publications Warehouse

Teh, W.J.; Willhite, G.P.; Doveton, J.H.; Tsau, J.S.

2011-01-01

In an matured field, developed during the 1950s, no porosity logs were available from sources other than invaded zone resistivity Rxo . The microresistivity porosity is calibrated with the core porosity to yield an accurate estimate of the porosity. However, the procedure of calibrating the porosity with Rxo for a linear regression model may not be predictive without an understanding of the pore types in the reservoir interval. A thorough investigation of the pore types, based on the lithofacies description obtained from the core analysis, and its role in obtaining a good estimate of porosity is demonstrated in the Ogallah field. Therefore, the objective of this paper is to separate the porosity-microlog data into pore-type based zones with characteristic cementation exponents (m) in this multi-petrotype reservoir with a complex mixture of Arbuckle dolomite and sandstone rock. The value of m is critical in making estimates of water saturation. "Rule of thumb" values of cementation might lead to errors in water saturation on either the optimistic or the pessimistic side. The rock types in the Ogallah contain interparticle/intercrystalline, vugs and fractures distributed through the rock-facies, which influence the values of cementation factor. We use the modern typed well to shed light on the Archie's equation parameter values. Rock fabric numbers and flow zone indices have been identified for classification of dolomite and sandstone, respectively. The analysis brings out characteristic cementation factors for distinct pore types in the Arbuckle rock. The porosity predictions The analysis results also compliment the petrofacies delineation using LDA in this complicated rock layout as a quality control of the statistical application. The comparison between the predicted and core porosities shows a significant improvement over using a single m value for carbonates and sandstones which will lead to improved description of a matured field. Copyright 2011, Society of Petroleum Engineers.

Study utilization of extractable petroleum hydrocarbons biodegradation waste as the main material for making solid fuels

NASA Astrophysics Data System (ADS)

Hendrianie, Nuniek; Juliastuti, Sri Rachmania; Ar-rosyidah, Fanny Husna; Rochman, Hilal Abdur

2017-05-01

Nowadays the existence of energy sources of oil and was limited. Therefore, it was important to searching for new innovations of renewable energy sources by utilizing the waste into a source of energy. On the other hand, the process of extractable petroleum hydrocarbons biodegradation generated sludge that had calorific value and untapped. Because of the need for alternative sources of energy innovation with the concept of zero waste and the fuel potential from extractable petroleum hydrocarbons biodegradation waste, so it was necessary to study the use of extractable petroleum hydrocarbons biodegradation waste as the main material for making solid fuel. In addition, sawdust is a waste that had a great quantities and also had a high calorific value to be mixed with extractable petroleum hydrocarbons biodegradation waste. The purpose of this study was to determine the characteristics of the extractable petroleum hydrocarbons biodegradation waste and to determine the potential and a combination of a mixture of extractable petroleum hydrocarbons biodegradation waste and sawdust which has the best calorific value. The variables of this study was the composition of the waste and sawdust as follows 1:1; 1:3; and 3:1 (mass of sawdust : mass of waste) and time of sawdust carbonization was 10, 15 and 20 minutes. Sawdust was carbonized to get the high heating value. The characteristic of main material and fuel analysis performed with proximate analysis. While the calorific value analysis was performed with a bomb calorimeter. From the research, it was known that extractable petroleum hydrocarbons biodegradation waste had a moisture content of 3.06%; volatile matter 19.98%; ash content of 0.56%; fixed carbon content of 76.4% and a calorific value of 717 cal/gram. And a mixture that had the highest calorific value (4286.5 cal/gram) achieved in comparison sawdust : waste (3:1) by carbonization of sawdust for 20 minutes.

Soybean-derived biofuels and home heating fuels.

PubMed

Mushrush, George W; Wynne, James H; Willauer, Heather D; Lloyd, Christopher L

2006-01-01

It is environmentally enticing to consider replacing or blending petroleum derived heating fuels with biofuels for many reasons. Major considerations include the soaring worldwide price of petroleum products, especially home heating oil, the toxicity of the petroleum-derived fuels and the environmental damage that leaking petroleum tanks afford. For these reasons, it has been suggested that domestic renewable energy sources be considered as replacements, or at the least, as blending stocks for home heating fuels. If recycled soy restaurant cooking oils could be employed for this purpose, this would represent an environmental advantage. Renewable plant sources of energy tend to be less toxic than their petroleum counterparts. This is an important consideration when tank leakage occurs. Home fuel oil storage tanks practically always contain some bottom water. This water environment has a pH value that factors into heating fuel stability. Therefore, the question is: would the biofuel help or exacerbate fuel stability and furnace maintenance issues?

Black shale source rocks and oil generation in the Cambrian and Ordovician of the central Appalachian Basin, USA

USGS Publications Warehouse

Ryder, R.T.; Burruss, R.C.; Hatch, J.R.

1998-01-01

Nearly 600 million bbl of oil (MMBO) and 1 to 1.5 trillion ft3 (tcf) of gas have been produced from Cambrian and Ordovician reservoirs (carbonate and sandstone) in the Ohio part of the Appalachian basin and on adjoining arches in Ohio, Indiana, and Ontario, Canada. Most of the oil and gas is concentrated in the giant Lima-Indiana field on the Findlay and Kankakee arches and in small fields distributed along the Knox unconformity. Based on new geochemical analyses of oils, potential source rocks, bitumen extracts, and previously published geochemical data, we conclude that the oils in both groups of fields originated from Middle and Upper Ordovician blcak shale (Utica and Antes shales) in the Appalachian basin. Moroever, we suggest that approximately 300 MMBO and many trillions of cubic feet of gas in the Lower Silurian Clinton sands of eastern Ohio originated in the same source rocks. Oils from the Cambrian and Ordovician reservoirs have similar saturated hydrocarbon compositions, biomarker distributions, and carbon isotope signatures. Regional variations in the oils are attributed to differences in thermal maturation rather than to differences in source. Total organic carbon content, genetic potential, regional extent, and bitument extract geochemistry identify the balck shale of the Utica and Antes shales as the most plausible source of the oils. Other Cambrian and Ordovician shale and carbonate units, such as the Wells Creek formation, which rests on the Knox unconformity, and the Rome Formation and Conasauga Group in the Rome trough, are considered to be only local petroleum sources. Tmax, CAI, and pyrolysis yields from drill-hole cuttings and core indicate that the Utica Shale in eastern and central Ohio is mature with respect to oil generation. Burial, thermal, and hydrocarbon-generation history models suggest that much of the oil was generated from the Utica-Antes source in the late Paleozoic during the Alleghanian orogeny. A pervasive fracture network controlled by basement tectonics aided in the distribution of oil from the source to the trap. This fracture network permitted oil to move laterally and stratigraphically downsection through eastward-dipping, impermeable carbonate sequences to carrier zones such as the Middle Ordovician Knox unconformity, and to reservoirs such as porous dolomite in the Middle Ordovician Trenton Limestone in the Lima-Indiana field. Some of the oil and gas from the Utica-Antes source escaped vertically through a partially fractured, leaky Upper Ordovician shale seal into widespread Lower Silurian sandstone reservoirs.Nearly 600 million bbl of oil (MMBO) and 1 to 1.5 trillion ft3 (tcf) of gas have been produced from Cambrian and Ordovician reservoirs (carbonate and sandstone) in the Ohio part of the Appalachian basin and on adjoining arches in Ohio, Indiana, and Ontario, Canada. Most of the oil and gas is concentrated in the giant Lima-Indiana field on the Findlay and Kankakee arches and in small fields distributed along the Knox unconformity. Based on new geochemical analyses of oils, potential source rocks, bitumen extracts, and previously published geochemical data, we conclude that the oils in both groups of fields originated from Middle and Upper Ordovician black shale (Utica and Antes shales) in the Appalachian basin. Moreover, we suggest that approximately 300 MMBO and many trillions of cubic feet of gas in the Lower Silurian Clinton sands of eastern Ohio originated in these same source rocks.

40 CFR 60.111a - Definitions.

Code of Federal Regulations, 2011 CFR

2011-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for..., reservoir, or container used for the storage of petroleum liquids, but does not include: (1) Pressure... tanks if the total volume of petroleum liquids added to and taken from a tank annually does not exceed...

40 CFR 60.111a - Definitions.

Code of Federal Regulations, 2014 CFR

2014-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for..., reservoir, or container used for the storage of petroleum liquids, but does not include: (1) Pressure... tanks if the total volume of petroleum liquids added to and taken from a tank annually does not exceed...

40 CFR 60.111a - Definitions.

Code of Federal Regulations, 2012 CFR

2012-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for..., reservoir, or container used for the storage of petroleum liquids, but does not include: (1) Pressure... tanks if the total volume of petroleum liquids added to and taken from a tank annually does not exceed...

40 CFR 60.111a - Definitions.

Code of Federal Regulations, 2013 CFR

2013-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for..., reservoir, or container used for the storage of petroleum liquids, but does not include: (1) Pressure... tanks if the total volume of petroleum liquids added to and taken from a tank annually does not exceed...

40 CFR 60.111a - Definitions.

Code of Federal Regulations, 2010 CFR

2010-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Storage Vessels for Petroleum Liquids for..., reservoir, or container used for the storage of petroleum liquids, but does not include: (1) Pressure... tanks if the total volume of petroleum liquids added to and taken from a tank annually does not exceed...

76 FR 80934 - Agency Information Collection Activities; Submission to OMB for Review and Approval; Comment...

Federal Register 2010, 2011, 2012, 2013, 2014

2011-12-27

... Activities; Submission to OMB for Review and Approval; Comment Request; NSPS for Petroleum Refineries... electronic docket, go to http://www.regulations.gov . Title: NSPS for Petroleum Refineries (Renewal). ICR... Source Performance Standards (NSPS) for Petroleum Refineries, the affected entities are subject to the...

Geophysical Parameter Estimation of Near Surface Materials Using Nuclear Magnetic Resonance

NASA Astrophysics Data System (ADS)

Keating, K.

2017-12-01

Proton nuclear magnetic resonance (NMR), a mature geophysical technology used in petroleum applications, has recently emerged as a promising tool for hydrogeophysicists. The NMR measurement, which can be made in the laboratory, in boreholes, and using a surface based instrument, are unique in that it is directly sensitive to water, via the initial signal magnitude, and thus provides a robust estimate of water content. In the petroleum industry rock physics models have been established that relate NMR relaxation times to pore size distributions and permeability. These models are often applied directly for hydrogeophysical applications, despite differences in the material in these two environments (e.g., unconsolidated versus consolidated, and mineral content). Furthermore, the rock physics models linking NMR relaxation times to pore size distributions do not account for partially saturated systems that are important for understanding flow in the vadose zone. In our research, we are developing and refining quantitative rock physics models that relate NMR parameters to hydrogeological parameters. Here we highlight the limitations of directly applying established rock physics models to estimate hydrogeological parameters from NMR measurements, and show some of the successes we have had in model improvement. Using examples drawn from both laboratory and field measurements, we focus on the use of NMR in partial saturated systems to estimate water content, pore-size distributions, and the water retention curve. Despite the challenges in interpreting the measurements, valuable information about hydrogeological parameters can be obtained from NMR relaxation data, and we conclude by outlining pathways for improving the interpretation of NMR data for hydrogeophysical investigations.

High Molecular Weight Petrogenic and Pyrogenic Hydrocarbons in Aquatic Environments

NASA Astrophysics Data System (ADS)

Abrajano, T. A., Jr.; Yan, B.; O'Malley, V.

2003-12-01

Geochemistry is ultimately the study of sources, movement, and fate of chemicals in the geosphere at various spatial and temporal scales. Environmental organic geochemistry focuses such studies on organic compounds of toxicological and ecological concern (e.g., Schwarzenbach et al., 1993, 1998; Eganhouse, 1997). This field emphasizes not only those compounds with potential toxicological properties, but also the geological systems accessible to the biological receptors of those hazards. Hence, the examples presented in this chapter focus on hydrocarbons with known health and ecological concern in accessible shallow, primarily aquatic, environments.Modern society depends on oil for energy and a variety of other daily needs, with present mineral oil consumption throughout the 1990s exceeding 3×109 t yr-1 (NRC, 2002). In the USA, e.g., ˜40% of energy consumed and 97% of transportation fuels are derived from oil. In the process of extraction, refinement, transport, use, and waste production, a small but environmentally significant fraction of raw oil materials, processed products, and waste are released inadvertently or purposefully into the environment. Because their presence and concentration in the shallow environments are often the result of human activities, these organic materials are generally referred to as "environmental contaminants." Although such reference connotes some form of toxicological or ecological hazard, specific health or ecological effects of many organic "environmental contaminants" remain to be demonstrated. Some are, in fact, likely innocuous at the levels that they are found in many systems, and simply adds to the milieu of biogenic organic compounds that naturally cycle through the shallow environment. Indeed, virtually all compounds in crude oil and processed petroleum products have been introduced naturally to the shallow environments as oil and gas seepage for millions of years ( NRC, 2002). Even high molecular weight (HMW) polyaromatic compounds were introduced to shallow environments through forest fires and natural coking of crude oil ( Ballentine et al., 1996; O'Malley et al., 1997). The full development of natural microbial enzymatic systems that can utilize HMW hydrocarbons as carbon or energy source attests to the antiquity of hydrocarbon dispersal processes in the environment. The environmental concern is, therefore, primarily due to the rate and spatial scale by which petroleum products are released in modern times, particularly with respect to the environmental sensitivity of some ecosystems to these releases ( Schwarzenbach et al., 1993; Eganhouse, 1997; NRC, 2002).Crude oil is produced by diagenetic and thermal maturation of terrestrial and marine plant and animal materials in source rocks and petroleum reservoirs. Most of the petroleum in use today is produced by thermal and bacterial decomposition of phytoplankton material that once lived near the surface of the world's ocean, lake, and river waters (Tissot and Welte, 1984). Terrestrially derived organic matter can be regionally significant, and is the second major contributor to the worldwide oil inventory ( Tissot and Welte, 1984; Peters and Moldowan, 1993; Engel and Macko, 1993). The existing theories hold that the organic matter present in crude oil consists of unconverted original biopolymers and new compounds polymerized by reactions promoted by time and increasing temperature in deep geologic formations. The resulting oil can migrate from source to reservoir rocks where the new geochemical conditions may again lead to further transformation of the petrogenic compounds. Any subsequent changes in reservoir conditions brought about by uplift, interaction with aqueous fluids, or even direct human intervention (e.g., drilling, water washing) likewise could alter the geochemical makeup of the petrogenic compounds. Much of our understanding of environmental sources and fate of hydrocarbon compounds in shallow environments indeed borrowed from the extensive geochemical and analytical framework that was meticulously built by petroleum geochemists over the years (e.g., Tissot and Welte, 1984; Peters et al., 1992; Peters and Moldowan, 1993; Engel and Macko, 1993; Moldowan et al., 1995; Wang et al., 1999; Faksness et al., 2002).Hydrocarbon compounds present in petroleum or pyrolysis by-products can be classified based on their composition, molecular weight, organic structure, or some combination of these criteria. For example, a report of the Committee on Intrinsic Remediation of the US NRC classified organic contaminants into HMW hydrocarbons, low molecular weight (LMW) hydrocarbons, oxygenated hydrocarbons, halogenated aliphatics, halogenated aromatics, and nitroaromatics (NRC, 2000). Hydrocarbons are compounds comprised exclusively of carbon and hydrogen and they are by far the dominant components of crude oil, processed petroleum hydrocarbons (gasoline, diesel, kerosene, fuel oil, and lubricating oil), coal tar, creosote, dyestuff, and pyrolysis waste products. These hydrocarbons often occur as mixtures of a diverse group of compounds whose behavior in near-surface environments is governed by their chemical structure and composition, the geochemical conditions and media of their release, and biological factors, primarily microbial metabolism, controlling their transformation and degradation.Hydrocarbons comprise from 50% to 99% of compounds present in refined and unrefined oil, and compounds containing other elements such as oxygen, nitrogen, and sulfur are present in relatively smaller proportions. Hydrocarbon compounds have carbons joined together as single C - C bonds (i.e., alkanes), double or triple C=C bonds (i.e., alkenes or olefins), or via an aromatic ring system with resonating electronic structure (i.e., aromatics). Alkanes, also called paraffins, are the dominant component of crude oil, with the carbon chain forming either straight (n-alkanes), branched (iso-alkanes), or cyclic (naphthenes) arrangement of up to 60 carbons (Figure 1). Aromatic compounds are the second major component of crude oil, with asphalthenes, consisting of stacks of highly polymerized aromatic structures (average of 16 rings), completing the list of major oil hydrocarbon components. Also shown in Figure 1 are several important classes of compounds that are extensively used in "fingerprinting" crude oil or petroleum sources: sterols derived from steroid, hopanol derived from bacteriohopanetetrols, and pristane and phytane derived from phytol (from chlorophyll) during diagenesis.

Standards of Performance for New Stationary Sources; Petroleum Dry Cleaners: 1985 Response to Petition for Reconsideration & Final Amendments to the Rule (50 FR 49022)

EPA Pesticide Factsheets

This document is a copy of the Federal Register publication of the November 27, 1985 Response to Petition for Reconsideration and Final Amendments to the Rule for the Standards of Performance for New Stationary Sources; Petroleum Dry Cleaners.

Relationships between data from Rock-Eval pyrolysis and proximate, ultimate, petrographic, and physical analyses of 142 diverse U.S. coal samples

USGS Publications Warehouse

Bostick, N.H.; Daws, T.A.

1994-01-01

Basic research on coal and oil shale led to automated pyrolysis analysis of petroleum source rocks; most widely used is the Rock-Eval equipment. In order to interpret Rock-Eval analyses in relation to traditional coal data, we analyzed 142 commercial coals with diverse rank, age, maceral and sulfur contents, for most regions of the United States. We compared the Rock-Eval data with traditional industrial coal data, including volatile matter, calorific value, hydrogen and oxygen content, free swelling index, and vitrinite reflectance. We found: (1) there is a close relationship between Tmax and vitrinite reflectance in the ranges 420-590??C Tmax and 0.4-3%Romax of most coals. (2) A close relationship between Tmax and volatile matter (%VM) extends through the entire sample range, including low-rank samples with 35-70% VM, a range where %VM is not considered to be a useful rank parameter. (3) TOC of medium- and high-rank coals is seriously under-measured by Rock-Eval; TOC of low-rank coals (less than 0.8%Romax) is close to "dry basis" carbon from ultimate analysis. (4) The direct relationships between oxygen index (OI) and %O and between hydrogen index (HI) and %H are clear, though only broadly defined. However, there is virtually no band of concentrated data points on the HI versus OI pseudo-Van Krevelen diagram comparable to the "development line" on the H/C versus O/C diagram. (5) There are systematic relationships between Rock-Eval and industrial coal parameters such as calorific value and FSI, but much standardization would be needed before Rock-Eval could find a place in the coal industry. Tests with blends of coal and quartz sand and with various loads of coal alone showed that the amount of organic matter in the Rock-Eval load greatly influences results. Total load in the crucible, if largely inert, plays a small role, however. Increasing absolute or relative coal content causes under-evaluation of Rock-Eval TOC and over-rating of hydrogen. Blends of several coals yielded hydrogen and oxygen indexes related proportionally to the properties of the individual coals, but Tmax is not raised by addition of high-rank coal until over 40% is added. ?? 1994.

POPO AGIE PRIMITIVE AREA, WYOMING.

USGS Publications Warehouse

Pearson, Robert C.; Patten, L.L.

1984-01-01

A mineral-resource appraisal was made of the Popo Agie Primitive Area and some adjoining lands. This scenic mountainous region of the Wind River Range in west-central Wyoming is composed largely of ancient granitic rocks in which virtually no evidence of mineral deposits was found. Deep crustal seismic-reflection profiles obtained across the southern Wind River Range suggest the possibility that young sedimentary rocks, similar to those at the surface along the northeast flank of the range, are present at depth beneath the granite in the Popo Agie primitive Area. If present, such buried sedimentary rocks could be petroleum bearing. Additional seismic and gravity studies would probably add valuable information, but ultimately very expensive, very deep drilling will be necessary to test this possibility.

The Nördlingen-Ries Geopark and nearby museums as a natural teaching laboratory for Geoscience students

NASA Astrophysics Data System (ADS)

Kaminski, Michael; Kaka, SanLinn; Kaminski, Matthew

2017-04-01

The hypervelocity impact of an asteroid in southern Germany around 15 million years ago not only caused an environmental catastrophe, but it also created a scenario that provides us with a world-class natural laboratory for teaching the basic Principles of Geology. The combination of museum visits and observation of rock outcrops enables the student to reinforce or rediscover the basic principles of physical and historical Geology that are presented in first- or second-year Geoscience courses. At KFUPM, our visit to the Ries Geopark begins at the Ries Crater Museum in Nördlingen, where students review knowledge learned in their Physical Geology course: the Nebular Theory, origin of the solar system, and the classification of meteorites based on real examples. Students then learn the stages of impact crater formation, shock metamorphism, and the products of impact crater formation such as tectites, impact breccia and suevite. Students also become familiar with the Mesozoic stratigraphy of Southern Germany, reviewing basic principals of stratigraphy. Visits to local outcrops reinforce the knowledge gained at the Museum. A visit to the nearby Solnhofen Museum and quarries provides insight into the nature of the late Jurassic animals that lived at the edge of the Tethys Sea, reinforcing many topics learned during their second-year Paleontology course, such as taphonomy, and the idea of a death assemblage. At the Museum of the Geosciences Department of the University of Tübingen, the students become familiar with Mesozoic ammonoids as part of their second-year Paleontology course. A visit to the Urwelt Museum and quarry in Holzmaden explores animal life during the Early Jurassic, stratigraphic principles as presented on the museum's "geological staircase", and the origin of petroleum source rocks. The museum houses spectacular examples of Early Jurassic marine reptiles. All knowledge gained in the Jurassic of southern Germany enriches the students' understanding of the Jurassic subsurface petroleum system in Saudi Arabia, which is one of the world's largest petroleum reservoirs. The combination of museum visits followed by field studies centered around the Ries Geopark in southern Germany not only creates a world-class attraction for Geotourists, but also an ideal teaching laboratory for students interested in Physical and Planetary Geology, Historical Geology, and Paleontology at various levels within the respective subjects.

Petroleum: An energy profile. [CONTAINS GLOSSARY

DOE Office of Scientific and Technical Information (OSTI.GOV)

Not Available

1991-08-01

This publication is intended as a general reference about petroleum: its origins, production, refining, marketing, and use. This report presents an overview of refined petroleum products and their use, crude oil reserves and production, refining technology and US refining capacity, the development and operation of petroleum markets, and foreign trade. A statistical supplement, an appendix describing refining operations, a glossary, and bibliographic references for additional sources of information are also included. 36 figs., 4 tabs.

76 FR 14986 - Notice of Proposed Reinstatement of Terminated Oil and Gas Lease WYW160429, Wyoming

Federal Register 2010, 2011, 2012, 2013, 2014

2011-03-18

..., Interior. ACTION: Notice. SUMMARY: Under the provisions of the Mineral Leasing Act of 1920, as amended, the Bureau of Land Management (BLM) received a petition for reinstatement from Rock Well Petroleum (US) Inc... FURTHER INFORMATION CONTACT: Bureau of Land Management, Julie L. Weaver, Chief, Fluid Minerals...

CMT for transport in porous media

DOE Office of Scientific and Technical Information (OSTI.GOV)

Schwartz, L.

This session is comprised of an outline of uses for x-ray microtomography in the field of petroleum geology. Calculations, diagrams, and color photomicrographs depict the many applications of synchrotron x-ray microtomograpy in determining transport properties and fluid flow characteristics of reservoir rocks, micro-porosity in carbonates, and aspects of multi-phase transport.

DOE workshop: Sedimentary systems, aqueous and organic geochemistry

DOE Office of Scientific and Technical Information (OSTI.GOV)

Not Available

1993-07-01

A DOE workshop on sedimentary systems, aqueous and organic geochemistry was held July 15-16, 1993 at Lawrence Berkeley Laboratory. Papers were organized into several sections: Fundamental Properties, containing papers on the thermodynamics of brines, minerals and aqueous electrolyte solutions; Geochemical Transport, covering 3-D imaging of drill core samples, hydrothermal geochemistry, chemical interactions in hydrocarbon reservoirs, fluid flow model application, among others; Rock-Water Interactions, with presentations on stable isotope systematics of fluid/rock interaction, fluid flow and petotectonic evolution, grain boundary transport, sulfur incorporation, tracers in geologic reservoirs, geothermal controls on oil-reservoir evolution, and mineral hydrolysis kinetics; Organic Geochemistry covered new methodsmore » for constraining time of hydrocarbon migration, kinetic models of petroleum formation, mudstones in burial diagenesis, compound-specific carbon isotope analysis of petroleums, stability of natural gas, sulfur in sedimentary organic matter, organic geochemistry of deep ocean sediments, direct speciation of metal by optical spectroscopies; and lastly, Sedimentary Systems, covering sequence stratigraphy, seismic reflectors and diagenetic changes in carbonates, geochemistry and origin of regional dolomites, and evidence of large comet or asteroid impacts at extinction boundaries.« less

Criteria for successful exploration for Miocene reef production in the Philippines

DOE Office of Scientific and Technical Information (OSTI.GOV)

Downey, M.W.

1990-06-01

An abundance of modern geologic, geophysical, and geochemical data has been provided to interested members of the petroleum industry by the Philippine government, in cooperation with the World Bank. These data have been analyzed to assess whether more, and larger, Miocene reef fields should be expected in the Philippines. In the past decade, exploration by Cities Service (OXY), Amoco, Alcorn, and others has resulted in the discovery of several small Miocene reef and Miocene sandstone oil fields in offshore Palawan. Phillips/Shell also made a significant gas discovery of about 750 bcf in a Palawan Miocene reef that is currently uneconomicmore » to develop given the water depth (1,090 ft) and distance from users. Miocene reefs are commonly buried within Miocene clastics, and, where these impinging clastics are porous, they allow pathways for hydrocarbons to leak from the Miocene reefs. Drape closure is an important positive factor in assessing seal risk for Philippine Miocene reefs. Source rocks to charge middle and upper Miocene reefs are typically restricted to lower Miocene horizons. Geothermal gradients are modest in much of the Philippine offshore, and only select areas provide sufficient burial to mature and expel significant hydrocarbons. It is predicted by the author that additional, larger, and highly profitable Miocene reef fields will be found by future explorers in areas where Miocene reefs have drape closure top seals and are adjacent to deeply buried Miocene source rocks.« less

A digital atlas of hydrocarbon accumulations within and adjacent to the National Petroleum Reserve - Alaska (NPRA)

USGS Publications Warehouse

Kumar, Naresh; Bird, Kenneth J.; Nelson, Philip H.; Grow, John A.; Evans, Kevin R.

2002-01-01

The United States Geological Survey (USGS) has initiated a project to reassess the hydrocarbon potential of the NPRA. Although exploration for hydrocarbons in the NPRA was initiated in 1944, it has taken fifty years for the first commercial discovery to be made. That discovery, the Alpine field (projected recoverable reserves of 430 million barrels), was made in 1994 along the eastern boundary of the NPRA. This field produces from a formation heretofore considered to be mostly a source rock. The Alpine discovery made such a reassessment necessary. As part of this assessment, we have compiled stratigraphic, structural, petrophysical, and seismic data related to nineteen accumulations within and nearby the NPRA. The goal is to provide basic documentation and a set of analog accumulations for the new assessment. The first two displays of this atlas consist of a location map and a stratigraphic column showing the stratigraphic settings for the primary reservoir and source rocks for these accumulations. The third display is a table listing each accumulation and providing the hydrocarbon fluid type, reservoir, operator, status, and discovery well and date for each. Compilation of basic information for each individual accumulation follows these displays. A typical compilation includes a structurecontour map on or near the reservoir horizon, a log display of the discovery well with reservoir characteristics along with figures for recoverable volumes, and one or two seismic lines across or near the accumulation.

Palaeoenvironment and Its Control on the Formation of Miocene Marine Source Rocks in the Qiongdongnan Basin, Northern South China Sea

PubMed Central

Li, Wenhao; Zhang, Zhihuan; Wang, Weiming; Lu, Shuangfang; Li, Youchuan; Fu, Ning

2014-01-01

The main factors of the developmental environment of marine source rocks in continental margin basins have their specificality. This realization, in return, has led to the recognition that the developmental environment and pattern of marine source rocks, especially for the source rocks in continental margin basins, are still controversial or poorly understood. Through the analysis of the trace elements and maceral data, the developmental environment of Miocene marine source rocks in the Qiongdongnan Basin is reconstructed, and the developmental patterns of the Miocene marine source rocks are established. This paper attempts to reveal the hydrocarbon potential of the Miocene marine source rocks in different environment and speculate the quality of source rocks in bathyal region of the continental slope without exploratory well. Our results highlight the palaeoenvironment and its control on the formation of Miocene marine source rocks in the Qiongdongnan Basin of the northern South China Sea and speculate the hydrocarbon potential of the source rocks in the bathyal region. This study provides a window for better understanding the main factors influencing the marine source rocks in the continental margin basins, including productivity, preservation conditions, and the input of terrestrial organic matter. PMID:25401132

40 CFR 98.390 - Definition of the source category.

Code of Federal Regulations, 2011 CFR

2011-07-01

... petroleum products and natural gas liquids as listed in Table MM-1 of this subpart. (a) A petroleum refinery... products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined... (CONTINUED) MANDATORY GREENHOUSE GAS REPORTING Suppliers of Petroleum Products § 98.390 Definition of the...

40 CFR 98.390 - Definition of the source category.

Code of Federal Regulations, 2013 CFR

2013-07-01

... petroleum products and natural gas liquids as listed in Table MM-1 of this subpart. (a) A petroleum refinery... products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined... (CONTINUED) MANDATORY GREENHOUSE GAS REPORTING Suppliers of Petroleum Products § 98.390 Definition of the...

40 CFR 98.390 - Definition of the source category.

Code of Federal Regulations, 2010 CFR

2010-07-01

... petroleum products and natural gas liquids as listed in Table MM-1 of this subpart. (a) A petroleum refinery... products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined... (CONTINUED) MANDATORY GREENHOUSE GAS REPORTING Suppliers of Petroleum Products § 98.390 Definition of the...

40 CFR 98.390 - Definition of the source category.

Code of Federal Regulations, 2014 CFR

2014-07-01

... petroleum products and natural gas liquids as listed in Table MM-1 of this subpart. (a) A petroleum refinery... products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined... (CONTINUED) MANDATORY GREENHOUSE GAS REPORTING Suppliers of Petroleum Products § 98.390 Definition of the...

40 CFR 98.390 - Definition of the source category.

Code of Federal Regulations, 2012 CFR

2012-07-01

... petroleum products and natural gas liquids as listed in Table MM-1 of this subpart. (a) A petroleum refinery... products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined... (CONTINUED) MANDATORY GREENHOUSE GAS REPORTING Suppliers of Petroleum Products § 98.390 Definition of the...

Petroleum produced water disposal: Mobility and transport of barium in sandstone and dolomite rocks.

PubMed

Ebrahimi, Pouyan; Vilcáez, Javier

2018-09-01

To assess the risk of underground sources of drinking water contamination by barium (Ba) present in petroleum produced water disposed into deep saline aquifers, we examined the effect of salinity (NaCl), competition of cations (Ca, Mg), temperature (22 and 60°C), and organic fracturing additives (guar gum) on the sorption and transport of Ba in dolomites and sandstones. We found that at typical concentration levels of NaCl, Ca, and Mg in petroleum produced water, Ba sorption in both dolomites and sandstones is inhibited by the formation of Ba(Cl) + complexes in solution and/or the competition of cations for binding sites of minerals. The inhibition of Ba sorption by both mechanisms is greater in dolomites than in sandstones. This is reflected by a larger decrease in the breakthrough times of Ba through dolomites than through sandstones. We found that the presence of guar gum has little influence on the sorption and thus the transport of Ba in both dolomites and sandstones. Contrary to most heavy metals, Ba sorption in both dolomites and sandstones decreases with increasing temperature, however the reducing effect of temperature on Ba sorption is relevant only at low salinity conditions. Higher inhibition of Ba sorption in dolomites than in sandstones is due to the greater reactivity of dolomite over sandstone. The results of this study which includes the formulation of a reactive transport model and estimation of partition coefficients of Ba in dolomites and sandstones have significant implications in understanding and predicting the mobility and transport of Ba in deep dolomite and sandstone saline aquifers. Copyright © 2018 Elsevier B.V. All rights reserved.

A petroleum system model for gas hydrate deposits in northern Alaska

USGS Publications Warehouse

Lorenson, T.D.; Collett, Timothy S.; Wong, Florence L.

2011-01-01

Gas hydrate deposits are common on the North Slope of Alaska around Prudhoe Bay, however the extent of these deposits is unknown outside of this area. As part of a United States Geological Survey (USGS) and the Bureau of Land Management (BLM) gas hydrate research collaboration, well cutting and mud gas samples have been collected and analyzed from mainly industry-drilled wells on the Alaska North Slope for the purpose of prospecting for gas hydrate deposits. On the Alaska North Slope, gas hydrates are now recognized as an element within a petroleum systems approach or TPS (Total Petroleum System). Since 1979, 35 wells have been samples from as far west as Wainwright to Prudhoe Bay in the east. Geochemical studies of known gas hydrate occurrences on the North Slope have shown a link between gas hydrate and more deeply buried conventional oil and gas deposits. Hydrocarbon gases migrate from depth and charge the reservoir rock within the gas hydrate stability zone. It is likely gases migrated into conventional traps as free gas, and were later converted to gas hydrate in response to climate cooling concurrent with permafrost formation. Gas hydrate is known to occur in one of the sampled wells, likely present in 22 others based gas geochemistry and inferred by equivocal gas geochemistry in 11 wells, and absent in one well. Gas migration routes are common in the North Slope and include faults and widespread, continuous, shallowly dipping permeable sand sections that are potentially in communication with deeper oil and gas sources. The application of this model with the geochemical evidence suggests that gas hydrate deposits may be widespread across the North Slope of Alaska.

Sequence stratigraphy of the Kingak Shale (Jurassic-Lower Cretaceous), National Petroleum Reserve in Alaska

USGS Publications Warehouse

Houseknecht, D.W.; Bird, K.J.

2004-01-01

Beaufortian strata (Jurassic-Lower Cretaceous) in the National Petroleum Reserve in Alaska (NPRA) are a focus of exploration since the 1994 discovery of the nearby Alpine oil field (>400 MMBO). These strata include the Kingak Shale, a succession of depositional sequences influenced by rift opening of the Arctic Ocean Basin. Interpretation of sequence stratigraphy and depositional facies from a regional two-dimensional seismic grid and well data allows the definition of four sequence sets that each displays unique stratal geometries and thickness trends across NPRA. A Lower to Middle Jurassic sequence set includes numerous transgressive-regressive sequences that collectively built a clastic shelf in north-central NPRA. Along the south-facing, lobate shelf margin, condensed shales in transgressive systems tracts downlap and coalesce into a basinal condensed section that is likely an important hydrocarbon source rock. An Oxfordian-Kimmeridgian sequence set, deposited during pulses of uplift on the Barrow arch, includes multiple transgressive-regressive sequences that locally contain well-winnowed, shoreface sandstones at the base of transgressive systems tracts. These shoreface sandstones and overlying shales, deposited during maximum flooding, form stratigraphic traps that are the main objective of exploration in the Alpine play in NPRA. A Valanginian sequence set includes at least two transgressive-regressive sequences that display relatively distal characteristics, suggesting high relative sea level. An important exception is the presence of a basal transgressive systems tract that locally contains shoreface sandstones of reservoir quality. A Hauterivian sequence set includes two transgressive-regressive sequences that constitute a shelf-margin wedge developed as the result of tectonic uplift along the Barrow arch during rift opening of the Arctic Ocean Basin. This sequence set displays stratal geometries suggesting incision and synsedimentary collapse of the shelf margin. ?? 2004. The American Association of Petroleum Geologists. All rights reserved.

Emissions of organic carbon and methane from petroleum and dairy operations in California's San Joaquin Valley

NASA Astrophysics Data System (ADS)

Gentner, D. R.; Ford, T. B.; Guha, A.; Boulanger, K.; Brioude, J.; Angevine, W. M.; de Gouw, J. A.; Warneke, C.; Gilman, J. B.; Ryerson, T. B.; Peischl, J.; Meinardi, S.; Blake, D. R.; Atlas, E.; Lonneman, W. A.; Kleindienst, T. E.; Beaver, M. R.; St. Clair, J. M.; Wennberg, P. O.; VandenBoer, T. C.; Markovic, M. Z.; Murphy, J. G.; Harley, R. A.; Goldstein, A. H.

2014-05-01

Petroleum and dairy operations are prominent sources of gas-phase organic compounds in California's San Joaquin Valley. It is essential to understand the emissions and air quality impacts of these relatively understudied sources, especially for oil/gas operations in light of increasing US production. Ground site measurements in Bakersfield and regional aircraft measurements of reactive gas-phase organic compounds and methane were part of the CalNex (California Research at the Nexus of Air Quality and Climate Change) project to determine the sources contributing to regional gas-phase organic carbon emissions. Using a combination of near-source and downwind data, we assess the composition and magnitude of emissions, and provide average source profiles. To examine the spatial distribution of emissions in the San Joaquin Valley, we developed a statistical modeling method using ground-based data and the FLEXPART-WRF transport and meteorological model. We present evidence for large sources of paraffinic hydrocarbons from petroleum operations and oxygenated compounds from dairy (and other cattle) operations. In addition to the small straight-chain alkanes typically associated with petroleum operations, we observed a wide range of branched and cyclic alkanes, most of which have limited previous in situ measurements or characterization in petroleum operation emissions. Observed dairy emissions were dominated by ethanol, methanol, acetic acid, and methane. Dairy operations were responsible for the vast majority of methane emissions in the San Joaquin Valley; observations of methane were well correlated with non-vehicular ethanol, and multiple assessments of the spatial distribution of emissions in the San Joaquin Valley highlight the dominance of dairy operations for methane emissions. The petroleum operations source profile was developed using the composition of non-methane hydrocarbons in unrefined natural gas associated with crude oil. The observed source profile is consistent with fugitive emissions of condensate during storage or processing of associated gas following extraction and methane separation. Aircraft observations of concentration hotspots near oil wells and dairies are consistent with the statistical source footprint determined via our FLEXPART-WRF-based modeling method and ground-based data. We quantitatively compared our observations at Bakersfield to the California Air Resources Board emission inventory and find consistency for relative emission rates of reactive organic gases between the aforementioned sources and motor vehicles in the region. We estimate that petroleum and dairy operations each comprised 22% of anthropogenic non-methane organic carbon at Bakersfield and were each responsible for 8-13% of potential precursors to ozone. Yet, their direct impacts as potential secondary organic aerosol (SOA) precursors were estimated to be minor for the source profiles observed in the San Joaquin Valley.

Effectiveness and mechanism of natural attenuation at a petroleum-hydrocarbon contaminated site.

PubMed

Lv, Hang; Su, Xiaosi; Wang, Yan; Dai, Zhenxue; Liu, Mingyao

2018-05-07

This study applied an integrated method for evaluating the effectiveness and mechanism of natural attenuation (NA) of petroleum-hydrocarbon contaminated groundwater. Site groundwater and soil samples were analysed to characterize spatial and temporal variations in petroleum hydrocarbons, geochemical indicators, microbial diversity and isotopes. The results showed that the area of petroleum hydrocarbon contamination plume decreased almost 60% in four years, indicating the presence of natural attenuation. The 14 C content and sequence analysis indicate that there are more relatively 'old' HCO 3 - that have been produced from petroleum hydrocarbons in the upgradient portion of the contaminated plume, confirming that intrinsic biodegradation was the major factor limiting spread of the contaminated plume. The main degradation mechanisms were identified as sulfate reduction and methanogenesis based on the following: (1) more SO 4 2- have been consumed in the contamination source than downgradient, and the δ 34 S values in the resident SO 4 2- were also more enriched in the contamination source, (2) production of more CH 4 in the contamination source with the δ 13 C values for CH 4 was much lower than that of CO 2 , and the fractionation factor was 1.030-1.046. The results of this study provide significant insight for applying natural attenuation and enhanced bioremediation as alternative options for remediation of petroleum-hydrocarbon contaminated sites. Copyright © 2018 Elsevier Ltd. All rights reserved.

75 FR 74457 - Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems

Federal Register 2010, 2011, 2012, 2013, 2014

2010-11-30

...EPA is promulgating a regulation to require monitoring and reporting of greenhouse gas emissions from petroleum and natural gas systems. This action adds this source category to the list of source categories already required to report greenhouse gas emissions. This action applies to sources with carbon dioxide equivalent emissions above certain threshold levels as described in this regulation. This action does not require control of greenhouse gases.

Evaporite-karst problems and studies in the USA

USGS Publications Warehouse

Johnson, K.S.

2008-01-01

Evaporites, including rock salt (halite) and gypsum (or anhydrite), are the most soluble among common rocks; they dissolve readily to form the same types of karst features that commonly are found in limestones and dolomites. Evaporites are present in 32 of the 48 contiguous states in USA, and they underlie about 40% of the land area. Typical evaporite-karst features observed in outcrops include sinkholes, caves, disappearing streams, and springs, whereas other evidence of active evaporite karst includes surface-collapse structures and saline springs or saline plumes that result from salt dissolution. Many evaporites also contain evidence of paleokarst, such as dissolution breccias, breccia pipes, slumped beds, and collapse structures. All these natural karst phenomena can be sources of engineering or environmental problems. Dangerous sinkholes and caves can form rapidly in evaporite rocks, or pre-existing karst features can be reactivated and open up (collapse) under certain hydrologic conditions or when the land is put to new uses. Many karst features also propagate upward through overlying surficial deposits. Human activities also have caused development of evaporite karst, primarily in salt deposits. Boreholes (petroleum tests or solution-mining operations) or underground mines may enable unsaturated water to flow through or against salt deposits, either intentionally or accidentally, thus allowing development of small to large dissolution cavities. If the dissolution cavity is large enough and shallow enough, successive roof failures can cause land subsidence and/or catastrophic collapse. Evaporite karst, natural and human-induced, is far more prevalent than is commonly believed. ?? 2007 Springer-Verlag.

Petroleum Market Model of the National Energy Modeling System

DOE Office of Scientific and Technical Information (OSTI.GOV)

NONE

1997-01-01

The purpose of this report is to define the objectives of the Petroleum Market Model (PMM), describe its basic approach, and provide detail on how it works. This report is intended as a reference document for model analysts, users, and the public. The PMM models petroleum refining activities, the marketing of petroleum products to consumption regions. The production of natural gas liquids in gas processing plants, and domestic methanol production. The PMM projects petroleum product prices and sources of supply for meeting petroleum product demand. The sources of supply include crude oil, both domestic and imported; other inputs including alcoholsmore » and ethers; natural gas plant liquids production; petroleum product imports; and refinery processing gain. In addition, the PMM estimates domestic refinery capacity expansion and fuel consumption. Product prices are estimated at the Census division level and much of the refining activity information is at the Petroleum Administration for Defense (PAD) District level. This report is organized as follows: Chapter 2, Model Purpose; Chapter 3, Model Overview and Rationale; Chapter 4, Model Structure; Appendix A, Inventory of Input Data, Parameter Estimates, and Model Outputs; Appendix B, Detailed Mathematical Description of the Model; Appendix C, Bibliography; Appendix D, Model Abstract; Appendix E, Data Quality; Appendix F, Estimation methodologies; Appendix G, Matrix Generator documentation; Appendix H, Historical Data Processing; and Appendix I, Biofuels Supply Submodule.« less

High resolution HH-XRF scanning and XRD modelling as a tool in sedimentological analysis - A case study from the Enreca-3 core, Bach Long Vi Island, Vietnam

NASA Astrophysics Data System (ADS)

Rizzi, Malgorzata; Hemmingsen Schovsbo, Niels; Korte, Christoph; Bryld Wessel Fyhn, Michael

2017-04-01

To improve the understanding and interpretation of the depositional environment of a late Oligocene lacustrine organic rich oil-prone source rock succession, 2464 hand held (HH)-XRF measurements were made systematically on the 500 m long, continuous core from the fully cored Enreca-3 well. This core, drilled on the remote Bach Long Vi Island, northern Gulf of Tonkin, offshore Vietnam, represents a deep lake succession alternating between lacustrine pelagic dominated sediments interrupted by hyperpycnal turbidites, high density turbidites and debris flows [1, 2]. From a combined HH-XRF-XRD data set, multivariate data analysis and regression models are used to type the rock and to predict the XRD mineral composition based on HH-XRF composition. The rock types and the modelled mineral composition highlight the geochemical variations of the sediment and allows for direct comparison with sedimentological processes and facies changes. The modeling also depicts the cyclic alteration of rock types that are present on many different scales ranging from centimeters to hundreds of meters [1, 2]. The sedimentological and geochemical variations observed throughout the cored section reflects fluctuating paleoclimate, tectonism and hinterland condition controlling the depositional setting, which may provide a deeper understanding of the deposition of this and similar Paleogene syn-rift succession in the South China Sea region. It allows furthermore the development of a more generalized depositional model relevant for other deep-lacustrine syn-rift basins. [1] Petersen et al. (2014) Journal of Petroleum Geology, 37: 373-389. [2] Hovikoski et al. (2016) Journal of Sedimentary Research, 86(8): 982-1007.

Bioremediation of petroleum-contaminated soil: A Review

NASA Astrophysics Data System (ADS)

Yuniati, M. D.

2018-02-01

Petroleum is the major source of energy for various industries and daily life. Releasing petroleum into the environment whether accidentally or due to human activities is a main cause of soil pollution. Soil contaminated with petroleum has a serious hazard to human health and causes environmental problems as well. Petroleum pollutants, mainly hydrocarbon, are classified as priority pollutants. The application of microorganisms or microbial processes to remove or degrade contaminants from soil is called bioremediation. This microbiological decontamination is claimed to be an efficient, economic and versatile alternative to physicochemical treatment. This article presents an overview about bioremediation of petroleum-contaminated soil. It also includes an explanation about the types of bioremediation technologies as well as the processes.

Evidence and characteristics of hydrolytic disproportionation of organic matter during metasomatic processes

USGS Publications Warehouse

Price, L.C.; Dewitt, E.

2001-01-01

Petroleum-geochemical analyses of carbonaceous regionally metamorphosed rocks, carbonaceous rocks from ore deposits, and alkalic plutonic rocks from diverse settings, demonstrated the presence of very low to moderately low concentrations of solvent-extractable organic matter, this observation in spite of the fact that some of these rocks were exposed to extremely high metamorphic temperatures. Biomarker and ??13C analyses established that the extractable organic matter originated as sedimentary-derived hydrocarbons. However, the chemistry of the extractable bitumen has been fundamentally transformed from that found in sediment bitumen and oils. Asphaltenes and resins, as defined in the normal petroleum-geochemical sense, are completely missing. The principal aromatic hydrocarbons present in oils and sediment bitumens (especially the methylated naphthalenes) are either in highly reduced concentrations or are missing altogether, Instead, aromatic hydrocarbons typical of sediment bitumens and oils are very minor, and a number of unidentified compounds and oxygen-bearing compounds are dominant. Relatively high concentrations of alkylated benzenes are typical. The polar "resin" fraction, eluted during column chromatography, is the principal compound group, by weight, being composed of six to eight dominant peaks present in all samples, despite the great geologic diversity of the samples. These, and other, observations suggest that a strong drive towards equilibrium exists in the "bitumen." Gas chromatograms of the saturated hydrocarbons commonly have a pronounced hump in both the n-paraffins and naphthenes, centered near the C19 to C26 carbon numbers, and a ubiquitos minimum in the n-paraffin distribution near n-C12 to n-C14. Multiple considerations dictate that the bitumen in the samples is indigenous and did not originate from either surficial field contamination or from laboratory procedures. Our observations are consistent with the hydrolytic disproportion of organic matter (HDOM), in which water and organic matter, including hydrocarbons, easily exchange hydrogen or oxygen with one another under certain conditions (Helgeson et al., 1993). The process appears to take place via well-known organic-chemical redox reaction pathways and is most evident in open-fluid systems. The conclusion that HDOM took place in the analyzed samples, thus producing the chemistry of the extractable bitumen, is supported by numerous previously published organic-geochemical studies of metamorphic, volcanic, plutonic, and ore-deposit-related rocks by other investigators. HDOM is suggested as an unrecognized geologic agent of fundamental importance. The process appears to control major chemical reactions in diverse geologic environments including, but not limited to, petroleum geology and geochemistry, regional metamorphism, and base- and precious-metal ore deposition. Copyright ?? 2001 Elsevier Science Ltd.

Hydrocarbon potential of the Early Oligocene Menilite shales in the Eastern Outer Carpathians (Tarcău and Vrancea Nappes, Romania)

NASA Astrophysics Data System (ADS)

Wendorff, Małgorzata; Rospondek, Mariusz; Kluska, Bartosz; Marynowski, Leszek

2017-04-01

During Oligocene to early Miocene time an extensive accumulation of organic-rich sedimentary rocks occurred in entire Paratethyan Basin, including its central part, i.e. the Carpathian Foredeep basin. Rocks of so-called Menilite facies formed there, burying significant amounts of organic matter (OM). These Menilite shales are now widely considered as a source of hydrocarbons throughout the Carpathian region. For the purpose of presented study, rock samples of the Menilite facies (mainly of the Lower Menilite and Bituminous Marl Members) were collected from two sections located in the different tectonic units (the Tarcău and Vrancea Nappes, Romania) of the Outer Carpathians. The main goal of the study was to assess and compare their hydrocarbon potential by examination of bulk geochemistry (total organic carbon content, pyrolysis Rock-Eval), vitrinite reflectance (Ro) and application of lipid biomarker parameters. The data show high variability in OM quantity and quality. Total organic carbon (TOC) content reaches peak values in the siliceous facies of the Lower Menilite Member (up to 8.6 wt% TOC), which contains type II kerogen represented by mainly marine OM type. Such results are confirmed by the presence of short-chain n-alkanes and hopanes. Mixed type II/III kerogen gains importance together with increasing contribution of turbiditic sedimentation. Terrigenous input is marked by occurrence of conifer aromatic biomarkers (such as simonellite, retene and 1,2,3,4-tetrahydroretene) and odd over even long chain n-alkanes predominance, characteristic for epicuticular leaf waxes. The analysed source rocks can be classified as oil-prone and subordinately mixed oil/gas-prone. OM in the inner tectonic unit (Tarcău Nappe; Tmax 430° C, Ro 0.5%) reaches onset of hydrocarbon generation, while in the outer unit (Vrancea Nappe) OM is immature (Tmax 425° C, Ro 0.4%). This maturity trend may be an effect of different burial histories of these units, as well as variation in subsequent erosion and exhumation levels resulting from the more inner position of the Tarcău Nappe within the orogen relative to the Vrancea Nappe (Wendorff et al., 2017). Based on the TOC content, S1 and S2 peak values the investigated rocks from the Vrancea Nappe reveal good to even excellent petroleum potential (especially for the siliceous facies of the Lower Menilite Mb.), although they did not attain the oil-window stage. The Tarcău Nappe source rocks have fair to good hydrocarbon potential. Hydrocarbons have been locally generated due to sufficient maturity, as also confirmed by high extractable bitumen yields and field observation of solid bitumen veins. However, hydrocarbon potential has not been exhausted as revealed by still high hydrocarbon index values. In the studied area the rocks of the Menilite facies have been suggested as a source for small gas/oil deposits, i.e. the Cuejdiu and Moineşti/Comăneşti field. References Wendorff, M., Rospondek, M., Kluska, B., Marynowski, L., 2017. Organic matter maturity and hydrocarbon potential of the Lower Oligocene Menilite facies in the Eastern Flysch Carpathians (Tarcău and Vrancea Nappes), Romania. Applied Geochemistry (in press).

Forensic identification of spilled biodiesel and its blends with petroleum oil based on fingerprinting information.

PubMed

Yang, Zeyu; Hollebone, Bruce P; Wang, Zhendi; Yang, Chun; Brown, Carl; Landriault, Mike

2013-06-01

A case study is presented for the forensic identification of several spilled biodiesels and its blends with petroleum oil using integrated forensic oil fingerprinting techniques. The integrated fingerprinting techniques combined SPE with GC/MS for obtaining individual petroleum hydrocarbons (aliphatic hydrocarbons, polyaromatic hydrocarbons and their alkylated derivatives and biomarkers), and biodiesel hydrocarbons (fatty acid methyl esters, free fatty acids, glycerol, monoacylglycerides, and free sterols). HPLC equipped with evaporative scattering laser detector was also used for identifying the compounds that conventional GC/MS could not finish. The three environmental samples (E1, E2, and E3) and one suspected source sample (S2) were dominant with vegetable oil with high acid values and low concentration of fatty acid methyl ester. The suspected source sample S2 was responsible for the three spilled samples although E1 was slightly contaminated by petroleum oil with light hydrocarbons. The suspected source sample S1 exhibited with the high content of glycerol, low content of glycerides, and high polarity, indicating its difference from the other samples. These samples may be the separated byproducts in producing biodiesel. Canola oil source is the most possible feedstock for the three environmental samples and the suspected source sample S2. © 2013 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim.

Comparative Toxicity and Mutagenicity of Soy-biodiesel and Petroleum-Diesel Emissions: Overview of Studies from the U.S. EPA, Research Triangle Park, NC

EPA Science Inventory

Biodiesel use as a fuel is increasing globally as an alternate to petroleum sources. To comprehensively assess the effects of the use of biodiesel as an energy source, end stage uses of biodiesel such as the effects of inhalation of combusted products on human health must be inco...

Volatile Fuel Hydrocarbons and MTBE in the Environment

NASA Astrophysics Data System (ADS)

Cozzarelli, I. M.; Baehr, A. L.

2003-12-01

Petroleum hydrocarbons (hydrocarbons that result from petroleum products such as oil, gasoline, or diesel fuel) are among the most commonly occurring and widely distributed contaminants in the environment. Volatile hydrocarbons are the lighter fraction of the petroleum hydrocarbons and, together with fuel oxygenates, are most often released from crude oil and liquid petroleum products produced from crude oil. The demand for crude oil stems from the world's ever-growing energy need. From 1970 to 1999, primary energy production of the world grew by 76% (Energy Information Administration, 2001), with fossil fuels (crude oil, natural gas, and coal) accounting for ˜85% of all energy produced worldwide (Figure 1). World crude oil production reached a record 68 million barrels (bbl) per day (1.08×1010 L d-1) in 2000. The world's dependence on oil as an energy source clearly is identified as contributing to global warming and worsening air and water quality. (7K)Figure 1. World primary energy production by source from 1970 to 1999 (Energy Information Administration, 2001). Petroleum products are present in Earth's subsurface as solids, liquids, or gases. This chapter presents a summary of the environmental problems and issues related to the use of liquid petroleum, or oil. The focus is on the sources of volatile hydrocarbons and fuel oxygenates and the geochemical behavior of these compounds when they are released into the environment. Although oxygenates currently in commercial use include compounds other than methyl t-butyl ether (MTBE), such as ethanol (ETOH), most of the information presented here focuses on MTBE because of its widespread occurrence. The environmental impact of higher molecular weight hydrocarbons that also originate from petroleum products is described in (Chapter 9.13, Abrajano et al.).Crude oil occurs within the Earth and is a complex mixture of natural compounds composed largely of hydrocarbons containing only hydrogen and carbon atoms. The minor elements of sulfur, nitrogen, and oxygen constitute less than 3% of most petroleum (Hunt, 1996). Releases to the environment occur during the production, transport, processing, storage, use and disposal of these hydrocarbons. The petroleum industry classifies oil naturally occurring in a liquid phase as either conventional oil or nonconventional oil. Conventional oils can be explored and produced by conventional primary and secondary recovery techniques, whereas nonconventional oils, such as heavy oils, tar sands, and synthetic oils, are more difficult to extract from the host rock ( Tissot and Welte, 1984). The history of liquid petroleum usage dates back centuries. Marco Polo described its use as a fuel for lamps in 1291 ( Testa and Winegardner, 2000). In the mid-nineteenth century, Native Americans used crude oil skimmed from creeks and rivers as a medicinal ointment ( Energy Information Administration, 1999). Commercial production in the United States began in 1859, with kerosene production for use in lamps. At the turn of the century, emphasis shifted to gasoline with the invention of the automobile, and in the 1930s and 1940s a substantial market for heating oil developed.In 2000, over 85% of the world's energy came from fossil fuels (Table 1), with oil production alone supplying 40% of that energy (Edwards, 2001). Oil, with its high British Thermal Unit (BTU) density and ease of transport, is the most valuable fuel in the world today, and the demand for world crude oil is ever increasing. Annual world crude-oil demand increased from 22 billion to 28 billion bbl of oil (BBO) ((3.5-4.5)×1012 L) from 1990 to 2000. Increasing population growth and industrialization in developing countries is expected to drive this annual oil demand up 1.5% annually to ˜38 BBO (6.0×1012 L) by 2030. As demand increases and known oil reserves are depleted, more emphasis will be placed on new discoveries and improved recovery technologies. Sources such as tar sands and oil shales are likely to become more important, bringing environmental problems inherent to the production, transport, and processing of these resources to new sectors of the environment. Table 1. United States and world energy consumption by source (January 2000) Energy SourceUnited StatesWorld BBOEPercentBBOEPercent Petroleum6.84127.140 Natural gas4.224.214.421.2 Coal3.923.216.724.7 Nuclear1.37.94.56.7 Hydroelectric0.733.71.62.4 Biomass3.45 Total7.610069.3100 Source: Edwards (2001). BBOE=billion barrels of oil equivalent. Reserves of crude oil, the raw material used to make petroleum products, are not evenly distributed around the world. The production levels of the major oil-producing nations in the world, shown in Figure 2, are based on data collected by the US Department of Energy's (DOEs) Energy Information Administration (EIA). Nations in the Organization of Petroleum Exporting Countries (OPEC) produce ˜43% of the world's total of nearly 68 million bbl per day (bpd) (1.08×1010 L d-1), with Saudi Arabia as the world's largest producer at 8.3 million bpd (12% of total) (1.33×109 L d-1), followed by Russia and the former Soviet Union at 6.4 million bpd (9%) (1.02×109 L d-1). The United States produced ˜5.7 million bpd (8%) (9.06×108 L d-1). Oil and gas are being produced in virtually all geographic areas intersecting a wide range of ecological habitats, including tropical rain forests, Middle Eastern deserts, Arctic regions, and deep offshore marine environments. (6K)Figure 2. World crude-oil production from leading producers, 1960-2000, in million barrels per day (Energy Information Administration, 2001). The petroleum industry has two main components, exploration/recovery and refinement/delivery. Crude oil is delivered to refineries and refined products are delivered to consumers through a large transportation network that includes tankers, barges, pipelines, and railroads. This transportation network links suppliers and producers across the world. Above-ground tanks, below-ground tanks and caverns, and offshore facilities store petroleum at various stages in this distribution system. The largest underground storage facilities in the US are part of the US. Strategic Petroleum Reserve maintained by the US government for times of supply shortage (Energy Information Administration, 1999). The global and complex nature of this industry means that every environmental compartment (air, land, water, biota) and all nations are affected by petroleum spills and waste products.Petroleum products are released into the environment inadvertently and intentionally at all stages of petroleum use, from exploration, production, transportation, storage, use and disposal (Figure 3). The more volatile components of oil partition preferentially into the atmosphere and hydrosphere, and to a lesser extent, the geosphere (e.g., sorption onto sediments), and biosphere (i.e., bioaccumulation), whereas the higher molecular weight fraction of oil is less soluble and less volatile and impacts the biosphere and geosphere more directly as described by Abrajano et al. (see Chapter 9.13). Usage causes compounds from petroleum products to separate and enter the environment. For example, incomplete fuel combustion in an automobile engine or a home heating furnace results in the release of compounds to the atmosphere, where they can be widely dispersed. Compounds in the exhaust gas of a motor boat partition in river or lake water, allowing for mixing and transport in the water body. These examples are illustrative of chronic low-level and widespread release of compounds referred to as nonpoint sources. (10K)Figure 3. Modes of contamination by petroleum products during production, transport, use, and disposal (after Fetter, 1993). Concentrated releases of compounds to the environment generally are associated with product mishandling and accidents during storage and transportation. For example, gasoline leaking from an underground storage tank (UST) releases compounds to the air, water, and solids of the subsurface. An oil tanker spill at sea can result in the rapid dispersal of large amounts of product. These two examples of more concentrated release are referred to as point sources. However, in the case of a tanker spill, the point release can result in a serious regional problem such as the spill of the Exxon Valdez that spilled oil that spread 750 km from the original spill site and impacted 1,750 km of shoreline (Wolfe et al., 1994).Nonpoint sources can cause compounds to be dispersed throughout the hydrosphere, which can complicate efforts to evaluate the effect of spills. Current sampling and analytical techniques allow for the detection of volatile organic compounds (VOCs) at low concentrations (0.1 μg L-1 and less). As a result, VOCs have been detected frequently in ambient shallow groundwater in urban areas across the country in studies conducted as part of the US Geological Survey (USGS) National Water-Quality Assessment (NAWQA) program (Squillace et al., 1996). The importance of VOCs at low concentrations in ambient water is unclear. If these low concentrations are the result of plumes emanating from point sources, then concentrations could possibly increase with time. If the source were diffuse (nonpoint), as in the case of atmospheric sources, then changes in VOC concentrations in groundwater over time would be constrained by atmospheric concentrations.Widely distributed and frequent point source spills can be considered nonpoint sources when the scale of concern is large in space or time. For example, the United States generates 1.3 billion gallons (4.9×109 L) of used motor oil each year, of which ˜13% is disposed of improperly (Motor Oil Facts, http://www.epa.gov/seahome/housewaste/src/oilfact.htm). This large quantity of improperly disposed motor oil could be a regional source of MTBE and benzene, toluene, ethylbenzene, and xylenes (BTEX) as used motor oil contains BTEX and MTBE, ˜500-2,000 mg L-1 for BTEX and 100 mg L-1 for MTBE (Baker et al., 2002; Chen et al., 1994). In a survey of 946 domestic wells designed to assess ambient groundwater quality in Maine, MTBE was detected in 15.8% of the wells, mostly at concentrations less than 0.1 μg L-1 (State of Maine Bureau of Health, 1998). Small and widely distributed spills of fuel-related products not necessarily associated with leaking storage tanks were identified as likely sources.

Kerogen maturation data in the Uinta Basin, Utah, USA, constrain predictions of natural hydrocarbon seepage into the atmosphere

NASA Astrophysics Data System (ADS)

Mansfield, Marc L.

2014-03-01

Natural seepage of methane from the lithosphere to the atmosphere occurs in regions with large natural gas deposits. According to some authors, it accounts for roughly 5% of the global methane budget. I explore a new approach to estimate methane fluxes based on the maturation of kerogen, which is the hydrocarbon polymer present in petroleum source rocks and whose decomposition leads to the formation of oil and natural gas. The temporal change in the atomic H/C ratio of kerogen lets us estimate the total carbon mass released by it in the form of oil and natural gas. Then the time interval of active kerogen decomposition lets us estimate the average annual formation rate of oil and natural gas in any given petroleum system, which I demonstrate here using the Uinta Basin of eastern Utah as an example. Obviously, this is an upper bound to the average annual rate at which natural gas seeps into the atmosphere. After adjusting for biooxidation of natural gas, I conclude that the average annual seepage rate in the Uinta Basin is not greater than (3100 ± 900) tonne yr-1. This is (0.5 ± 0.15)% of the total flux of methane into the atmosphere over the Basin, as measured during aircraft flights. I speculate about the difference between the regional 0.5% and the global 5% estimates.

Biomass-bioenergy crops in the United States: a changing paradigm

Treesearch

Jane M-F Johnson; Mark D. Coleman; Russ Gesch; Adbullah Jaradat; Rob Mitchell; Don Reicosky; W.W. Wilhelm

2007-01-01

The world energy paradigm is changing from one based on petroleum to one based on a mixture of energy platforms. This change is precipitated by a finite petroleum supply, an expanding global demand, and political instability in areas with major petroleum reserves. The mixed energy platform will include an array of renewable energy sources. The agricultural and forestry...

10 CFR 504.7 - Prohibition against excessive use of petroleum or natural gas in mixtures-electing powerplants.

Code of Federal Regulations, 2012 CFR

2012-01-01

... fuel as its primary energy source, OFP may prohibit, by order, the use in that unit of petroleum or... 10 Energy 4 2012-01-01 2012-01-01 false Prohibition against excessive use of petroleum or natural gas in mixtures-electing powerplants. 504.7 Section 504.7 Energy DEPARTMENT OF ENERGY (CONTINUED...

10 CFR 504.7 - Prohibition against excessive use of petroleum or natural gas in mixtures-electing powerplants.

Code of Federal Regulations, 2014 CFR

2014-01-01

... fuel as its primary energy source, OFP may prohibit, by order, the use in that unit of petroleum or... 10 Energy 4 2014-01-01 2014-01-01 false Prohibition against excessive use of petroleum or natural gas in mixtures-electing powerplants. 504.7 Section 504.7 Energy DEPARTMENT OF ENERGY (CONTINUED...

10 CFR 504.7 - Prohibition against excessive use of petroleum or natural gas in mixtures-electing powerplants.

Code of Federal Regulations, 2013 CFR

2013-01-01

... fuel as its primary energy source, OFP may prohibit, by order, the use in that unit of petroleum or... 10 Energy 4 2013-01-01 2013-01-01 false Prohibition against excessive use of petroleum or natural gas in mixtures-electing powerplants. 504.7 Section 504.7 Energy DEPARTMENT OF ENERGY (CONTINUED...

Identification of refined petroleum products in contaminated soils using an identification index for GC chromatograms.

PubMed

Kwon, Dongwook; Ko, Myoung-Soo; Yang, Jung-Seok; Kwon, Man Jae; Lee, Seung-Woo; Lee, Seunghak

2015-08-01

Hydrocarbons found in the environment are typically characterized by gas chromatography (GC). The shape of the GC chromatogram has been used to identify the source of petroleum contamination. However, the conventional practice of simply comparing the peak patterns of source products to those of environmental samples is dependent on the subjective decisions of individual analysts. We have developed and verified a quantitative analytical method for interpreting GC chromatograms to distinguish refined petroleum products in contaminated soils. We found that chromatograms for gasoline, kerosene, and diesel could be divided into three ranges with boundaries at C6, C8, C16, and C26. In addition, the relative peak area (RPA(GC)) of each range, a dimensionless ratio of the peak area within each range to that of the total range (C6-C26), had a unique value for each petroleum product. An identification index for GC chromatograms (ID(GC)), defined as the ratio of RPA(GC) of C8-C16 to that of C16-C26, was able to identify diesel and kerosene sources in samples extracted from artificially contaminated soils even after weathering. Thus, the ID(GC) can be used to effectively distinguish between refined petroleum products in contaminated soils.

Subsurface and petroleum geology of the southwestern Santa Clara Valley ("Silicon Valley"), California

USGS Publications Warehouse

Stanley, Richard G.; Jachens, Robert C.; Lillis, Paul G.; McLaughlin, Robert J.; Kvenvolden, Keith A.; Hostettler, Frances D.; McDougall, Kristin A.; Magoon, Leslie B.

2002-01-01

Gravity anomalies, historical records of exploratory oil wells and oil seeps, new organic-geochemical results, and new stratigraphic and structural data indicate the presence of a concealed, oil-bearing sedimentary basin beneath a highly urbanized part of the Santa Clara Valley, Calif. A conspicuous isostatic-gravity low that extends about 35 km from Palo Alto southeastward to near Los Gatos reflects an asymmetric, northwest-trending sedimentary basin comprising low-density strata, principally of Miocene age, that rest on higher-density rocks of Mesozoic and Paleogene(?) age. Both gravity and well data show that the low-density rocks thin gradually to the northeast over a distance of about 10 km. The thickest (approx 4 km thick) accumulation of low-density material occurs along the basin's steep southwestern margin, which may be controlled by buried, northeast-dipping normal faults that were active during the Miocene. Movement along these hypothetical normal faults may been contemporaneous (approx 17–14 Ma) with sedimentation and local dacitic and basaltic volcanism, possibly in response to crustal extension related to passage of the northwestward-migrating Mendocino triple junction. During the Pliocene and Quaternary, the normal faults and Miocene strata were overridden by Mesozoic rocks, including the Franciscan Complex, along northeastward-vergent reverse and thrust faults of the Berrocal, Shannon, and Monte Vista Fault zones. Movement along these fault zones was accompanied by folding and tilting of strata as young as Quaternary and by uplift of the modern Santa Cruz Mountains; the fault zones remain seismically active. We attribute the Pliocene and Quaternary reverse and thrust faulting, folding, and uplift to compression caused by local San Andreas Fault tectonics and regional transpression along the Pacific-North American Plate boundary. Near the southwestern margin of the Santa Clara Valley, as many as 20 exploratory oil wells were drilled between 1891 and 1929 to total depths as great as 840 m. At least one pump unit is still standing. Although no lithologic or paleontologic samples are available from the wells, driller's logs indicate the presence of thick intervals of brown shale and sandstone resembling nearby outcrops of the Miocene Monterey Formation. Small amounts of oil and gas were observed in several wells, but commercial production was never established. Oil from the Peck well in Los Gatos is highly biodegraded, contains biomarkers commonly found in oils derived from the Monterey Formation, and has a stable-C-isotopic (d13C) composition of –23.32 permil, indicating derivation from a Miocene Monterey Formation source rock. Preliminary calculations suggest that about 1 billion barrels of oil may have been generated from source rocks within the Monterey Formation in the deepest part of the subsurface sedimentary basin between Los Gatos and Cupertino. Most of this oil was probably lost to biodegradation, oxidation, and leakage to the surface, but some oil may have accumulated in as-yet-undiscovered structural and stratigraphic traps along the complex structural boundary between the Santa Clara Valley and the Santa Cruz Mountains. Although some of these undiscovered accumulations of oil may be of commercial size, future petroleum exploration is unlikely because most of the area is currently devoted to residential, recreational, commercial, and industrial uses.

Brookian structural plays in the National Petroleum Reserve, Alaska

USGS Publications Warehouse

Potter, Christopher J.; Moore, Thomas E.

2003-01-01

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

Role of the source to building lateral separation distance in petroleum vapor intrusion.

PubMed

Verginelli, Iason; Capobianco, Oriana; Baciocchi, Renato

2016-06-01

The adoption of source to building separation distances to screen sites that need further field investigation is becoming a common practice for the evaluation of the vapor intrusion pathway at sites contaminated by petroleum hydrocarbons. Namely, for the source to building vertical distance, the screening criteria for petroleum vapor intrusion have been deeply investigated in the recent literature and fully addressed in the recent guidelines issued by ITRC and U.S.EPA. Conversely, due to the lack of field and modeling studies, the source to building lateral distance received relatively low attention. To address this issue, in this work we present a steady-state vapor intrusion analytical model incorporating a piecewise first-order aerobic biodegradation limited by oxygen availability that accounts for lateral source to building separation. The developed model can be used to evaluate the role and relevance of lateral vapor attenuation as well as to provide a site-specific assessment of the lateral screening distances needed to attenuate vapor concentrations to risk-based values. The simulation outcomes showed to be consistent with field data and 3-D numerical modeling results reported in previous studies and, for shallow sources, with the screening criteria recommended by U.S.EPA for the vertical separation distance. Indeed, although petroleum vapors can cover maximum lateral distances up to 25-30m, as highlighted by the comparison of model outputs with field evidences of vapor migration in the subsurface, simulation results by this new model indicated that, regardless of the source concentration and depth, 6m and 7m lateral distances are sufficient to attenuate petroleum vapors below risk-based values for groundwater and soil sources, respectively. However, for deep sources (>5m) and for low to moderate source concentrations (benzene concentrations lower than 5mg/L in groundwater and 0.5mg/kg in soil) the above criteria were found extremely conservative as the model results indicated that for such scenarios the lateral screening distance may be set equal to zero. Copyright © 2016 Elsevier B.V. All rights reserved.

Regional structural framework and petroleum assessment of the Brooks Range foothills and southern coastal plain, National Petroleum Reserve, Alaska

USGS Publications Warehouse

Potter, Christopher J.; Moore, Thomas E.; O'Sullivan, Paul B.; Miller, John J.

2002-01-01

The transects, along with other seismic-reflection examples, illustrate four play concepts being used in the deformed area for the 2002 U.S. Geological Survey oil and gas assessment of the National Petroleum Reserve-Alaska (NPRA). The Brookian topset structural play includes broad west-northwest-trending anticlines in the Cretaceous Nanushuk Group, developed above structurally thickened Torok mudstones in the incipiently-deformed, most northerly part of the thrust system. The Torok structural play includes prominent anticlines affecting deep-basin sandstones, many of which are detached from folds exposed at the surface. The Ellesmerian structural play includes closures developed in the clastic part of the Ellesmerian sequence, mainly above a detachment in the Shublik Formation. The thrust belt play includes antiformal stacks of allochthonous Endicott Group clastic rocks and Lisburne Group carbonates; these stacks were assembled at about 120 Ma, and were transported to their present positions in the foothills at about 60 Ma.

Authigenic chlorite as a controlling factor in the exploration of Turonian/Coniacian turbidites in the Santos Basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Porsche, E.; Lopes de Freitas, E.

1996-08-01

Upper Turonian/Coniacian and Campanian turbidites are major targets for petroleum exploration in the Santos Basin, southeastern Brazil. They occur between 140 and 1000 m of present water depth, are buried at about 4500 m, and reach thickness of up to 60 m. The main reservoir facies is composed of unstratified, fine to very fine grained, poorly sorted sandstones, which framework is compositionally immature, including a high proportion of feldspars and volcanic rock fragments. Early coating of grains by authigenic chlorite inhibited pressure solution and quartz cementation in the reservoir. This diagenetic characteristic allowed important preservation of primary porosity (>20%) inmore » the reservoir; nevertheless its permeability never exceeds 30 ml. The study of sedimentary facies and related depositional processes has been conducted to predict the distribution of petroleum-bearing turbidites throughout the Santos Basin; this comprises a major challenge for the petroleum exploration in this important Brazilian exploration frontier.« less

Early Cretaceous to Paleocene North American Drainage Reorganization and Sediment Routing from Detrital Zircons: Significance to the Alberta Oil Sands and Gulf of Mexico Petroleum Provinces

NASA Astrophysics Data System (ADS)

Blum, M. D.

2014-12-01

Detrital zircons (DZs) represent a powerful tool for reconstructing continental paleodrainage. This paper uses new DZ data from Lower Cretaceous strata of the Alberta foreland basin, and Upper Cretaceous and Cenozoic strata of the Gulf of Mexico passive margin, to reconstruct paleodrainage and sediment routing, and illustrate significance to giant hydrocarbon systems. DZ populations from the Lower Cretaceous Mannville Group of Alberta and Saskatchewan infer a continental-scale river system that routed sediment from the eastern 2/3rds of North America to the Boreal Sea. Aptian McMurray Formation fluvial sands were derived from a drainage sourced in the Appalachians that was similar in scale to the modern Amazon. Albian fluvial sandstones of the Clearwater and Grand Rapids Formations were derived from the same Appalachian-sourced drainage area, which had expanded to include tributaries from the Cordilleran arc of the northwest US and southwest Canada. DZ populations from the Gulf of Mexico coastal plain complement this view, showing that only the southern US and Appalachian-Ouachita cordillera was integrated with the Gulf through the Late Cretaceous. However, by the Paleocene, drainage from the US Western Cordillera to the Appalachians had been routed to the Gulf of Mexico, establishing the template for sediment routing that persists today. The paleodrainage reorganization and changes in sediment routing described above played key roles in establishment of the Alberta oil sands and Gulf of Mexico as giant petroleum provinces. Early Cretaceous routing of a continental-scale fluvial system to the Alberta foreland provided large and contiguous fluvial point-bar sand bodies that became economically viable reservoirs, whereas mid- to late Cretaceous drainage reorganization routed greatly increased sediment loads to the Gulf of Mexico, which loaded the shelf, matured source rocks, and drove the gravitational and salt tectonics that helped establish the working hydrocarbon systems extant today.

Core evidence of paleoseismic events in Paleogene deposits of the Shulu Sag in the Bohai Bay Basin, east China, and their petroleum geologic significance

NASA Astrophysics Data System (ADS)

Zheng, Lijing; Jiang, Zaixing; Liu, Hui; Kong, Xiangxin; Li, Haipeng; Jiang, Xiaolong

2015-10-01

The Shulu Sag, located in the southwestern corner of the Jizhong Depression, Bohai Bay Basin of east China, is a NE-SW trending, elongate Cenozoic half-graben basin. The lowermost part of the third member of the Shahejie Formation in this basin is characterized by continental rudstone and calcilutite to calcisiltite facies. Based on core observation and regional geologic analysis, seismites are recognized in these lacustrine deposits, which include soft-sediment deformation structures (sedimentary dikes, hydraulic shattering, diapir structures, convolute lamination, load-flame structures, ball-and-pillow structures, loop bedding, and subsidence structures), synsedimentary faults, and seismoturbidites. In addition, mixed-source rudstones, consisting of the Paleozoic carbonate clasts and in situ calcilutite clasts in the lowermost submember of Shahejie 3, appear in the seismites, suggesting an earthquake origin. A complete representative vertical sequence in the lowermost part of the third member found in well ST1H located in the central part of the Shulu Sag shows, from the base to the top: underlying undeformed layers, synsedimentary faults, liquefied carbonate rocks, allogenetic seismoturbidites, and overlying undeformed layers. Seismites are widely distributed around this well and there are multiple sets of stacked seismites separated by undeformed sediment. The nearby NW-trending Taijiazhuang fault whose fault growth index is from 1.1 to 1.8 and the NNE-trending Xinhe fault with a fault growth index of 1.3-1.9 may be the source of the instability to create the seismites. These deformed sedimentary layers are favorable for the accumulation of oil and gas; for example, sedimentary dikes can cut through many layers and serve as conduits for fluid migration. Sedimentary faults and fractures induced by earthquakes can act as oil and gas migration channels or store petroleum products as well. Seismoturbidites and mixed-source rudstones are excellent reservoirs due to their abundant primary or dissolved pores.

Arsenic in ground water of the United States: occurrence and geochemistry

USGS Publications Warehouse

Welch, Alan H.; Westjohn, D.B.; Helsel, Dennis R.; Wanty, Richard B.

2000-01-01

Concentrations of naturally occurring arsenic in ground water vary regionally due to a combination of climate and geology. Although slightly less than half of 30,000 arsenic analyses of ground water in the United States were 1 μg/L, about 10% exceeded 10 μg/L. At a broad regional scale, arsenic concentrations exceeding 10 μg/L appear to be more frequently observed in the western United States than in the eastern half. Arsenic concentrations in ground water of the Appalachian Highlands and the Atlantic Plain generally are very low ( 1 μg/L). Concentrations are somewhat greater in the Interior Plains and the Rocky Mountain System. Investigations of ground water in New England, Michigan, Minnesota, South Dakota, Oklahoma, and Wisconsin within the last decade suggest that arsenic concentrations exceeding 10 μg/L are more widespread and common than previously recognized.Arsenic release from iron oxide appears to be the most common cause of widespread arsenic concentrations exceeding 10 μg/L in ground water. This can occur in response to different geochemical conditions, including release of arsenic to ground water through reaction of iron oxide with either natural or anthropogenic (i.e., petroleum products) organic carbon. Iron oxide also can release arsenic to alkaline ground water, such as that found in some felsic volcanic rocks and alkaline aquifers of the western United States. Sulfide minerals are both a source and sink for arsenic. Geothermal water and high evaporation rates also are associated with arsenic concentrations 10g/L in ground and surface water, particularly in the west.Arsenic release from iron oxide appears to be the most common cause of widespread arsenic concentrations exceeding 10 µg/L a ground water. This can occur in response to different geochemical conditions, including release of arsenic to ground water through reaction of iron oxide with either natural or anthropogenic (i.e., petroleum products) organic carbon. Iron oxide also can release arsenic to alkaline ground water, such as that found in some felsic volcanic rocks and alkaline aquifers of the Western United States. Sulfide minerals are both a source and sink for arsenic. Geothermal water and high evaporation rates also are associated with arsenic concentrations ≥ 10g/L in ground and surface water, particularly in the west.

PAH, PCB, TPH and mercury in surface sediments of the Delaware River Estuary and Delmarva Peninsula, USA.

PubMed

Kim, A W; Vane, C H; Moss-Hayes, V; Engelhart, S E; Kemp, A C

2018-04-01

Surface sediment concentrations of polycyclic aromatic hydrocarbons (PAH) and polychlorinated biphenyls (PCB), total petroleum hydrocarbons (TPH) and mercury, were compared from two areas with contrasting land use history, the industrial Delaware Estuary and the rural Delmarva Peninsula (USA). TPH in the Delaware (38-616mg/kg) and saturate/aromatic fractions suggested petroleum/industrial sources compared to biogenic sources in the Delmarva coastal control (<34-159mg/kg). Within the Delaware the ∑PAH18 ranged from 3749 to 22,324μg/kg with isomeric ratios indicative of petroleum combustion source/s, conversely, those in the Delmarva (5-2139μg/kg) also yielded relatively higher perylene that were consistent with natural background levels derived from vegetation/coal combustion source/s. ∑PCB(tri-hepta) concentrations in the Delmarva (0.6-6.5μg/kg) were less than the threshold effect concentration (TEC), whereas the Delaware had received much higher PCB loading (18.1-136.8μg/kg) as evidenced by a significantly higher amounts in some samples (>TEC). Copyright © 2017 Elsevier Ltd. All rights reserved.

Global prediction of continuous hydrocarbon accumulations in self-sourced reservoirs

USGS Publications Warehouse

Eoff, Jennifer D.

2012-01-01

This report was first presented as an abstract in poster format at the American Association of Petroleum Geologists (AAPG) 2012 Annual Convention and Exhibition, April 22-25, Long Beach, Calif., as Search and Discovery Article no. 90142. Shale resource plays occur in predictable tectonic settings within similar orders of magnitude of eustatic events. A conceptual model for predicting the presence of resource-quality shales is essential for evaluating components of continuous petroleum systems. Basin geometry often distinguishes self-sourced resource plays from conventional plays. Intracratonic or intrashelf foreland basins at active margins are the predominant depositional settings among those explored for the development of self-sourced continuous accumulations, whereas source rocks associated with conventional accumulations typically were deposited in rifted passive margin settings (or other cratonic environments). Generally, the former are associated with the assembly of supercontinents, and the latter often resulted during or subsequent to the breakup of landmasses. Spreading rates, climate, and eustasy are influenced by these global tectonic events, such that deposition of self-sourced reservoirs occurred during periods characterized by rapid plate reconfiguration, predominantly greenhouse climate conditions, and in areas adjacent to extensive carbonate sedimentation. Combined tectonic histories, eustatic curves, and paleogeographic reconstructions may be useful in global predictions of organic-rich shale accumulations suitable for continuous resource development. Accumulation of marine organic material is attributed to upwellings that enhance productivity and oxygen-minimum bottom waters that prevent destruction of organic matter. The accumulation of potential self-sourced resources can be attributed to slow sedimentation rates in rapidly subsiding (incipient, flexural) foreland basins, while flooding of adjacent carbonate platforms and other cratonic highs occurred. In contrast, deposition of this resource type on rifted passive margins was likely the result of reactivation of long-lived cratonic features or salt tectonic regimes that created semi-confined basins. Commonly, loading by thick sections of clastic material, following thermal relaxation after plate collision or rift phases, advances kerogen maturation. With few exceptions, North American self-sourced reservoirs appear to be associated with calcitic seas and predominantly greenhouse or transitional ("warm" to "cool") global climatic conditions. Significant changes to the global carbon budget may also be a contributing factor in the stratigraphic distribution of continuous resource plays, requiring additional evaluation.

West African Oil: Will It Make a Difference?

DTIC Science & Technology

1982-12-01

West Africa: Estimated Proved Reserves, 1 January 1982 -i-----------------------------------i1 10. West Africa: Crude Oil Export Potential... Exporting Countries sq. km. Square kilometers 12 I. INTRODUCTION In the 1950s, petroleum became the world’s dominant source of commercial energy, and in the...in 1973 the Organization of Petroleum Exporting Countries (OPEC) abruptly and permanently ended the era of inexpensive petroleum, and in the process

Provenance of sediments from Sumatra, Indonesia - Insights from detrital U-Pb zircon geochronology, heavy mineral analyses and Raman spectroscopy

NASA Astrophysics Data System (ADS)

Liebermann, C.; Hall, R.; Gough, A.

2017-12-01

The island of Sumatra is situated at the southwestern margin of the Indonesian archipelago. Although it is the sixth largest island in the world, the geology of the Sumatra sedimentary basins and their underlying basement is relatively poorly understood in terms of their provenance. This work is a multi-proxy provenance study utilizing U-Pb detrital zircon dating by LA-ICP-MS combined with optical and Raman spectroscopy-based heavy mineral analysis. It will help to unravel the stratigraphy of Sumatra, contribute to paleogeographic reconstruction of western SE Asia, and aid a wider understanding of Sumatran petroleum plays. Thin section analyses, heavy mineral assemblages, and >3500 concordant U-Pb zircon ages, from samples acquired during two fieldwork seasons indicate a mixed provenance for Cenozoic sedimentary formations, including both local igneous sources and mature basement rocks. Characteristic Precambrian zircon age spectra are found in all analysed Cenozoic sedimentary strata. These can be correlated with zircon age populations found in Sumatran basement rocks; Neoproterozoic and Mesoproterozoic age groups are dominant (c. 500-600 Ma, c. 850-1000 Ma, c. 1050-1200 Ma). Paleoproterozoic to Archaean zircons occur as minor populations. The Phanerozoic age spectra of the Cenozoic formations are characterised by distinct Carboniferous, Permo-Triassic, and Jurassic-Cretaceous zircon populations. Permo-Triassic zircons are interpreted to come from granitoids in the Malay peninsula or Sumatra itself. Eocene to Lower Miocene strata are characterised by ultrastable heavy minerals such as zircon, tourmaline, and rutile, which together with garnet, suggest the principal sources were igneous and metamorphic basement rocks. Cenozoic zircons appear only from the Middle Miocene onwards. This change is interpreted to indicate a new contribution from a local volcanic arc, and is supported by the occurrence of unstable heavy minerals such as apatite and clinopyroxene, and the presence of volcanic quartz. The absence of an earlier volcanic contribution is surprising since subduction is widely considered to have been active from the Eocene.

Stratigraphic reconnaissance of the Middle Jurassic Red Glacier Formation, Tuxedni Group, at Red Glacier, Cook Inlet, Alaska

USGS Publications Warehouse

LePain, David L.; Stanley, Richard G.

2015-01-01

The Alaska Division of Geological & Geophysical Surveys (DGGS) and U.S. Geological Survey (USGS) are implementing ongoing programs to characterize the petroleum potential of Cook Inlet basin. Since 2009 this program has included work on the Mesozoic stratigraphy of lower Cook Inlet, including the Middle Jurassic Tuxedni Group between Tuxedni and Iniskin bays (LePain and others, 2013; Stanley and others, 2013; fig. 5-1). The basal unit in the group, the Red Glacier Formation (fig. 5-2), is thought to be the principal source rock for oil produced in upper Cook Inlet, and available geochemical data support this contention (Magoon and Anders, 1992; Magoon, 1994). Despite its economic significance very little has been published on the formation since Detterman and Hartsock’s (1966) seminal contribution on the geology of the Iniskin–Tuxedni area nearly 50 years ago. Consequently its stratigraphy, contact relations with bounding formations, and source rock characteristics are poorly known. During the 2014 field season, a nearly continuous stratigraphic section through the Red Glacier Formation in its type area at Red Glacier was located and measured to characterize sedimentary facies and to collect a suite of samples for analyses of biostratigraphy, Rock-Eval pyrolysis, vitrinite reflectance, and sandstone composition (fig. 5-3).The poorly known nature of the Red Glacier Formation is likely due to its remote location, steep terrain, and the fact that the type section is split into two segments that are more than 3 km apart. The lower 375 m segment of the formation is on the ridge between Red Glacier and Lateral Glacier and the upper 1,009 m segment is on the ridge between Red Glacier and Boulder Creek (fig. 5-3). Structural complications in the area add to the difficulty in understanding how these two segments fit together.

Fate and groundwater impacts of produced water releases at OSPER "B" site, Osage County, Oklahoma

USGS Publications Warehouse

Kharaka, Y.K.; Kakouros, E.; Thordsen, J.J.; Ambats, G.; Abbott, M.M.

2007-01-01

For the last 5 a, the authors have been investigating the transport, fate, natural attenuation and ecosystem impacts of inorganic and organic compounds in releases of produced water and associated hydrocarbons at the Osage-Skiatook Petroleum Environmental Research (OSPER) "A" and "B" sites, located in NE Oklahoma. Approximately 1.0 ha of land at OSPER "B", located within the active Branstetter lease, is visibly affected by salt scarring, tree kills, soil salinization, and brine and petroleum contamination. Site "B" includes an active production tank battery and adjacent large brine pit, two injection well sites, one with an adjacent small pit, and an abandoned brine pit and tank battery site. Oil production in this lease started in 1938, and currently there are 10 wells that produce 0.2-0.5 m3/d (1-3 bbl/d) oil, and 8-16 m3/d (50-100 bbl/d) brine. Geochemical data from nearby oil wells show that the produced water source is a Na-Ca-Cl brine (???150,000 mg/L TDS), with high Mg, but low SO4 and dissolved organic concentrations. Groundwater impacts are being investigated by detailed chemical analyses of water from repeated sampling of 41 boreholes, 1-71 m deep. The most important results at OSPER "B" are: (1) significant amounts of produced water from the two active brine pits percolate into the surficial rocks and flow towards the adjacent Skiatook reservoir, but only minor amounts of liquid petroleum leave the brine pits; (2) produced-water brine and minor dissolved organics have penetrated the thick (3-7 m) shale and siltstone units resulting in the formation of three interconnected plumes of high-salinity water (5000-30,000 mg/L TDS) that extend towards the Skiatook reservoir from the two active and one abandoned brine pits; and (3) groundwater from the deep section of only one well, BR-01 located 330 m upslope and west of the site, appear not to be impacted by petroleum operations. ?? 2007.

Petroleum Refineries New Source Performance Standards (NSPS) Direct Final Amendments Fact Sheet

EPA Pesticide Factsheets

This page contains a December 2013 fact sheet with information regarding the direct final rule for the NSPS for Petroleum Refineries. This document provides a summary of the information for this NSPS.

Chemical and Biological Characterization of Black Rock Harbor Dredged Material.

DTIC Science & Technology

1985-09-01

452. .... Stegeman, J.J. and Teal, J.M. 1973. "Accumulation, Release and Reten- ’’’’’ tion of Petroleum Hydrocarbons by the Oyster, Crassostrea...sediment (6800 ng/g), while tissue concentrations of parent poly- nuclear hydrocarbons were 28% of sediment concentrations that ranged up to " 9800 ng/g...36 ,- "-. Annelids ................................................... 40 Molluscs .................................................. 43

Biogeochemical evidence for subsurface hydrocarbon occurrence, Recluse oil field, Wyoming; preliminary results

USGS Publications Warehouse

Dalziel, Mary C.; Donovan, Terrence J.

1980-01-01

Anomalously high manganese-to-iron ratios occurring in pine needles and sage leaves over the Recluse oil field, Wyoming, suggest effects of petroleum microseepage on the plants. This conclusion is supported by iron and manganese concentrations in soils and carbon and oxygen isotope ratios in rock samples. Seeping hydrocarbons provided reducing conditions sufficient to enable divalent iron and manganese to be organically complexed or adsorbed on solids in the soils. These bound or adsorped elements in the divalent state are essential to plants, and the plants readily assimilate them. The magnitude of the plant anomalies, combined with the supportive isotopic and chemical evidence confirming petroleum leakage, makes a strong case for the use of plants as a biogeochemical prospecting tool.

Numeric stratigraphic modeling: Testing sequence Numeric stratigraphic modeling: Testing sequence stratigraphic concepts using high resolution geologic examples

DOE Office of Scientific and Technical Information (OSTI.GOV)

Armentrout, J.M.; Smith-Rouch, L.S.; Bowman, S.A.

1996-08-01

Numeric simulations based on integrated data sets enhance our understanding of depositional geometry and facilitate quantification of depositional processes. Numeric values tested against well-constrained geologic data sets can then be used in iterations testing each variable, and in predicting lithofacies distributions under various depositional scenarios using the principles of sequence stratigraphic analysis. The stratigraphic modeling software provides a broad spectrum of techniques for modeling and testing elements of the petroleum system. Using well-constrained geologic examples, variations in depositional geometry and lithofacies distributions between different tectonic settings (passive vs. active margin) and climate regimes (hothouse vs. icehouse) can provide insight tomore » potential source rock and reservoir rock distribution, maturation timing, migration pathways, and trap formation. Two data sets are used to illustrate such variations: both include a seismic reflection profile calibrated by multiple wells. The first is a Pennsylvanian mixed carbonate-siliciclastic system in the Paradox basin, and the second a Pliocene-Pleistocene siliciclastic system in the Gulf of Mexico. Numeric simulations result in geometry and facies distributions consistent with those interpreted using the integrated stratigraphic analysis of the calibrated seismic profiles. An exception occurs in the Gulf of Mexico study where the simulated sediment thickness from 3.8 to 1.6 Ma within an upper slope minibasin was less than that mapped using a regional seismic grid. Regional depositional patterns demonstrate that this extra thickness was probably sourced from out of the plane of the modeled transect, illustrating the necessity for three-dimensional constraints on two-dimensional modeling.« less

Core analysis of heterogeneous rocks using experimental observations and digital whole core simulation

NASA Astrophysics Data System (ADS)

Jackson, S. J.; Krevor, S. C.; Agada, S.

2017-12-01

A number of studies have demonstrated the prevalent impact that small-scale rock heterogeneity can have on larger scale flow in multiphase flow systems including petroleum production and CO2sequestration. Larger scale modeling has shown that this has a significant impact on fluid flow and is possibly a significant source of inaccuracy in reservoir simulation. Yet no core analysis protocol has been developed that faithfully represents the impact of these heterogeneities on flow functions used in modeling. Relative permeability is derived from core floods performed at conditions with high flow potential in which the impact of capillary heterogeneity is voided. A more accurate representation would be obtained if measurements were made at flow conditions where the impact of capillary heterogeneity on flow is scaled to be representative of the reservoir system. This, however, is generally impractical due to laboratory constraints and the role of the orientation of the rock heterogeneity. We demonstrate a workflow of combined observations and simulations, in which the impact of capillary heterogeneity may be faithfully represented in the derivation of upscaled flow properties. Laboratory measurements that are a variation of conventional protocols are used for the parameterization of an accurate digital rock model for simulation. The relative permeability at the range of capillary numbers relevant to flow in the reservoir is derived primarily from numerical simulations of core floods that include capillary pressure heterogeneity. This allows flexibility in the orientation of the heterogeneity and in the range of flow rates considered. We demonstrate the approach in which digital rock models have been developed alongside core flood observations for three applications: (1) A Bentheimer sandstone with a simple axial heterogeneity to demonstrate the validity and limitations of the approach, (2) a set of reservoir rocks from the Captain sandstone in the UK North Sea targeted for CO2 storage, and for which the use of capillary pressure hysteresis is necessary, and (3) a secondary CO2-EOR production of residual oil from a Berea sandstone with layered heterogeneities. In all cases the incorporation of heterogeneity is shown to be key to the ultimate derivation of flow properties representative of the reservoir system.

Noble Gases as tracers of fluid migration in the Haynesville shale and overlying strata

NASA Astrophysics Data System (ADS)

Byrne, D. J.; Barry, P. H.; Lawson, M.; Ballentine, C. J.

2017-12-01

Noble gases are ideal tracers of physical processes and fluid provenance in crustal systems. Due to their inert nature, they are unaffected by chemical alteration, redox, or biological phenomena that fractionate other geochemical tracers. Noble gas analysis has been used to quantify fluid provenance, interactions, and ages in petroleum systems [1,2], but the effects of hydrocarbon migration on noble gas signatures have not been directly observed. The Haynesville Shale (East Texas & Louisiana), is exploited commercially for unconventional shale gas, but also acts as the source-rock for overlying conventional reservoirs. We present noble gas isotope and abundance data in samples collected from 9 natural gas wells sourced from the Haynesville Shale, as well as 21 from reservoirs in the overlying Cotton Valley (n=7), Travis Peak (n=9), and James (n=5) groups. Using a stratigraphic model, we observe systematic changes in the noble gas signatures as the fluids migrate from the Haynesville source rock to the overlying conventional accumulations. Helium isotope ratios (3He/4He) are strongly radiogenic in the Haynesville and stratigraphically older conventional reservoirs, with the younger reservoirs showing evidence of a mantle helium input. Argon isotope ratios (40Ar/36Ar) are strongly correlated with high 3He/4He, suggesting a similar provenance for radiogenic 40Ar and mantle 3He. Concentrations of groundwater-derived 36Ar are consistently higher in the conventional reservoirs than in the Haynesville shale, reflecting the greater interaction with groundwater during migration. However, 20Ne/36Ar ratios are not significantly different, suggesting that solubility-dependent partitioning is not simply dependent on vertical or horizontal migration distance. Krypton and xenon abundances are higher than expected for groundwater in all samples, a phenomenon that has been observed in many other hydrocarbon accumulations [3]. The excess Xe/Kr ratio is highest in the Haynesville itself, suggesting that this excess Xe and Kr originates from within the source-rock, and is subsequently shifted towards normal Xe/Kr values by mixing with groundwater-derived noble gases during migration. [1] Barry et al., 2016, GCA 194, 291-309; [2] Darrah et al., 2014, PNAS 111, 14076-81; [3] Zhou et al., 2005, GCA 69, 5413-28

Petroleum supply monthly, February 1991. [Glossary included

DOE Office of Scientific and Technical Information (OSTI.GOV)

Not Available

1991-02-01

Data presented in the Petroleum Supply Monthly (PSM) describe the supply and disposition of petroleum products in the United States and major US geographic regions. The data series describe production, imports and exports, inter-Petroleum Administration for Defense (PAD) District movements, and inventories by the primary suppliers of petroleum products in the United States (50 States and the District of Columbia). The reporting universe includes those petroleum sectors in Primary Supply. Included are: petroleum refiners, motor gasoline blenders, operators of natural gas processing plants and fractionators, inter-PAD transporters, importers, and major inventory holders of petroleum products and crude oil. When aggregated,more » the data reported by these sectors approximately represent the consumption of petroleum products in the United States. Data presented in the PSM are divided into two sections (1) the Summary Statistics and (2) the Detailed Statistics. Explanatory Notes, located at the end of this publication, present information describing data collection, sources, estimation methodology, data quality control procedures, modifications to reporting requirements and interpretation of tables. Industry terminology and product definitions are listed alphabetically in the Glossary. 12 figs., 54 tabs.« less

Stress-Induced Fracturing of Reservoir Rocks: Acoustic Monitoring and μCT Image Analysis

NASA Astrophysics Data System (ADS)

Pradhan, Srutarshi; Stroisz, Anna M.; Fjær, Erling; Stenebråten, Jørn F.; Lund, Hans K.; Sønstebø, Eyvind F.

2015-11-01

Stress-induced fracturing in reservoir rocks is an important issue for the petroleum industry. While productivity can be enhanced by a controlled fracturing operation, it can trigger borehole instability problems by reactivating existing fractures/faults in a reservoir. However, safe fracturing can improve the quality of operations during CO2 storage, geothermal installation and gas production at and from the reservoir rocks. Therefore, understanding the fracturing behavior of different types of reservoir rocks is a basic need for planning field operations toward these activities. In our study, stress-induced fracturing of rock samples has been monitored by acoustic emission (AE) and post-experiment computer tomography (CT) scans. We have used hollow cylinder cores of sandstones and chalks, which are representatives of reservoir rocks. The fracture-triggering stress has been measured for different rocks and compared with theoretical estimates. The population of AE events shows the location of main fracture arms which is in a good agreement with post-test CT image analysis, and the fracture patterns inside the samples are visualized through 3D image reconstructions. The amplitudes and energies of acoustic events clearly indicate initiation and propagation of the main fractures. Time evolution of the radial strain measured in the fracturing tests will later be compared to model predictions of fracture size.

Eastern Devonian shales: Organic geochemical studies, past and present

USGS Publications Warehouse

Breger, I.A.; Hatcher, P.G.; Romankiw, L.A.; Miknis, F.P.

1983-01-01

The Eastern Devonian shales are represented by a sequence of sediments extending from New York state, south to the northern regions of Georgia and Alabama, and west into Ohio and to the Michigan and Ilinois Basins. Correlatives are known in Texas. The shale is regionally known by a number of names: Chattanooga, Dunkirk, Rhinestreet, Huron, Antrim, Ohio, Woodford, etc. These shales, other than those in Texas, have elicited much interest because they have been a source of unassociated natural gas. It is of particular interest, however, that most of these shales have no associated crude oil, in spite of the fact that they have some of the characteristics normally attributed to source beds. This paper addresses some of the organic geochemical aspects of the kerogen in these shales, in relation to their oil generating potential. Past organic geochemical studies on Eastern Devonian shales will be reviewed. Recent solid state 13C NMR studies on the nature of the organic matter in Eastern Devonian shales show that Eastern Devonian shales contain a larger fraction of aromatic carbon in their chemical composition. Thus, despite their high organic matter contents, their potential as a petroleum source rock is low, because the kerogen in these shales is of a "coaly" nature and hence more prone to producing natural gas.

Eastern Devonian shales: Organic geochemical studies

DOE Office of Scientific and Technical Information (OSTI.GOV)

Berger, I.A.; Hatchner, P.G.; Miknis, F.P.

The Eastern Devonian shales are represented by a sequence of sediments extending from New York state, south to the northern regions of Georgia and Alabama, and west into Ohio and to the Michigan and Illinois Basins. Correlatives are known in Texas. The shale is regionally known by a number of names: Chattanooga, Dunkirk, Rhinestreet, Huron, Antrim, Ohio, Woodford, etc. These shales, other than those in Texas, have elicited much interest because they have been a source of unassociated natural gas. It is of particular interest, however, that most of these shales have no associated crude oil, in spite of themore » fact that they have some of the characteristics normally attributed to source beds. This paper addresses some of the organic geochemical aspects of the kerogen in these shales, in relation to their oil generating potential. Past organic geochemical studies on Eastern Devonian shales are reviewed. Recent solid state /sup 13/C NMR studies on the nature of the organic matter in Eastern Devonian shales show that Eastern Devonian shales contain a larger fraction of aromatic carbon in their chemical composition. Thus, despite their high organic matter contents, their potential as a petroleum source rock is low, because the kerogen in these shales is of a ''coaly'' nature and hence more prone to producing natural gas.« less

Provenance of sediments from Sumatra, Indonesia

NASA Astrophysics Data System (ADS)

Liebermann, Christof; Hall, Robert; Gough, Amy

2017-04-01

The island of Sumatra is situated at the south-western margin of the Indonesian archipelago. Sumatra is affected by active continental margin volcanism along the Sunda Trench, west of Sumatra as a result of active northeast subduction of the Indian plate under the Eurasian plate. Exposures of the Palaeozoic meta-sedimentary basement are mainly limited in extent to the northeast-southwest trending Barisan Mountain chain. The younger Cenozoic rocks are widespread across Sumatra, but can be grouped into structurally subdivided 'fore-arc', 'intramontane', and 'back-arc' basins. However, the formation of the basins pre-dates the current magmatic arc, thus a classical arc-related generation model can not be applied. The Cenozoic formations are well studied due to hydrocarbon enrichment, but little is known about their provenance history. A comprehensive sedimentary provenance study of the Cenozoic formations can aid in the wider understanding of Sumatran petroleum plays, can contribute to palaeographic reconstruction of western SE Asia, and might help to simplify the overall stratigraphy of Sumatra. This work represents a multi-proxy provenance study of sedimentary rocks from the main Cenozoic basins of Sumatra, alongside sediment from present-day river systems. The project refines the provenance in two ways: first, by studying the heavy mineral assemblages of the targeted formations, and secondly, by U-Pb detrital zircon dating using LA-ICP-MS to identify the age-range of the potential sediment sources. Preliminary U-Pb zircon age-data of >1500 concordant grains (10% discordant cut-off), heavy mineral compositions, and thin section analysis from two fieldwork seasons indicate a mixed provenance model, with a proximal igneous source, and mature basement rocks. An increase of the proximal signature in Lower-Miocene strata indicated by the occurrence of unstable heavy mineral phases such as apatite, and clinopyroxene suggests a major change of the source at the Oligocene-Miocene boundary. This can be interpreted as a pulse in the uplift of the Barisan Mountains. The presence of volcanic quartz in thin section supports this hypothesis. On the contrary, older sedimentary strata are characterised by ultra-stable heavy minerals such as zircon, tourmaline, and rutile; the presence of garnet in both pre-, and post-uplift affected strata indicates a contribution from metamorphic basement rocks, either from the local Sumatran basement or the Malay-Peninsula. Detrital zircon ages as old as Archean are present in all sedimentary formations; a prominent Triassic age group can be correlated with the Main Range Province granitoids reported from the Malay-Peninsula. It is noteworthy that zircon age spectra from Sumatra lack some diagnostic age groups commonly found in central- and western SE Asia, such as Cretaceous ages, correlated with igneous rock in the Schwaner Mountains, SW Borneo. The analysis of modern river sands suggests that the current sedimentary fluvial systems are mainly sourced from the recent Barisan-related volcanic arc. Zircon age patterns of the modern river sands resemble the populations found in the sedimentary strata, whereas, the heavy mineral composition is highly diluted by the recent igneous sources.

In-situ ATR-FTIR and surface complexation modeling studies on the adsorption of dimethylarsenic acid and p-arsanilic acid on iron-(oxyhydr)oxides

USDA-ARS?s Scientific Manuscript database

Arsenic is an element that exists naturally in many rocks and minerals around the world. It also accumulates in petroleum, shale, oil sands and coal deposits as a result of biogeochemical processes, and it has been found in fly ash from the combustion of solid biofuels. Arsenic compounds in their o...

Geology and assessment of the undiscovered, technically recoverable petroleum resources of Armenia, 2013

USGS Publications Warehouse

Klett, T.R.

2016-02-23

The U.S. Geological Survey (USGS) assessed the undiscovered, technically recoverable oil and gas resources of Armenia in 2013. A Paleozoic and a Cenozoic total petroleum system (TPS) were identified within the country of Armenia. The postulated petroleum system elements are uncertain, resulting in low geologic probabilities for significant oil an gas resources. Two assessment units (AU) were delineated in each TPS—a Paleozoic-Sourced Conventional Reservoirs AU and a Permian Shale Gas AU in the Paleozoic Composite TPS and a Paleogene-Sourced Conventional Reservoirs AU and a Cenozoic Coalbed Gas AU in the Cenozoic Composite TPS. The TPS elements are largely uncertain and risked, and so only the Paleogene-Sourced Conventional Reservoirs AU was quantitatively assessed because the geologic probability is more than the threshold of 10 percent (that is, the probability of at least one conventional oil or gas accumulation of 5 million barrels of oil equivalent or greater based on postulated petroleum-system elements). The USGS estimated fully risked mean volumes of about 1 million barrels of oil (MMBO), about 6 billion cubic feet of natural gas (BCFG), and less than 1 million barrels of natural gas liquids (MMBNGL).

Biodegradation of Petroleum Hydrocarbon in the Vadose Zone

EPA Science Inventory

There are two major impediments to a better understanding of the influence of biodegradation on the risk of intrusion of petroleum vapors. We describe the contribution of biodegradation as an attenuation factor between the source and the receptor. The use of attenuation factors...

10 CFR 1009.4 - Exclusions.

Code of Federal Regulations, 2010 CFR

2010-01-01

.... (c) Crude oil, natural gas and other petroleum products and services by or from the Naval Petroleum and Oil Shale Reserves. (d) Uranium enriching services, source material, and special nuclear material... data and information provided by the Energy Information Administration. (g) Crude oil and related...